Ladies and gentlemen, thank you for standing by. Welcome to the American Electric Power fourth quarter 2020 earnings call. At this time, all lines are in a listen-only mode. Later, we will conduct a question-and-answer session. Instructions will be given to you at that time. If you need assistance during the call, press star and then zero, and an operator will assist you offline. As a reminder, today's conference call is being recorded. I would now like to turn the conference over to Darcy Reese. Please go ahead.
Thank you, Cynthia. Good morning, everyone, and welcome to the fourth quarter 2020 earnings call for American Electric Power. We appreciate you taking time today to join us. Our earnings release, presentation slides, and related financial information are available on our website at aep.com. Today, we will be making forward-looking statements during the call. There are many factors that may cause future results to differ materially from these statements. Please refer to our SEC filings for a discussion of these factors. Joining me this morning for opening remarks are Nick Akins, our Chairman, President, and Chief Executive Officer, as well as Julie Sloat, our Chief Financial Officer. We will take your questions following their remarks. I will now turn the call over to Nick.
Good. Thanks, Darcy. Darcy says, Happy Birthday, Bette Jo Rozsa . This one's for you. Welcome, everyone, to the American Electric Power's fourth quarter 2020 earnings call. 2020 was a year of tremendous challenges, the likes of which we have never seen. It appears that 2021 has thus far had its own set of challenges. Our hearts go out to everyone that has been and are impacted by the ongoing challenges of COVID-19 and to all the customers impacted by the severe cold and ice conditions that precipitated significant outages from Texas to West Virginia and beyond. There will be plenty of opportunities to do a postmortem of the conditions that led to these outages and to address changes to help ensure these kinds of events do not occur again. As of now, getting customers back and some return to normalcy is paramount in everyone's mind.
I'll discuss these issues a little later, but I want to tell you, in the midst of significant challenges come tremendous accomplishments that make us even stronger for the future, and AEP has once again delivered. The fourth quarter further illustrated the resiliency of AEP and its employees to deliver and exceed expectations in ensuring the consistent quality of earnings and dividend growth that you would expect from a premium regulated utility. AEP's operating earnings for the quarter came in at $0.87 a share, ending the year at $4.44 per share, which is the top of the operating earnings range that we projected for 2020.
An excellent outcome buoyed by our employees' aggressive moves to control costs during the COVID-19 downturn of the economy, the arbitrage of residential to industrial and commercial loads that we have discussed in previous earnings calls, and certain tax and investment-related outcomes that went our way, along with positive regulatory outcomes in several of our cases that concluded in 2020. Given the progress that we have made on cost control with our Achieving Excellence program and in updating our load forecast for 2021, AEP is now revising our operating earnings guidance range for 2021 upward from a midpoint of $4.61 per share to $4.65 per share, bringing our new guidance range to $4.55 - $4.75 per share.
We're also rebasing our 5%-7% operating earnings growth rate on the new 2021 guidance range and continue in our view that we would be disappointed not to be in the upper half of the guidance range. AEP is reaffirming our $37 billion five-year capital plan and are committed to our credit ratings quality as we move forward. Additionally, after further analysis, as we do each and every year through our corporate accountability reporting process, AEP is now prepared to accelerate our carbon dioxide emission reduction goals to reach 80% by 2030 and to achieve net zero by 2050.
We will be releasing a new climate scenario analysis report during the first quarter that has been over a year in the making. You will find this to be a state-of-the-art report covering everything from extensive scenario analysis of carbon reduction efforts to technology innovations to just transition-related aspects of the complex path before us as we require substantial stakeholder engagement as we go along. Like all these commercials, wait, there's more. As I mentioned to you in the last earnings call, we are refining our integrated resource plan recommendations for all of our operating jurisdictions, which we will roll out at our next first quarter 2021 earnings call or before. Just a brief teaser on the future plans, we are proposing up to 3,300 MW of new renewable energy to serve SWEPCO customers to be delivered in the 2025 to 2028 timeframe.
We will give further updates on this, as I said, by next quarter's earnings call. AEP has a lot of work to do to manage regulatory and project-related activities as well as financial activities that are respectful to our balance sheet and credit metrics. I'm reminded of one of my favorite movies, Gladiator, in which Maximus Decimus Meridius says, "The time for half-measures and talk are over." It is time for serious execution by AEP to transform ourselves to embrace our clean energy future on behalf and for our customers and communities. Additionally, we will actively manage our portfolio of assets and companies to enable this movement while ensuring our balance sheet and credit metric strength as we define this path forward. This execution has been recently evidenced by our sale of the Racine Hydro plant.
This form of asset optimization will continue as we focus on our core growth opportunities. Moving on to our economy and load. The AEP load forecast is up considering the recent improvement in our commercial and industrial loads, still trailing pre-COVID-19 levels, but improving. We are optimistic about the recovery in both our service territory and with load during 2021. Modest overall growth should occur led by industrials and a focus on infrastructure by the administration and in developing the hardening and resiliency-related investments such as pipelines, natural gas distribution, and other infrastructure, particularly after the winter weather events. Julie will be covering load-related topics in more detail in a couple of minutes. Our rate case activity across our jurisdictions continues to be robust. In Virginia, Appalachian Power received an order in its Virginia Triennial Rate Case on November 24th, 2020.
We were extremely disappointed in the Commission's finding that APCO finished the Triennial within the earnings band and therefore was not entitled to a rate increase. This result hinged on the Commission's determination that APCO should have amortized the disposition of certain coal plant balances over 10- years starting in June 2015 versus impairing the assets in 2019, which we believe was consistent with state law. The company believed the Commission erred in this determination and as a result, immediately sought both rehearing and appealed the decision to the Virginia Supreme Court. More to come on that. AEP Ohio filed its base rate case in June of 2020. The parties have been engaged in ongoing settlement discussions and will update the Commission on or before March 4th as to whether a settlement was reached.
If not, the Commission will proceed with a full hearing, but I will say that the settlement discussions continue to be positive and constructive. In Kentucky, the Commission issued a constructive order on January 13th, awarding the company a net revenue increase of $52 million out of a $65 million request with a 9.3% ROE and modified the transmission tracker from 80% to 100%. In our SWEPCO jurisdictions, we have rate cases pending in Louisiana and Texas. SWEPCO filed its Texas case in October, seeking a net revenue increase of $73 million and ROE of 10.35%. The following included investments made from February 2018, accelerated depreciation for three coal plants, and an increase in storm reserves and vegetation management. Hearings are scheduled for the end of May, with a final order expected at the end of October.
In Louisiana, the company filed its base rate case on December 18th, seeking a 10.35% ROE and a net revenue increase of $93 million. A little over one month into the year, and we've experienced ice storms in the east and record cold temperatures in the west. Our APCO and Kentucky territory sustained significant ice and tree damage to our transmission and distribution system with back-to-back storms. Our teams, along with significant support from our operating companies and mutual assistance teams, have made headway on restoring service to our impacted communities. We intend to file for the appropriate regulatory recovery as we have with other major storms. The tragedy that unfolded in Texas is an important one for me to address.
First and foremost, again, our thoughts and prayers go out to the people of Texas, and particularly to those families and communities who lost family members or experienced loss and damage as a result of the polar vortex that engulfed the state. As you know, our AEP Texas affiliate provides energy delivery services to a little over one million customers in the state. The unprecedented weather conditions required ERCOT to direct AEP and others to immediately curtail load and to operate in an emergency condition to maintain the stability and integrity of the Texas grid. During this event, our focus centered on responding to the directives from ERCOT to ensure that the flow of available power continued throughout this crisis.
We also worked with our communities to identify critical loads such as hospitals and other first responder resources in an effort to mitigate the impacts of key resources within our communities. Throughout this emergency, I could not have been more proud of our team's response in dealing with the situation that confronted them. This event serves as a sober reminder as to the critical nature of our nation's energy supply in maintaining and supporting not only our economy, but also our fundamental way of life. As a T&D utility with cost-based rates in the ERCOT portion of Texas, our AEP Texas subsidiary is not a generator, nor is it a Retail Electric Provider. We expect minimal, if any, financial impact from the ERCOT Texas weather events. Our AEP wind assets in ERCOT began to experience outages on February 10th and started returning to service on February 19th.
We expect all three wind farms to be returned to full availability soon. We have no financial exposure from our hedges, which are all based upon unit contingent performance. Financial performance related to wholesale loads served by AEP Energy Partners and ERCOT is not material. In the SPP, we also experienced minimal load shedding events, fuel costs were substantially higher during this event. As you know, we recover fuel through our fuel clauses as a pass-through. That being said, in the SWEPCO and PSO jurisdictions, we will work with the various state commissions on any alternative fuel recovery mechanisms to lessen the impacts to our customers, much like we do with major storm costs, we have to be respectful of the cash flow metrics and the capital structure of the company going forward.
Certainly, a weighted average cost of capital is extremely important from that perspective. These events, along with others around the country, have indicated the need for specific policy changes that focus on further refinements in reliability and resiliency of the grid. Specifically, we would encourage more robust reliability assessments across electric, gas, and other critical infrastructure classes to determine where interdependencies exist, and market designs that promote adequate capacity levels and increased generation reserve margins to provide a sufficient safety net during emergency situations.
In addition, to counteract the frequency, intensity, and impact of storms, we need to ensure a higher level of system resilience by implementing transmission planning and interconnection reforms to enable regions to lean on each other during times of crisis, as well as winterization requirements for power plants, natural gas delivery systems, and critical infrastructure. I actually, in 2014, testified before the Senate Energy Committee regarding some of these recommendations after the polar vortex that hit the PJM territories. All stakeholders must do better to address the issues that led us to these failures that have impacted so many customers at the worst possible time. Whether it's winter and summer weather event reliability or the speed at which the clean energy future can occur, AEP stands ready to be an active participant in resolving these issues, both from the state and national perspective.
We will also remain active on other significant issues impacting our society, from racial injustice to COVID-19 related safety, as we strive to advance in a positive way the communities that we are so fortunate to serve. Now I'll move to the equalizer chart, and that's I think the second page of the handout. I'll go through that. Our overall ROE is 9.1% across the board. We generally target the ROE for our regulated segments combined to be in the 9.5%-10% range. As you see, the ROEs below are not weather normalized. Keep in mind that we're also thickening the equity layers as we go along as well.
You also note in the table, at least the indication of the size of the bubbles that you see, AEP Transmission Holdco. Is now our largest company based on average equity, followed by APCO with AEP Texas, I&M, AEP Ohio, and SWEPCO being comparable to each other. First with AEP Ohio. The ROE for AEP Ohio at the end of the fourth quarter was 10.7%. AEP Ohio's ROE was above authorized primarily due to favorable regulatory items, partially offset by the roll-off of the legacy fuel and capacity carrying charge recoveries that we've discussed in the past. We expect the ROE to trend around authorized levels of 10% as we maintain concurrent capital recovery of distribution and transmission investment. In June 2020, as I said earlier, AEP Ohio filed the base case and certainly we'll see an outcome of that pretty soon.
APCO, the ROE for APCO at the end of the fourth quarter was 8.6%. Its ROE was below authorized due to lower normalized usage and higher amortization and depreciation from increased Virginia depreciation rates and increased capital investments, partially offset by lower O&M expenses. Of course, we already talked about the Virginia Triennial Review. APCO did subsequently file a petition for reconsideration with the commission, which was granted in December 2020 and resulted in suspension of that final order at this point. As far as Kentucky is concerned, we ended the fourth quarter at 5.5% ROE. The ROE was below authorized due to loss of load from weak economic conditions and loss of major customers, along with higher expenses. Transmission revenues were also lower due to the delay of some capital projects.
Of course, you knew we filed a base rate case there, so we fully expect that ROE to improve after the rate case outcome. I&M, its ROE is 11.4%. I&M's ROE was above authorized due to continued management of O&M expenses, reduced interest expense, and rates true-ups, partially offset by lower commercial and industrial sales. I&M is projecting to trend below 10%, consistent with the authorized ROEs of 9.86% in Michigan and 9.7% in Indiana. PSO, the ROE there is 9%. Its ROE was below its authorized level, primarily due to lower normalized usage and unfavorable weather in 2020, partially offset by continued management of O&M expenses. PSO's 2019 base case approved a transmission tracker, a partial distribution tracker, and an ROE of 9.4%. PSO's 2019 base case settlement also required filing a case no later than October of 2021. More to come on that.
SWEPCO, the ROE for SWEPCO at the end of the fourth quarter was 7.5%. ROE was below authorized due to loss of load and the continued impact of the Arkansas share of TCOS, which we've discussed several times. That equates to about 110 basis points discount associated with TCOS. In October 2020, as you know, I've already talked about this, filed a Texas case. We recently filed a Louisiana case as well. More to come on that one. AEP Texas, the ROE is 7.9% at the end of the fourth quarter. It's below authorized due to lag associated with the timing of annual cost recovery filings and one-time adjustments from our finalized base rate case earlier in 2020.
Favorable regulatory treatment allows AEP Texas to file annual DCRF and biannual TCOS filings to recover costs on capital investment and had to wait till after the rate case to file those. While the exception is for the ROE to trend towards an authorized ROE of 9.4% in the longer term, continued significant levels of investment in Texas will continue to impact the ROE. AEP Transmission Holdco. Came in at fourth quarter at 9.9%. It was below authorized, primarily driven by the annual revenue true-up in the second quarter of 2020 to return the overcollection of 2019 revenues. Transmission is forecasting their ROE to be in the mid-10% range in 2021. All in all, an outstanding year, both financially and operationally, given the significant challenges in 2020. We were off to a great start in 2021.
AEP has shown time and time again our agility and resilience in meeting our objective of consistent quality of earnings and dividends that embody a truly premium electric utility. As we emerge from the COVID-19 challenge and get the economy back on track in 2021 while working on a clean energy future, to paraphrase the lyrics of Johnny Nash, who passed away in 2020, "I can see clearly now, the rain is gone, and we can remove all obstacles in our way to a bright sunshiny day." As many of you already know, Brian Tierney has moved on to take over our focus on corporate strategy after serving over 11 years as Chief Financial Officer. I want to thank him for his dedication to the company and to our investors while in this important role. Now I'll turn it over to our new Chief Financial Officer, who many of you already know, Julie Sloat.
She approaches everything with the infectious energy and focus that will take AEP to the next level. Even Brian would agree with that. Julie, you're up.
Thank you, Nick. Thank you, Darcy, and Happy Birthday, Bette Jo Rozsa . It's good to be with everyone this morning. I'm going to walk us through the fourth quarter results, spend a little more time on the full-year financial results, share some thoughts on our service territory load and economy, review our balance sheet and liquidity, we'll finish up with our revised outlook for 2021. Let's go to slide number six, which shows the comparison of GAAP to operating earnings for the quarter and for the year-to-date periods. GAAP earnings for the fourth quarter were $0.88 per share compared to $0.31 per share in 2019. GAAP earnings for the year were $4.44 per share compared to $3.89 per share in 2019. There's a reconciliation of GAAP to operating earnings on pages 15 and 16 of the presentation today.
Let's walk through our fourth quarter operating earnings performance by segment, which is laid out on slide number seven. Operating earnings for the fourth quarter totaled $0.87 per share compared to $0.60 per share in 2019. The detail by segment is provided in the boxes on the chart. To summarize, the change in our collective regulated businesses was driven by lower O&M and the return on incremental investment to serve our customers, which more than offset higher depreciation and unfavorable weather. On the generation and marketing side, earnings were up $0.05 from 2019. This was driven by land sales and favorable effects associated with the retirement of plants in the generation business, as well as higher wholesale margins. Lower retail margins were offset by the expected timing of income taxes.
Corporate and other was up $0.10 from last year, primarily due to lower taxes relating to state tax adjustments and consolidating items, an investment gain on a privately held investment, all of which was partially offset by higher O&M. Let's take a look at our full-year results on page number eight. Annual operating earnings for 2020 were $4.44 per share or $2.2 billion, compared to $4.24 per share or $2.1 billion in 2019. Looking at the drivers by segment, operating earnings for vertically integrated utilities were $2.21 per share, up $0.04 year-over-year. Favorable items in this segment included lower O&M, the impact of rate changes across multiple jurisdictions, and higher transmission revenue, primarily due to true-ups. Weather was unfavorable due to warmer-than-normal temperatures in 2020 and a warmer summer in 2019. Other decreases included higher depreciation and tax expenses and lower revenue items in AFUDC.
Transmission and distribution utilities segment earned $1.03 per share, up $0.03 from 2019. Favorable drivers in this segment included higher rate changes, the recovery of increased transmission investment in ERCOT, and the impact of the Ohio transmission true-up, both on O&M and transmission revenue. Other O&M was favorable due to concerted effort to decrease O&M expenditures through one-time and sustainable reductions. These items were partially offset by the 2019 reversal of a regulatory provision in Ohio and higher depreciation associated with the increased investment. Other smaller drivers included things like higher interest and tax expenses, the roll-off of legacy riders in Ohio, prior-year Texas carrying charges, unfavorable weather, and AFUDC. The AEP Transmission Holdco. Segment contributed $1.03 per share, down $0.02 from 2019 due to the impacts of the annual true-up and prior-year FERC settlements.
Our fundamental return on investment growth continued as net plant increased by $1.3 billion or 13% since December of 2019. Generation and marketing produced $0.36 per share, up $0.06 year-over-year. The renewables business grew with asset acquisitions. Land sales and other one-time items more than offset the impact of weaker wholesale prices on the generation business and lower retail margins. Corporate and other was up $0.09 per share, driven by taxes from lower state taxes and adjustments, as well as an investment gain, partially offsetting these items with higher interest expense. We're pleased with our 2020 financial results as we landed in the upper half of our operating earnings guidance range. Let's take a look at our normalized load for the quarter on page nine.
Starting in the lower right corner, our fourth quarter normalized load came in 0.2% above the fourth quarter of 2019. This was significant not only because it was the first time we saw positive load growth since the pandemic began, but it was also the strongest quarter for load growth in over two years. For the year, AEP's 2020 normalized load finished down 2.2% compared to 2019. Normalized load has continued to improve since bottoming out in the second quarter of 2020 when COVID-19 restrictions were at their highest levels. The strong finish for the year in our retail load was one of the drivers that enabled us to reach the upper end of our guidance range in 2020. I'll talk a little bit more about why this occurred when we get to slide 11, where we can view some economic data specific to our service territory.
For 2021, we're projecting 0.2% growth in normalized load. While this will be an improvement from the 2.2% decline in 2020, it also shows that our service territory is gradually getting back to its normal growth trajectory. In the upper left quadrant, our normalized residential sales increased by 5.2% in the fourth quarter and ended the year up 3.2%. For both the quarter and year-to-date comparisons, growth in residential sales was spread across every operating company. Residential loads spiked in the second quarter of 2020 when the COVID-19 restrictions were at their highest and people were spending the majority of their time at home.
Looking to this year, while we expect residential sales to decline by 1.1% in 2021, as vaccinations are rolled out and as we migrate to our post-pandemic lives, we are assuming a moderate sustained load benefit from this segment given the stickiness from work-from-home relationships or arrangements for many office workers across our service territory for the foreseeable future. Let's slide over to commercial sales in the upper right quadrant. Normalized commercial sales decreased by 2.1% in the fourth quarter and finished the year down 4.2%. Even though commercial sales were down across all operating companies in the quarter, we're seeing steady improvement since the pandemic began. In fact, the same sectors that were hardest hit by the shutdowns in the second quarter of 2020 were the most improved sectors in the fourth quarter. Specifically, these sectors included schools, churches, restaurants, and hotels.
As we look forward to 2021, we expect commercial sales to experience a modest 0.5% decline as the service territory continues to recover, which is still a significant improvement from the record-setting 4.2% decline we saw in 2020. The improvement in commercial sales will likely track with vaccinations, and as the service territory population acquires additional immunity, this class of customers should be positioned for a strong recovery. In the lower left chart, industrial sales decreased by 2% in the quarter, ending the year down 5.7%. Even though industrial sales were down for the quarter in aggregate, we did have a few operating companies, namely I&M, AEP Ohio, and AEP Texas, post growth in industrial sales compared to the fourth quarter of 2019. Our projection for 2021 assumes industrial sales will continue to recover and end the year up 1.9%.
On slide 10, we have a little more color on the industrial recovery we saw in the fourth quarter. The blue bars show the growth in sales to our oil and gas customers. Led by growth in the pipeline transportation sector, our total oil and gas sector sales in the fourth quarter came in 1.3% above last year. In fact, the pipeline transportation sector has been the fastest-growing sector since 2018. The orange bars show the growth in industrial sales excluding oil and gas. While it was still down 3.3% for the quarter, you can see how dramatic the sequential improvement has been since the second quarter. The industrial sectors that are experiencing the strongest growth for the quarter were pipeline transportation and plastics and rubber manufacturing. This is mostly offset by softer demand from oil and gas extraction, mining, and primary metals.
Overall, we're seeing evidence of faster recovery in the industrial sector, which supports our projected growth in industrial sales for 2021. We anticipate improvements across most sectors with the exception of the coal mining sector as the industry faces headwinds with the shift toward reduced carbon dioxide emissions. If you join me on slide 11, I can provide the update I mentioned a few moments ago on the latest economic conditions within the AEP footprint. Starting with the chart on the left, you'll notice that AEP service territory experienced a 2% decline in gross regional product compared to the fourth quarter of 2019. This was 40 basis points better than the U.S. The AEP service territory was less impacted by the virus and had fewer restrictions on businesses than other parts of the country, which allowed our territory economy to fare better than the U.S. throughout the pandemic.
Looking forward, the AEP service territory is expected to grow by 4.8% in 2021, relatively consistent with the economic recovery in the U.S. Moving to employment on the right, you can see that the job market for the AEP service territory also performed better than the U.S. throughout the pandemic. For the quarter, employment was down 4.6%, which was 1.4% better than the U.S. This is largely the result of the mix of jobs within our local economy, which has a heavier relative concentration of manufacturing and government jobs and a smaller share of leisure and hospitality jobs. Going forward, we expect a job growth of 1.1% in our service territory in 2021. Let's turn over to page 12 to check on the company's capitalization and liquidity position. Our debt-to-cap ratio increased 0.7% in the fourth quarter to 61.8%.
As I noted, debt increased by 0.2% during the quarter to 13% on a Moody's basis, primarily due to changes in regulatory assets and working capital. Our liquidity position remains strong at $2.5 billion, supported by our revolving credit facility. I'd like to touch base on a couple things relating to our financing plan, as we receive questions from time to time on this. Our current financing plan does not include an assumption of any asset rotation. I'd like to share that we do believe it is incumbent upon us to engage in analysis of any opportunity within our portfolio that can generate more value for another party than it can generate for us.
To the extent that we engage in such activity, that would result in the sale of an asset or a business unit, the associated proceeds would likely supplant some of the planned equity and/or debt financing you see on page 39 in the appendix of the presentation today. Nick talked about the severe winter weather in Texas, which impacted both SPP and ERCOT. I want to take a moment to provide some quantification exposure details since that's top of mind for us and also for you. As you know, the winter storm increased the demand for natural gas and limited natural gas supply availability, resulting in unanticipated market prices for natural gas power plants to meet reliability needs for the SPP electric system. PSO's preliminary estimate of natural gas costs and purchases of electricity are approximately $825 million. SWEPCO's preliminary estimate of natural gas costs is $375 million.
To provide some perspective, PSO's annual fuel and purchase power costs are roughly $550 million-$600 million. You get the sense of how big that is. Importantly, PSO and SWEPCO have active fuel clauses that permit recovery of prudently incurred fuel and purchase power expenses. However, we would expect this recovery to likely occur over an extended period of time in an effort to mitigate the impact on customer bills, which is consistent with the filing we submitted yesterday seeking a regulatory asset and mechanism to recover the costs inclusive of PSO's weighted average cost of capital. We're taking this into consideration as it relates to our financing plan, since the payments to suppliers are due in March. On that note, we're contemplating the use of long-term debt and the possibility of making funding contributions to PSO and SWEPCO from the parent company.
As far as ERCOT exposure goes, as Nick mentioned, this would be related to AEP Texas' receipt of funds from the REPs, AEP Renewables wind generation assets, and the wholesale load served by AEP Energy Partners. This exposure should not be significant. Switching gears, our qualified pension funding increased 5% during the quarter to 101.8%, and our OPEB funding increased 20.4% - 160.9%. Strong equity returns in both plans were the primary driver for the funded status increases during the fourth quarter. The OPEB plan funded status also benefited from lower than expected per capita and Medicare Advantage rates, which reduced the liability. Let's go to slide 13 to do a quick recap of where we've been and where we're going. We begin 2021 with a proven track record.
Our earnings were strong in 2020 as we continued to invest capital in our businesses and earn a return on this investment. In response to expected decline in sales from the pandemic and early mild weather, we implemented O&M savings from both one-time and sustainable reductions, and we also got some help from favorable sales mix shift. We received approval of our North Central Wind project in Oklahoma, and that will be a benefit to our PSO and SWEPCO customers. In addition, over time, we've been able to grow our dividend in line with earnings and expect to be able to do so going forward. Our dividend payout ratio is solidly within our stated target range of 60%-70%. As we look forward to 2020, we feel confident in raising our operating earnings guidance range to $4.55 per share-$4.75 per share.
This is up from our previously stated 2021 operating earnings guidance range of $4.51 per share - $4.71 per share. There is an operating earnings waterfall on page 31 of the appendix reflecting the midpoint of this updated guidance. The primary differences from what we shared at EEI relate to normalized load and weather reflecting 2020 actual results, as well as continued focus on sustainable O&M savings from lessons learned during the pandemic. Not surprisingly, examples on the O&M front include things like reduced non-essential travel and training, since we know now a great deal of this can be done very effectively in a virtual format, sustaining some of the reduction in material and supply expenses, minimizing overtime, and efficiency modifications in our field crew practices, et cetera, just to name a few.
Specifically, we're originally forecasting our 2021 on-track O&M to be $2.7 billion. Now we are forecasting this to be $2.62 billion compared to the $2.68 billion actual for 2020. As we proceed through 2021, we'll finalize our pending rate cases and move forward with additional opportunities in the renewable space supporting our ESG focus as we transition toward a clean energy future. We will continue our disciplined approach to allocating capital. We're confident there is significant runway in our capital programs to reaffirm our 5%-7% growth rate off the increased 2021 operating earnings guidance range. Thanks so much for joining us for the call today. With that, I'm going to turn it over to the operator for your questions.
Thank you. Ladies and gentlemen, if you wish to ask a question, please press one and then zero on your touch-tone phone. You will hear a tone indicating that you are in queue. Once again, it's one and then zero for any questions or comments. One moment please for the first question. We will go to the line of Shar Pourreza with Guggenheim Partners, your line is open.
Morning, Shar.
Good morning, guys.
Good morning.
Good morning, guys.
Good morning.
Just a couple of quick questions here. Nick, just on the Ohio settlement, it seems like you've been kind of close to a resolution for some time now with sort of the procedural schedule being paused to make room for continued dialogue. Is there sort of any pushes and takes we should be sort of thinking about at this juncture? Is the noise in this state at all impacting the conversations?
No, the noise in the state, there's no impact there. We continue in discussions with the parties, and the typical issues of distribution riders and ROEs and that kind of thing. Nothing unusual. Like I said, I think the discussions are going positively, and the parties continue to engage with one another. We all know we have March 4th, and I think that could actually be two or three days different as well. Nevertheless, everyone's focused on getting it concluded.
Excellent. Just on the Racine Hydro sale, obviously, had an immaterial impact to sort of the financing plan, it does sort of show kind of your desire to focus on the core business. How are you sort of thinking about further asset optimization that could potentially offset some of the equity needs related to North Central? Whether we're thinking about a full utility transaction with an underperforming asset, for instance, or a partial sale transaction, maybe similar to the Duke GIC deal. Any sort of updated thoughts here on incremental opportunities you're seeing in the near term?
Yeah, there's a lot of creative ways, obviously, and Duke showed one of those, but there's others as well. Yes, we'll continue to look at all of our assets, actually. As I mentioned in the call, the time for half measures and talk is over. We've got to get about the process of ensuring that we're making the way to move to that clean energy future. That means we're going to have to make sure that we're rotating capital effectively and dealing with assets from an optimization standpoint in an effective fashion going forward. That is a prime motivation for us, particularly with maintaining our balance sheet structure to where it is. We want to make absolutely sure that we manage this process actively in all of those ways.
That's why Brian is over in the strategy area to focus on some of these activities as well. We'll continue that approach, and you'll see more to come.
Got it. That's helpful. Lastly for me, just on Rockport Unit 2 and Pirkey, any sort of additional thoughts there on the replacement generation and potentially what the implications could be to sort of this five-year capital plan you presented this morning? Thanks.
Yeah. The 3,300 MW is an incremental 2,400 MW of what we had before. Some of that is related to Pirkey, obviously. When you talk about Rockport, that's still yet to come. There's still plenty of analysis getting done of all of our operating jurisdictions, and that's what I've talked about before, where we'll come out with our plans, which will be reflected in our integrated resource plans, and that would accommodate Rockport and any of the other measures that we have in place to move to that clean energy future. You'll see that, like I said, by the time we get to the first quarter earnings call or before.
Got it. Congrats. I'll jump back in the queue , g reat execution.
Okay, thanks a lot. Appreciate it.
Thank you. Our next question will come from the line of Steve Fleishman with Wolfe Research. Your line is open.
Morning, Steve.
Hey, good morning, th anks. Just, I guess, first question in terms of the 2021 guidance increase. If you go back to the segments, back to EEI, I think a lot of it is in the Corporate and Other segment. Could you just clarify better, like what's driving that?
Yeah. In 2020, the corporate and other investments, there were some tax-related issues around the tax provisions that were put in place relative to COVID-19. Also, there was some investment returns. We were an early investor in ChargePoint, and certainly we had some opportunities there to monetize by the end of the year. There were warrants that we held. We continue to invest in different technologies. We have investments that have gone positively. We've had investments that have gone negatively. This happened to be a year where it was positive from an investment standpoint. For an ongoing perspective, it really is not so much driven. There still is some investment-related activity that bleeds over into 2021.
I'd say the story of 2021 is when we had November EEI, we didn't know exactly where load was going, didn't know where the economy was going. We're feeling much better about that and the progress in 2021. Also our Achieving Excellence program. We continue to advance in a very positive way from that perspective. We feel like certainly the confidence level was much more for us to raise guidance, but also continue to encourage that we'll be in the upper half of that guidance range.
Steve, this is Julie. The items that we're calling out here obviously were much more pronounced in the fourth quarter of 2020, and specifically as it relates to an investment gain in some income tax items, et cetera. If you look at page 31 in the slide presentation, you can look again at that full-year view, 2020 actual versus 2021 projected or revised projection. You'll see that we still have a little bit of an investment gain associated with ChargePoint in that particular column around corporate and other. Then we'll have a little bit of pickup on the O&M front. Offsetting this is going to be some increased interest expense, largely due to continuing to fund the investment program. We have slightly higher long-term debt balances out there.
Okay. Just to clarify. Yeah.
Go ahead. Go ahead, Steve.
I was just looking at the guidance you gave at EEI for 2021, and then the guidance that you're giving now for 2021. I think the corporate and other is $0.08 better. It sounds like that's mainly due to a mix of interest savings and then the ChargePoint gains or some other things continuing?
As well as some O&M pickup. Yes. Improvement, I should say.
That shows up. Okay. That's in the corporate segment?
Yep. Bingo.
Got it.
Yep. Versus what we showed you at EEI. Yes.
Okay. Super helpful. One other question, just on the SWEPCO new renewable megawatts. Do you have a sense how much of those you are going to be able to own. Are those all owned or some of those may be PPA, or how do we know the mix there?
We would certainly like to own as much of that as possible because I think it's really important from a capital structure perspective and these companies to be well-funded and have a firm foundation within the states we serve. We feel like that these generation resources, particularly the renewable resources, need to be vested within the operating companies. We'll continue that approach, and those are the filings that we'll make. Obviously, some portion of it may wind up being PPAs, but I think we have to get the message across that it's important to the vitality of the operating companies and the operating utilities in these states that we continue to flourish from a capital standpoint. I think, obviously too, the weather events and SPP demonstrate that. I'm going to be probably testifying again on this pretty soon.
I really think it's important for the utility to have a view of what generation looks like in these particular events, and the interaction and interoperability of these resources with the transmission and distribution system is incredibly important. I started my career as an electrical engineer in system operations, and I went through an ice storm in, actually I'll tell my age now, it was 1984. Mills were tripping with coal, power line was freezing, valves were freezing. All these activities were occurring, and it was our ability to redispatch and utilize the ties and those kinds of things that were important for us to be able to manage through that crisis. That's why I think it's important for there to be control features in place and, from an ownership perspective, be able to focus on ensuring those benefits for our customers.
You look at even some of the coal-fired generation that was in place, that mitigated some of the impact from a fuel cost perspective going forward with natural gas prices going up so much. There's a reason for each part of the portfolio, and I think it's important for the utility to be the party that runs those particular facilities. That's my view, and certainly we'll go into these cases with a firm view toward that.
Oh, great. Thanks so much. Agree. Take care.
Thank you.
Thank you.
Our next question comes from the line of Jeremy Tonet with JPMorgan, and your line is open.
Hi, good morning.
Good morning. How are you?
Good. Just wanted to start off with on O&M, if I could. Just wanted to see what you guys are seeing there, because it seems like it's a nice little step down even versus what you guys had at EEI there. Just wondering if you could provide a bit more color on what you see now versus then, and really the durability of those savings as you think about 2022 plus, just sticking around all these cost savings that you're pulling out.
This is Julie. Thanks so much for the question. O&M was a nice benefit to us in 2020, we're going to try to hang on to as much of that, and maybe a little bit more for 2021, as you can see in our forecast. The things that we're looking to would be things that are not only one-time in nature, obviously sustainable, and try to take the learnings that we were able to glean from the pandemic, really, and how we've had to operate in different ways. Things that we're talking about include things like data analytics, automation, digital tools, drone usage, outsourcing, workforce planning, other related items. Essentially, those types of things that I mentioned in my preamble at the beginning of the call here. Reducing non-essential travel and training.
We've been able to be very successful in a virtual format. That actually brings a fair amount of cost savings into the pocket as well. Reduce materials and supplies to the extent that we can continue to rein in on advertising, minimizing overtime, et cetera. We're looking at this from more of a sustainability or sustainable perspective, and we'll see what else we can pull out of the hat in terms of additional learnings as we go forward. It's a little bit of everything. I can't particularly point you to one thing. In fact, it's a variety of the entire team pulling together to be able to make this stuff come to fruition. The track record's there. We've been able to do it. We're going to continue to turn the crank.
That's very helpful. Thanks. Maybe just pivoting over towards the renewables. I think you mentioned 10 GW of wind and solar generation in regulated states by 2030 you're looking to add there. Just wondering if you could provide a bit more color on where you think that could fall out jurisdiction-wise. It seems like SWEPCO has a good focus here. Just wondering where else you might be seeing the potential over that timeframe.
Yeah, that's a number that continues to be in play. Obviously, we originally had, I think it was like 7,500 MW, 8,000 MW of renewables the last time we showed. Adding the 2,400 MW gets to 10,000 MW or so. As we further update this analysis, like I said, by our first quarter earnings call, you'll see more renewables being placed in as well. I think it is a work in progress.
Got it. Okay. We'll stay tuned there. Thanks.
Okay.
Just last one, if I could. Post the elections here, just wondering, Biden's plan for 2035, if that impacts you directly. Also with the new head of FERC here. Just wondering what that could mean on the transmission side, if you see more supportive actions there, and what opportunities that could bring to AEP.
Yeah. I think we'll continue to see supportive actions by FERC related to transmission, because obviously the build-out necessary to support renewables and clean energy is something that the Biden administration is taking on. I'd be highly surprised if there's any letup on that. Matter of fact, they're probably more aggressive than what the industry feels like they can do at this point. Certainly, in order to do that and aggressively meet the kind of targets that are being placed out there, transmission will play a critical role, and that means AEP.
Got it. That's very helpful. Thank you.
Thank you. Our next question comes from the line of Durgesh Chopra with Evercore ISI. Your line is open.
Hi, Durgesh. How are you?
Hey, good morning, Nick.
Good morning.
This is one of my favorite movies as well.
Yeah.
Julie, real quick, I just want to make sure I have this right. The last week's storm-related costs, I think when you add those numbers up between PSO and SWEPCO, roughly north of a billion dollar, $1.2 call it. The financing plan, the interest-related charges, are those incorporated into your 2021 guidance numbers?
Not yet, no. We have not yet updated our financing plan. We're actually holding tight just a bit here until we get a little more clarity on exactly how this stuff is going to roll out, and we have firming up of all those numbers. As I mentioned, we made an application at the commission in Oklahoma, so that's another piece of that as well. We will update you as we continue to move forward and make those crystallized plans for you. As I mentioned, what you can largely anticipate is taking on a little bit more debt. Obviously, you're picking up on that with the increased potential interest expense.
Obviously looking to be able to be sensitive to the customer needs as they try to absorb this cost, also managing the balance sheet and the metrics that we really need to have to stay at that Baa2 stable type rating and arrangement.
Got it. Okay. Understood. I guess maybe just in terms of the interest charges and other things, looks like at least near term, you're going to borrow debt. Is there a plan to offset that with O&M or other savings in the business?
Yeah. As a matter of fact, a couple of things that I'd point out. Number one, we're always going to work to mitigate any potential unforeseen risk, right? Plan-do-check-adjust as we move through the dynamic year. The other thing that you may recall me making a statement about specifically in my opening comments here, that application that we made for PSO in Oklahoma specifically called out the fact that we were looking for a regulatory asset with a mechanism that included a WACC. That's incredibly important to us as well. I know Nick made the comment several times through his opening comments regarding making sure that our balance sheet metrics are intact. Having a WACC helps us do that, because we need to be able to preserve the financial integrity of the operating companies as well as the entire enterprise.
Those are the things that we'll be looking at. It's early.
Understood.
Yep.
Thanks.
It's early.
Just one quick follow-up on the Ohio settlement discussions on the rate case there. The March 4th, is that the drop-dead date, or can that be extended?
Yeah, it can be extended. Obviously everyone's sort of geared toward March 4th, but it could be extended.
Okay. Thanks, guys.
Yep.
Much appreciate the update.
Yep. Okay.
Thank you. Our next question comes from the line of Julien Dumoulin-Smith from Bank of America, and your line is open.
Morning, Julien.
Hey, good morning. Thank you, team.
Yep.
Thank you, Nick.
Yeah.
Nick, maybe just to start here. You seem passionate about it, and I'm quite curious. You guys have a footprint that stretches RTOs here. How do you think about what reforms and weatherization looks like here, and how that could impact your capital budget? I hear your comments about reserve margins, et cetera. I'm just curious if you can elaborate a little bit further. What are your lessons learned from 2014 and 1984 here as you see them being applied, perhaps in Texas holistically, and especially as you see your specific dialogues kicking off, whether in Texas?
Yeah
Frankly, the other adjacent states as well?
Yeah. In 2014, I really testified over three issues. One was capacity markets and understanding the value of capacity, and certainly 24/7 base load generation. The second part of it was at that point in 2014, it was the dash to gas. It was gas and renewables. If we're going to depend upon natural gas for a substantial part, supply this country, then we really have to reinforce the ability for natural gas to perform during these types of events. That means someone's going to have to be able to pay for it, and markets will have to compensate generators for those kinds of investments. For the utility system itself, it really is around infrastructure to support resiliency and hardening of the system.
One of the other areas I talked about in 2014 was how quickly we retire units and what the replacements of those are, and how we're changing the nature of the generation mix. Those have different factors associated with the planning and operation of the grid. Those are critical areas where, I think, if I were to opine on Texas, it'd be more around market reform to support weatherization, market reform around communications that exist during crisis times. It's important for operators to know, and even T&D operators to know, where the generation is coming from to make adjustments from a transmission and distribution standpoint. When you think about some of these opportunities that exist for us, it's seams projects on the seams of the RTOs. It's particularly important to have interchange capability. Now, for Texas, it may be more DC ties.
It could be more transmission in general, but Texas will have to decide that. I think there's opportunities for more levels of interchange, more ability to put infrastructure in place to support weatherization, and then market changes to support the ability for capacity to be valued the way it should be based upon its contribution to the total grid. Those are key points that continue. With California, you sort of see the same thing. They're depending on heavy level of imports from out of state. If out of state has issues, then they have issues internal within the state. When you think about all those things, I think the planning and the optimization of what occurs is going to really carry the day in terms of our ability to better take care of these types of situations.
Got it. Excellent. If I could just quickly clarify your earlier comments here. To quote you, I think you used the expression, "The time for half measures and talk is over. Can you elaborate a little bit on the timing there, just as you think about it? Obviously, you're already moving. It's probably a question for Brian more than Nick. What's the timing of this? Just to make sure we're on the same page here, whatever it may be.
Yeah. I think you have to see those decisions start this year. I think what's crystallized for us is really the path that we're taking. We're moving to a clean energy future. We need to be able to move from a regulatory standpoint to ensure that we're achieving the balance sheet capacity to do the things that need to be done for the transition and the optimization of the grid. I think it's really important for us to be able to manage internally, not only from an O&M perspective, but also our assets, generally what the assets are that contribute to not only an improved return for our investors, but also in terms of optimization of the business itself. That will be part of the path because you really have two, maybe three forcing functions. One of those is the movement to a clean energy economy.
The other is the capital structure and balance sheet of the company. The third is really focused on those two objectives, but ensuring that we're moving forward with infrastructure development and grid development to support resiliency and reliability of the grid. Those things together, along with electrification, I think are really going to be tailwinds for this industry going forward. In particular, AEP is the largest transmission provider. We have a large distribution footprint. We have significant amount, as I said in the last earnings call, we were on the precipice of clean energy transformation. A lot of opportunity for AEP. We just need to make sure we manage all those throttles to ensure that we're consistently driving forward.
Got it. Thank you, guys. Best of luck.
Yep.
Thank you. Next, we will go to the line of James Thalacker with BMO Capital Markets. Your line is open.
Good morning.
Thanks so much. Good morning. How are you guys?
Just fine.
Good.
Great. Welcome back, Julie. It's great to hear your voice.
Thanks, James.
Julie addressed some of the asset rotation to mitigate your financing needs. Nick, it's been a while since you've, I guess, updated how you're thinking about how you prioritize growth via the different channels that are in front of you. Obviously, Chuck's working on the non-regulated side on renewables, and you've got plenty of opportunities of regulated growth on the renewable side transmission. Just wondering, how are you thinking about inorganic growth, maybe on the regulated side? How are you prioritizing all those different opportunities in front of you?
Yeah. Obviously, our priorities are around transmission, distribution infrastructure. Certainly, on the regulated transformation of the resources that are ongoing. Chuck's business with AEP Energy and so forth, they've done a great job of managing risk around that business. They've also done a great job in terms of their allocation of capital and being able to manage it, not only within their own part of the business, but also in total of the entire enterprise. Chuck is more than willing to turn capital over if it's of better use anywhere else in the corporation, and vice versa. We would like for that business to be less than 10% of the overall business. It continues to track that.
It gives us the ability to not only further optimize that business, and you're seeing really continued opportunities on that part of the business with AEP OnSite Partners on special relationships with customers around resources that really drive tremendous benefit for us because we can also approach that on the regulated side as well. I think there's an opportunity there, but certainly our focus is ensuring that we're able to move forward with this clean energy transformation and all the optimization around the grid and the grid resiliency and the issues there, and do it in a very pragmatic way. That means we're going to have to make sure that whoever is progressing better from that perspective, that's where the equity is going to go. We need to ensure that we're managing that portfolio in that fashion.
We can now look at this business like it's a fully regulated business. We can make decisions. There obviously are things that we look at like, what's the quality of the service territory? What's the quality of the regulatory environment? What's the ongoing view of valuation of any particular entity for us, for someone else? What that means in terms of rotation of capital, in terms of optimization. We are continuing that approach. I would say that we've said in the past that for all of our utilities, if we see the ability to continue sustainable growth and quality growth in those jurisdictions, they make a lot of sense to us. Then, of course, we have to look at also those that are challenged and understand what those challenges are. Can we erase those challenges? Are they systemic challenges?
Those are the kinds of things we have to look at, and we'll continue to do that, and that's what Brian is doing.
Okay, great. I guess just one last follow-up on that because I know we're running up on time here. When you look at all the opportunities, like you just rolled out another 2,400 MW of renewables.
Yep.
Transmission's always been something you've had plenty of opportunities to. Do you still look at those opportunities like where you can put earning assets in at 1x rate base as your best opportunities? Or do you see, as you look across the landscape, inorganic, maybe M&A of regulated properties as something that makes sense? Or is it just better to stick to your point in the jurisdictions where you see the growth, it's visible, and you've got a good regulatory sort of opportunity to achieve your goals?
I think our primary focus is do it at one times with the organic growth that's occurred. That's really why the previous question about whether we want to own the renewable assets or not. The question is, if we own those renewable assets, that gives us more capacity to be able to invest, we can take full advantage of tax benefits and other things that enable us to continue to organically grow. As I said earlier, we have a very high threshold for M&A because we do feel like that we have plenty of opportunities. We just have to manage the portfolio in a way that optimizes that going forward. That's the way we think about it. From an M&A perspective, it has to be strategic, it has to be accretive for shareholders.
It has to be something that really produces strategic benefit for us in some fashion of what we're trying to do. Again, that's a high threshold.
Great. Thanks so much for all that.
Yep.
Thank you. Our next question comes from the line of Andrew Weisel with Scotiabank. Your line is open.
Morning, Andrew.
Hey, good morning. Thanks for all the good detail on renewables. I just want to dig into one or two relative to your CapEx outlook. You mentioned the incremental capacity at SWEPCO, and then you mentioned that you'll do an AEP-wide regulated renewable plan in the coming months. Would a lot of that be incremental to the $37 billion? I know a lot of the spending will probably come after 2025, do you think of that as upside to the plan?
It's early to tell, but we would like it to be incremental. We'll be working to help support that. Obviously, as you said, some of it's 2025, some of it's 2028. As we progress, we want to make sure, okay, if cash flow increases, load continues to improve, optimization of capital deployed has a lot of benefits associated with that. There's a lot of parts in the puzzle. Sort of like when we did North Central, we didn't know what the financing plan for that was. We continue to focus on that one. We'll also continue to focus on trying to make sure that they are seen as incremental. That's our focus. Whether we have to obviate some of that with the redeployment of capital or not remains to be seen, but the target is for it to be incremental.
Okay, great. On the RFP at SWEPCO, you mentioned that you prefer to own those assets. Do you plan to bid in from the contracted renewables business as well as from the regulated utility?
Well, from the contracted renewables business, there may be rules associated with that. Just like with North Central, we did sort of a turnkey type thing that really allows us to time the recovery with the investment itself. That's always sort of a preferred opportunity for us because it really is handled well from a financial standpoint and also handled well from a risk standpoint relative to the construction and customers, the risk to customers as well. I think we'd probably stick with something like that. Whether our contracted business is on the back end or not is another question. I mean, obviously, we don't really care if it's our contracted business or someone else, as long as at the end of the day, we wind up owning it.
Yep, got it. That makes sense. One last one, just to clarify. I think you said you still want that contracted renewables to be capped at about 10% of the company. Did I hear you right? Given the overall growing demand for renewables across the country and support out of D.C., does that mean that you'll be more selective in your projects or look for higher returns or lower risk?
Yeah.
How do you think about that dynamic?
No, that's exactly right. We've always managed that business around higher returns. We want to be commensurate on a levered basis with our regulated businesses. We will continue. Matter of fact, we turn away a lot more projects than what we actually move forward with. As you probably have seen, it just seems to get more aggressive all the time about what the return levels are. The difference is really what people say at the end of a contract, what that terminal value is. We really don't want to get into that kind of war. We really focus on those relationships with customers and developers that help us move forward with very positive projects. That's the way we'll continue to look at that business. OnSite Partners and others with specific customer-related issues.
Like, for example, here in Columbus, we have several businesses that have signed up for a joint renewables project that we continue to focus on. We do aggregation of customers in Columbus, which was approved by a referendum vote that AEP Energy would be doing. It's those kinds of things that we can mix and match and tailor the relationship that the customer is looking for. I think that's what we're after.
Just to circle back real quickly, too, if I could. As an initial comment. As it relates to that threshold in terms of business mix, there are a couple of reasons why that 10% makes sense for us, n umber one, to a credit profile risk management perspective, that's very important for us. That's something we keep top of mind. The other is really on tax shield associated with debt. We've got a couple of things that we're sensitive to and just continue to high-grade the earnings opportunities from our unregulated contracted renewables business. That gives you probably a little bit more perspective, if that wasn't already top of mind for you, because it surely is for us.
Okay. Very helpful. Just want to echo the congrats to Julie and congrats to the team on another strong year.
Awesome.
Thank you.
Thank you.
Thank you. Our final question will come from the line of Paul Patterson with Glenrock Associates. Your line is open.
Morning, Paul.
Hey, good morning. How are you guys?
Good morning. Just fine.
Strange to hear your voice, Julie.
Hey, Paul.
Just some quick follow-up on the Oklahoma filing. I haven't had a chance to look at it. My understanding was I heard you correctly that you're asking for a Weighted Average Cost of Capital. I was wondering, how long will it take to amortize the asset, I guess?
Yeah.
Under what you're filing for.
Yeah. Well, actually, we haven't been prescriptive in our filing, we've got a little flexibility there. That's another reason why I mentioned we're thinking about any potential financing in the interim and how that would map to any potential outcome there. I do know that one of our peer companies out in Oklahoma made a similar filing, I believe that it was 10 years on theirs as well as a WACC to give you a kind of perspective. We want to be sensitive to customer bills as well, as I'm sure you can imagine.
Okay, sure. When do you think we'll get some sort of feedback from the commission?
Probably a couple of months.
Okay.
I don't have a timeline yet.
Sure. It's all early.
Yeah.
Just a really quick one on APCO. As I recall, you guys were granted rehearing in the case. You guys are also apparently filing an appeal. I was just if you could elaborate a little bit more on that. There was a decision.
Yeah, that's right.
On, okay.
We did file for rehearing, and it was granted. The parties are filing briefs. That it stands with the commission. Also, we filed in the Supreme Court of Virginia, because we're not wasting time.
Just to sort of understand it procedurally, do you expect to get something from the Supreme Court before the commission, or the commission, I would think normally before the Supreme Court?
Yeah. It's normally the commission before the Supreme Court. Obviously, we felt like it's such an important issue and a focus on what we believe state law says, that it's important for the Supreme Court to resolve that issue in case the commission doesn't.
Okay. Do you know when the commission might come out? Is there a schedule on that, or is it just whenever they want to?
Yeah, I think it's whenever they want.
Okay. Awesome. Thanks so much.
Okay. Thank you.
Thank you. Speakers, do you have any closing comments?
We do. Thank you for joining us on today's call. As always, our team will be available to answer any additional questions you may have. Cynthia, would you please give the replay information?
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