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Ladies and gentlemen, thank you for standing by. Welcome to the American Electric Power Third Quarter, 2021 Earnings Conference Call. At this time, your telephone lines are in a listen-only mode. Later there will be an opportunity for questions and answers. If you would like to ask a question during the call, [Operator Instructions] You have an indication you've been placed into queue, and you will move yourself from the queue by repeating the one as we command. [Operator Instructions] Now as a reminder, your conference call today is being recorded. I will now turn the conference call over to your host, Vice President of Investor Relations, Darcy Reese. Go ahead please.
Thank you, Allen. Good morning, everyone and welcome to the Third Quarter 2021 earnings call for American Electric Power. We appreciate you taking the time to join us today. Our earnings release, presentation slides and related financial information are available on our website at www. 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 and Julie Sloat our Chief Financial Officer. We will take your questions following their remarks. I will now turn the call over to Nick.
Okay. Thanks, Darcy. Welcome again, everyone to American Electric Power's third quarter 2021 earnings call. Today we're pleased to report a strong third quarter operating earnings of a $1.43 per share for the third quarter, this brings our year-to-date operating earnings to 376 per share versus 356 per share last year, which gives us confidence in raising the midpoint of our guidance range for 2021.
AEP service territory continues to prove us with resiliency and stability with continued economic recovery experienced in the third quarter. In fact, AEP posted the strongest sales quarter in over a decade, and the gross regional product for the AEP footprint of third quarter was the highest on record, as well as job growth being the strongest since 1984. The strength and diversity of our portfolio, the robustness of our organic growth opportunities, and our consistent ability to execute against our plan places AEP among what we believe should be one of the country's premium regulated utilities.
Our strength -- our strong performance this quarter, coupled with the level of economic recovery experienced within our footprint, provides us, once again, the confidence needed to raise our midpoint to 470 per share and nearer, the 2021 guidance range to 465 to 475 while reaffirming our 5% to 7% long-term earnings growth rate. And as I've stated previously, I would still be disappointed if we were not in that upper half of our long-term growth rate. The driver of our strong performance is the talent and commitment of our employees.
Our front line of central service work teams has continued to adapt to ensure the needs of our customers and communities are met day in day -- day in and day out throughout the pandemic. Like many industries, the face of work for AEP will never be the same. As employees return to the office, we have taken actions to ensure the safe return to the workplace environment. I remain appreciative of the dedication of our employees and have the utmost confidence in their continuing ability to successfully check and adjust as we adapt to the future.
We believe that this new work environment will continue to enable more efficiency, flexibility, and creativity, that will contribute to the culture to excel in meeting our strategic objectives. This new future of work along with digitization and automation will continue to provide benefits for our Achieving Excellence program. Our growth opportunities over the next decade are significant driven by our future forward renewables plan, that over 16 gigawatts of new renewables resources by 2030, and the transmission distribution investments needed to support the needs of a clean energy economy for our customers and communities.
Additionally, the completion of a strategic review of our Kentucky Companies and our decision to move forward with the sale delivered utilities enables us to focus our attention on executing that transaction and delivering on our gross strategy. So, let's cover the announced sale of Kentucky Power. Earlier this week, on Tuesday at market close, we announced the sale of Kentucky Power and Kentucky Transco to Liberty Utilities, the regulated utility operation of Algonquin Power.
The sale was a result of the strategic review that we launched back in April. The sale was subject to regulatory approvals, including approvals from the Federal Energy Regulatory Commission which is within a 180 days, and the Kentucky Public Service Commission, within a 120 days. The transaction was also subject to federal clearance pursuant to Hart-Scott-Rodino, which typically is within 30 to 60 days, and the clearance from the Committee on Foreign Investment in the U.S., within 90 and a 120 days for that approval.
We anticipate making these regulatory filings in late November and early December. Separately, we will file -- with both the Kentucky, West Virginia and full commissions with necessary changes to the metro plant operating agreement to accommodate the ELG investments recently approved by the West Virginia Commission. The following will include a plan to resolve the question of Mitchell ownership post 2028. Both state commissions are expecting these filings as both issued recent orders directing us to do so.
These filings will be made in the mid to late November time frame. We're also very pleased with the outcome of the strategic review and know that the future owner of our Kentucky assets will be a great steward for all stakeholders in Kentucky, our value employees, customers, and certainly the communities. Lastly, I want to thank all the Kentucky employees and the corporate support employees for their patience, during this review and for their continued focus on safety and operational excellence during this period, and as the transaction is completed. Now, moving to several of the regulatory activities.
In Ohio, we expect an order in the fourth quarter on the settlement reached and filed with the Commission earlier this year. As a reminder of the settlement has broad support from the settling parties, including the commission staff, Ohio consumers’ counsel, Industrial companies, commercial companies, and other entities like Ohio Hospital Association. Additionally, AEP Ohio's grid smart Phase III settlement was filed yesterday and paves the way to continue our deployment of advanced smart grid technologies, including completion of our AMR meter rollout, the remaining 475,000 rollout customers.
The unopposed settlement with support from commission staff allows consumer's counsel and several of our largest customers demonstrates that AEP Ohio continues to maintain a great working relationship with our regulator and interested parties. Public Service Company of Oklahoma reached a settlement in the rate case with the Oklahoma staff and other parties. The settlement was presented to the commission on October 5th. The black-box settlement includes 50.7 million net increase in rates while adding another 102.7 million in base rates.
In addition to continuing the practice of allowing some interim recovery of Capex riders, the rider collecting for Maverick and Sundance North-Central wind assets was also included, in orders expected by year-end with rates reflected in November bills. In Indiana, the unfollowed base rate case on the July 1st based on a future test year model seeking 97 million in net revenue increase with a 10% ROE.
Major items included recognition of over 500 million in capital investment per year in Indiana continuation of the transmission tracker a federal tax rider in the event of a change in federal tax rates and the advancement of AMI to provide customers greater control insight into their usage. The hearing was set before the Indiana Utility Regulatory Commission on December 2nd, with an order expected by April of '22. In a Southwestern Electric Power Company's jurisdictions cases are pending in Louisiana, Texas, and Arkansas.
The SWEPCO Texas Commission deliberations set for November 18th. Parties filed exceptions to the preliminary draft order issued by the hearing [Indiscernible] and replies. So those exceptions were filed yesterday. SWEPCO is seeking a net revenue increase of $73 million with an ROE of 10.35%. Our file includes investments made from February 2018, accelerated depreciation for [Indiscernible] plant, a strong reserve, increased vegetation management.
We expect an order in the fourth quarter with rates being retroactive back to March of '21. In SWEPCO Louisiana testimony has been filed a hearing scheduled for January of '22. A case $6 million to $73 million net revenue increase and a 10.35% ROE in order to expect between the second third quarter of '22. And so, at Arkansas, we were seeking a $56 million net revenue increase with a 10.35 ROE. The following contains with formula rate plan for subsequent years and considers the pending retirement of previously announced call net assets.
This fall, we used time to align with the North-Central in-service dates and the provided mechanism both for recovery of costs associated with the investment and flow through of the PTC in SWEPCO customers. The hearing is set for March of '22. Both SWEPCO and PSO continue to make progress to recognize the Storm Uri expenditures. As a reminder, we filed for recovery of a lack returned over 5 years in Louisiana, Arkansas, Oklahoma, and Texas.
PSO is moving forward with the state on the securitization of costs as premiering under Oklahoma law. We are continuing our efforts to secure approvals and clear clarity regarding investments necessary to with the EPA, CCR, ELG requirements. We received [Indiscernible] to construct the CCR compliance plans in Virginia, West Virginia, and Kentucky. While West Virginia approved ELG investments, Virginia, and Kentucky did not.
West Virginia has since determined it was in the public interest to move forward with EOG investments for all 3 plans and has issued an order regarding in support of West Virginia investing to preserve the option for these plants to run past 2028, approving both the investment inward cost recovery from West Virginia customers. We'll be working with our commissions to implement the West Virginia decision and making the necessary adjustments to respect each state's decision.
The Virginia Commission ask us to come back with more information, so we'll do that. We plan to lay out all the options before them, on how to satisfy their capacity needs. The Virginia PSC were approved the first-year revenue requirement of 4.8 million for broadband, which means we now have recovery for our world broadband efforts in both Virginia, and West Virginia.
We continue to engage legislators and commissions, and other states and stand ready, to invest in synergistic mid-model broadband, to support advanced group technologies, and rural broadband for our communities. We also understand, it's all about execution. On September 10th, AEP began commercial operation of the 287-megawatt Maverick Wind Energy Center in North Central Oklahoma.
Maverick was one of three wind projects that composed the North Central energy facilities, which will provide 1485 megawatts of clean energy to customers of our PSO and SWEPCO subsidiaries. The Traverse project, the largest single site wind farm in North America is well under construction and will come online in the January to April 2022 time frame. Transforming the way energy is generated, delivered, and consumed is necessary to support the needs of a clean energy economy and AEP continues to drive that transformation for the benefit of our customers and communities.
With the success of doors central setting the foundation of our future forward regulated renewables platform, we are diligently working on securing additional renewable opportunities for our customers. RFP filings are going -- are ongoing and planned in multiple states. So more to come on this as we file for approval, after resources, as a result of the RFP that were out in the market for which some of you probably have heard of, we will be able to provide greater detail on the progress being made.
Further, if federal efforts through the various tax proposals to extend and expand PTCs, ITCs for Clean Energy Resources succeed, even more benefits will be enjoyed by our customers. So now, we move quickly to the equalizer char now at this point, and I'll go quickly through this. So far, the average with the overall regulated operations is currently 9%. We generally target in the 9.5% to 10% range. So obviously we continue to work on that. AP Ohio came in at 9.3% for the third quarter, as blow authorized primarily due to timely recovery of capital investments, partially offset by higher O&M expenses.
We expect that ROE to trend around authorized levels, as we maintain concurrent capital recovery of distribution, transmission investments. We also, as I mentioned earlier, expect the commission order here in the fourth quarter of '21. After it came in at 7.3%, as below authorized due to higher amortization, primarily related to what's hard coal-fired-generating assets, and higher depreciation from increase Virginia depreciation rates and capital investment. And as you know, we are still at the Appeals Court appealing -- the Virginia Supreme Court, which is currently outstanding.
We filed appeal with that Virginia Supreme Court, so we're still waiting on that. As far as Kentucky is concerned, 6.9% below authorized due to loss of load from weak economic conditions and loss of major customers. Transmission revenues were also lower due to the delay in some capital projects. I&M came in at 10.3%. It's rare that's authorized ROE primarily due to increase in sales, partially offset by increased OEM and depreciation expenses associated with items continued capital investment programs. As far as PSO is concerned, came in at 7.6%.
It's below its authorized level primarily due to increased capital investment currently not in base rates and higher than anticipated equity due to the extreme February winter weather event. And of course, we expect the commission order here on the rate case in the fourth quarter of '21. SWEPCO came in at 8.2% as well authorized due to increased capital investment currently not in base rates and the continued impact of the Arkansas share of the Turk plant that is not in retail rates.
The Turkish, you again, accounts for about 110 basis points that we're not recovering in Arkansas. Again, as I mentioned earlier, we expect various commission orders, and particularly in Texas, in the fourth quarter of 2021, it's retroactive back to March. API Texas came in at 8.2% as below authorized primarily due to the significant level of investment in Texas. And of course, we have favorable regulatory treatment there with that annual DCOS and bi-annual TCOS filings to recover rates.
So significant levels of investment in Texas will continue to impact the ROE. But the expectation is for the ROE to trend towards an authorized 9.4% in the longer-term. AEP Transmission Holdco came in at 11.2%. It was above authorized primarily driven by differences between actual and forecasted expenses. The transfer will benefit from a forward-looking formula rate mechanism, which helps minimize regulatory lag, and that forecasted dollar rate is around 11% in 2021. So overall, continue to make progress.
Cases, obviously, we're waiting to hear the results of several cases that should provide some additional benefits, but that work continues. So, in closing, we are executing all [Indiscernible] and continue to drive the results expected of a premium regulated utility. The AEP portfolio is one that has enabled our investments in the wire side of the business supporting our transmission investments, including the $0.33 per share this quarter, through our AEP trends -- transmission Holdco investments.
Our plan to transition our generation fleet and reduce carbon emissions by 80% by 2030 and net 0 by 2050 is well underway with 2 of our 3 wind facilities of our 2 billion investment in North-Central land under our belt, providing a solid foundation for the next decade of growth. Throughout this transition, we remain engaged in a trusted voice on energy transformation efforts, helping to ensure responsible transition to clean energy economy.
And we will continue to support Federal efforts in that regard and State efforts as well. Finally, our strong quarter performance gives us the confidence again, to set our midpoint at 470, or the range of 465 to 475. And we continue to have all 17,000 employees dedicated to our customers and communities to enable the strong performance. Our discipline and controlling cost, our progress to manage the portfolio, and the significance of our future organic growth opportunities provides us with a confidence needed, in raising the midpoint and nearing the guidance range.
Two weeks ago, I was really struck by the half time performance of the Ohio State Buckeyes marching band. They set their goals in my opinion, really high. Never do I expect to see a marching band dedicate their halftime show to the music of Rash (ph), to hear Tom saw your yyz(ph), the limelight and others, was truly amazing when they are difficult to even play. even though they were also marching while designing guitar players, drones, and other choreography on the field. The creativity and the execution came through to deliver a truly remarkable show.
It made me think of our team at AEP, on November 11th, I've been AEP CEO for 10-years, I'm fortunate to lead a great Company with great people who have an outstanding track record of delivering on the promises made to investors and customers consistently year in and year out. And we fully expect to continue our drive to take this Company to the next level toward the clean energy economy and a solid infrastructure foundation bucks-rating aggressive goals and delivering with creativity and solid execution. With that, I will turn it over to Julie.
Thanks so much, Nick. Thanks, Darcy. And Nick I love your Buckeye reference. Go Bucks.
I love that.
Thank you very much. Big game this weekend. Anyway, it's good to be with everybody this morning. I'm going to walk us through the third quarter and year-to-date financial results. I'll share some updates on our service territory load, and finish with some commentary on financing plans, credit metrics, and liquidity. Let's go to slide six, which shows the comparison of GAAP top rating earnings for the quarter and year-to-date periods.
GAAP earnings for the third quarter were $1.59 per share, compared to a $1.51 per share in 2020. GAAP earnings through September were $3.90 per share compared to $3.56 per share in 2020. There's a reconciliation of GAAP to operating earnings on Pages 14 and 15 of the presentation today. Let's go to Slide 7 where we can talk about our quarterly operating earnings performance by segment.
Operating earnings for the third quarter totaled $1.43 per share or $717 million compared to $1.47 per share or $728 million in 2020. Operating earnings from the vertically integrated utilities were $0.87 per share, up $0.02. Favorable drivers included, rate changes across multiple jurisdictions, weather primarily in the West, transmission revenue and lower income tax.
These items were offset somewhat by higher O&M expenses to in part to lower prior year O&M, which included actions we took to adjust to the pandemic and higher depreciation expense, as well as lower normalized margins and lower AFUDC. The Transmission and Distribution Utilities segment earned $0.31 per share flat to last year. Favorable drivers in this segment included rate changes, transmission revenue, and income taxes.
Offsetting these favorable items were O&M expenses again, a function of lower prior year O&M associated with pandemic growing efforts, depreciation, and property taxes. The AEP Transmission Holdco segment continued to grow, contributing $0.33 per share, that was an improvement of $0.05, driven by the return-on-investment growth. Generation and Marketing produced $0.04 per share, down $0.09 from last year, includes by the prior-year land sales, lower retail volumes and margins, generation and income taxes.
Finally, Corporate and other was down $0.02 per share driven by lower investment gains, and unfavorable net interest expense, which was partially offset by lower income taxes. The lower investment gains, are related to a pullback of some of the ChargePoint related gains, we've talked about on prior quarters. Let's have a look at our year-to-date results on slide number 8. Operating earnings through September totaled $3.76 per share, or $1.9 billion compared to $3.56 per share, or $1.8 billion in 2020.
Looking at the drivers by segment, operating earnings for vertically integrated utilities, were $1.87 per share down $0.03, due to higher O&M and depreciation expenses. Other smaller decreases included lower normalized sales and wholesale load, higher other taxes, and a prior period fuel adjustment. Offsetting these unfavorable variances were weight changes across various operating companies and the impact of weather due to warmer than normal temps in the winter of 2020 and the summer 2021, which created a favorable year-over-year comp for us.
Other favorable items in this segment included higher off-system sales, transmission revenue, net interest expense, and income taxes. The transmission and distribution utilities segments earned $0.85 per share, up a penny from last year. Earnings in this segment were up due to higher transmission revenue, rate changes, weather, normalized load, and income taxes. Partially offsetting these favorable items were increased depreciation, O&M, other taxes, and interest expenses.
AEP Transmission Holdco segment contributed $1.02 per share up $0.27 from last year, related to investment growth and favorable year-over-year true-up. Generation and marketing produced $0.20 per share down $0.11 from last year due to favorable one-time items in the prior year relating to an Oklaunion ARO adjustment in the sale of Conesville and reduced land sales in 2021.
Higher energy margins and low expenses in the generation business offset the unfavorable [Indiscernible] marketplaces on the wholesale business during storm yearly in February. We also saw an unfavorable result in retail due to lower power and gas margins. Income taxes were also unfavorable. Finally, Corporate matter was up $0.06 per share driven by investment gains and lower taxes and partially offset by higher O&M.
Let me take a quick minute here to talk about the investment gain, which is predominantly a function of our direct and indirect Investment ChargePoint. As you'll see on the waterfall, was produced a $0.06 benefit year-to-date in 2021, as compared to the corresponding 2020 period. You may recall that in the fourth quarter at full-year 2020, this investment produced a $0.05 contribution, and we would expect the year-over-year bids to be more pronounced at this point in 2021, as we have no benefit during the same period in 2020.
Turning to Page 9, I'll update you on our normalized low performance for the quarter. We, then, get into the specifics. Let me start by reminding everyone that everything you see on the slide is showing year-over-year growth. That means these numbers can be influenced by what was going on last year or what is happening now in 2021. Given all that occurred in the economy last year, it's obvious that these growth rates are at least partially being influenced by the comparison basis.
This leads to the natural follow-up question like, how does today's low compare to pre -pandemic level? And I'll get to that question on the next slide. But before I do, let's take a look what a -- at what our normalized low growth was for the quarter. Starting in the upper left corner, normalized residential sales were down 1.6% compared to last year, bringing the year-to-date declined down to 9/10 of a percent.
That means that last year, residential sales were up 3.8% in the third quarter when the economy was just starting to reopen. One year later, they're down only 1.6%, which suggests there has been a shift up in residential sales, as more businesses have embraced a remote workforce for jobs that can be performed at home. The last item to point out on the residential charges that you'll notice that we added a new bar to the right, showing our latest projection for 2021 based on the load forecast update.
The original guidance assumed residential sales would decrease by 1.1% in 2021. The latest update showed an improvement as we now expect residential to end the year down 9/10 of a percent. Moving right, weather-normalized commercial sales increased by 5%, bringing the year-to-date growth up to 4.3%. Last year's third quarter commercial sales were down 4.6%. So again, we're seeing a net positive stories of commercial sales classes bouncing back faster than expected.
And while we're seeing a strong bounce back and the sector's most impacted by the pandemic such as schools, churches, and hotels, we're actually seeing the strongest growth in commercial sales this year from growth in data centers, especially in the Central Ohio. To give you some perspective, last year, the sector was the 9th largest commercial sector across the AP system. Today, it's the 6th largest, and will likely move further up in the rankings as more data center loads are expected to come in online over the next several years.
You will also notice that our latest load forecast update now suggests that commercial sales were end-year up 3.7% as opposed to the 0.5% decline assumed in the original guidance forecast. The economy has recovered much faster than we originally assumed, which is one of the reasons why we've updated the forecast and ensuring an improvement in that regard. In the lower left corner, you'll see that industrial sales also had a very strong quarter.
Industrial sales for the quarter increased by 7%, bringing the year-to-date up to 4.2%. Industrial sales were up at every operating Company in nearly every sector. I point out, however, that the 7% growth in the third quarter this year did not quite offset the 7.8% decline experienced last year. Which means we still have a little more room to grow before the industrial class fully recovers from the pandemic recession. The good news is we have a lot of momentum to work with.
The latest node update now projects industrial sales will end the year up 4.3%, which is 2.4% higher than assumed in the original guidance forecast. Finally, when you put it all together in the lower left corner, you'll see that normalized retail sales increased by 3% for the quarter and were up 2.3% for the first 9 months. But all indications that recovery from the pandemic and recession is happening faster than expected and our service territory is positioned to benefit from future economic growth. You'll recall that the original guidance forecast assumed normalized load growth of 2/10 of a percent in 2021.
Based on our latest update, we're now expecting to end the year up 2.2%, which is a supporting factor in narrowing our earnings guidance range, and raising the midpoint for 2021. Turning to Slide 10, I want to answer the question from earlier, that asked how our current low performance compares to pre -pandemic levels. This bar chart is designed to answer that question. The blue bars are the same year-to-date bars that we shared on the prior page. As a reminder, these represent growth versus 2020, which was influenced by the restrictions implemented to manage the public health crisis.
The orange bars here show how the year-to-date sales in 2021 compared to 2019, which was the most recent pre - pandemic year for comparison. These bars tell us how close we are to a full recovery from the pandemic. Starting at the left, you'll notice that a reported residential sales are down 9/10 of a percent compared to last year, but they're actually up 1.6% compared to our pre -pandemic levels. This is a gauge for how our customers behaviors have changed since the pandemic, with more people working from home.
The next bar shows that while commercial sales are up 4.3% compared to last year. There are still 8/10 of the percent below the pre -pandemic levels. Given the recent growth we're seeing, especially in the data center nodes, we would expect commercial sales to fully recover nearly soon. Moving further, right, you can notice that while the industrial sales were up 4.2% compared to last year, they are still 3% lower than pre -pandemic levels.
Given some of the headwinds for manufacturing today with supply chain disruptions, later shortages, et cetera, it may take a little longer before the industrial quest fully recovers from the pandemic recession. But we do expect to eclipse the pre -pandemic levels in 2022. In total, our normalized load is up 2.3% compared to last year and is now within 7/10 of a percent of being fully recovered from the pandemic, so it's safe to say that we're pleased with the strength and balance of this recovery in the AEP system. Let's check on the Company's capitalization and liquidity on Page 11.
On a GAAP basis, our debt-to-capital ratio decreased 0.4% from the prior quarter to 62.2%. When adjusted for the storm during event, the ratio is slightly lower than it was at year-end 2022, sorry 2020, and now stands at 61.5%. Let's talk about our FFO to debt metric, as in the first and second quarter. Effective storm yearly continues to have a temporary and noticeable impact, on this 2021 metric. Taking a look at the upper right quadrant on this page, you'll see our FFO to debt metrics based on traditional Moody's and GAAP calculated basis. As well as an adjusted Moody's and GAAP calculated basis.
On a traditional unadjusted basis, our FFO - to -debt ratio increased by 0.9% during the quarter to 10.2% on a Moody's basis. And just, again, reiterate, radio agencies continue to take the anticipated recovery into consideration as it relates to our credit ratings. So very important to note that. On an adjusted basis, the Moody's FFO-to-debt metric is 13.6%.
This figure removes or adjusts the calculation to eliminate the impact of approximately 1.2 billion of cash outflows associated with covering the unplanned urine-driven fuel and purchase power in the SPP region, directly impacting PSO and SWEPCO in particular. The metric is also adjusted to remove the effect of the associated debt we used to fund the unplanned payments. This should give you a sense of where we would be from a business - as -usual perspective with that 13.6%.
Importantly, as Nick mentioned, the recovery of the [Indiscernible] fuel and purchase power expense in the PSO and SWEPCO jurisdictions is well underway and we're making progress. As a result, inconsistent with what we have previously communicated, we still anticipate our cash flow metrics to return to below the mid-teens target range next year. Obviously, we are trying to push towards the mid-teens range, but that will take us a little while longer, but we're definitely on our way there.
And as you know, we'll keep you posted on our progress. Before we leave the Balance Sheet topic, I do want to make note of the intended change to our 2022 financing plan, in light of our announced sale of Kentucky Power and Kentucky Transco. You may recall that we had planned to issue $1.4 billion of equity in 2022, that's inclusive of $100 million dividend reinvestment plan to fund our growth Capex program, where we will provide our typical 3-year forward annual review of our cash flows and financial metrics at the upcoming EEI Conference, where we can expect to see is that the 2022 forecast will be adjusted to eliminate the previously planned $1.4 billion of equity financing that I just mentioned with any residual proceeds being used to reduce a small portion of the 2022 debt financing that we had planned.
These actions will have no impact on our previously stated credit metric targets or messaging in that regard. On the slide deck today, on page 39, you'll see our current cash flow forecast, with which you are already familiar, We've included a note on the side to reflect the fact that the numbers have not been updated for the announced Kentucky transaction, along with the red circle around the 2022 financing -- equity financing amount that will be changed and updated when we roll out the new view in a couple of weeks in conjunction with the EEI conference.
So, while we're talking about the Kentucky transaction, I can also share that we expect that the sale will be $0.01 to $0.02 accretive in 2022, and we will reflect this in our 2022 earnings guidance that we provide to you at the EEI Conference. Okay. So back to our regularly-scheduled earnings call programming and commentary. Let's take a quick moment to visit our liquidity summary on the lower right slot -- side of Slide 11.
Our 5-year $4 billion bank revolver and 2-year $1 billion revolving credit facility, along with proceeds from the quarter-end debt issuance, support our liquidity position, which means we were strong at $5.1 billion. If you look at the lower left side of the page, you will see that our qualified pension continues to be well funded at a 104%. Additionally, our OPEB is funded at a 173.9%. Let's go slide 12 and I'll do a quick wrap up and we can get to your questions.
Our performance through the first 3 quarters of this year gives us confidence to narrow our operating guidance to the upper half of our current range, resulting in the new range of $4.65 per share to $4.75 per share with a midpoint of $4.70 per share. As we stated, we are committed to our long-term growth, rate target of 5% to 7%. Today's 2021 earnings guidance revision is yet another demonstration of our drive to deliver performance in the upper half of our guidance range. From a strategic perspective, we're making significant progress in addressing items that are top of mind for our current and perspective investors.
We're mounting contract to sell Kentucky Power and Kentucky Transco, which we expect to complete in the second quarter of 2022. This transaction enables us to avoid the 1.4 billion equity issuance, that was part of our original forecast, would share with you for 2022. Therefore, alleviates the overhang, the equity overhang. Also allows us to deliver transaction that we estimate to be 1 to 2 [Indiscernible] in 2022.
We will be more able to do this, while concurrently preserving our ability to get our FFO to debt metrics comfortably, into that mid to low teens range by 2022, which is commensurate with a Moody's BAAT stabilizing, as we continue to target that. The intention is to remain in this credit metric range. Again, with a preference to try to get closer to that midpoint, as we move along in time. All of this positions us to continue our generation transformation, which is underpinned by the renewable investment opportunity we have shared with you in complemented by our ongoing energy delivery investment.
So here you can expect to see from us at the upcoming EEI Conference in early November. In addition to the updated 3-year forward cash flow and financing plan, we'll be introducing and sharing the details behind our 2022 Earnings Guidance and our longer-term capital plan, we typically got out 5 years, all of which will incorporate the effects of the announced Kentucky sales. So, with that, surely, we do appreciate your time and attention and I'm going to turn it over to the operator so we can get to your questions.
Thank you. [Operator Instructions] Also please, take up your handset before pressing any buttons. We will go first to the line of Julien Dumoulin Smith. Your line is open. Go ahead, please. I'm sorry. I'm having some technical difficulty, one moment while we open your line. Your line is open. Go ahead, please.
Thank you. Can you hear me now?
Hey you doing and how you?
Hey, quite well. Thank you. Congratulations on the transaction there. Nicely done.
Yeah, I'm angst.
Absolutely. So perhaps just to dive into that one a little bit more, can you talk about what happens with the Mitchell plant here, just as a function of the sale, will it get transferred to Wheeling, how are you thinking about that vis -a - vis liberty, and any kind of pricing there, and in terms of transfer, what have you?
Yes. That's why the operating agreement is being followed. Wheeling would become the operator and it does get transferred to Wheeling in 2028. And so that's really -- we're continuing with Kentucky being half-owner of Mitchell until that period of time. So, the Wheeling will take over the operations of the plant, the employees will move over to wheeling as well. And then we'll continue working with the West Virginia and Kentucky commission to get resolved the operating agreement and related issues.
And then, of course, at the end -- at 2028, it transfers over at fair market value [Indiscernible]. So that's the plan. And that will get followed here in November and December time frame and we'll go through that. And actually, both commissions have the incentive to get this resolved because we do have various views of the ELG piece of it. So regardless of whether we had this transaction or not, we would be needing to fall for the operating agreement change out just because the different directions of the commissions have gone. So, we'll get that resolved as part of process to the overall approvals.
Excellent. Nicely said -- nicely done. Fair market value it is. And then just vis -a - vis, ongoing transactions in portfolio evaluation of really a review with the equity means here in the very near-term, how do you think about just continued evaluation a portfolio? I mean, clearly, it's not necessarily a near-term dynamic, but want to give you the opportunity to speak to that a little bit further.
Yes, sure. I said over and over, I guess for a couple of years now but even beyond that. We do have to get to portfolio management to enable us to look at the sources and uses of the capital needs that we have. And to manage the balance sheet, as Julie has mentioned. We target the mid-teens, and we want to get there, and obviously, we're well on our way of getting there. So, we want to do that, but at the same time, be able to fund the capital growth.
And when you think about it, we've sold the unregulated generation, we sold Rover Rob's, we sold some hydro-related facilities. With Kentucky, we're talking about 6 billion of assets that have been sold, but they fueled substantial growth. I mean, to the tune of 7 billion a year in capital. It's part of the process to determine what the portfolio, needs to be in the future and we will continue to do that.
Certainly, we have Chuck, and Julie, and others will continue to review that portfolio, and we will manage it in a proper way. I'll say this, Kentucky Power, you think about the threshold -- at one point we talked about we always invested in coal units no matter what. And, obviously, we've changed that focus to make sure it's more deliveries of in terms of the decision points that are made. It's quite a move for AEP to get to a point where we're managing our portfolio in a way that, first of all, we became fully regulate, and then we start to look at that portfolio to determine what's the best approach to fuel 20 billion in potential renewables investment.
So, when you think about that, we have to consider it. And I can tell you, the last time we sold a regulated utility was, I guess, the Scranton Pennsylvania System, and then the Pennsylvania -- in Pennsylvania and the New Jersey system back in the 1940s and 50s. So, it's a pretty substantial change. And when you think about Kentucky Power sales, it was one of the first acquisitions of American Gas and Electric in 1922. So, by the time we get through this, it's been 100 years. So, when you think about the threshold level of portfolio management that has occurred in this Company, it really should show a lot on terms of our seriousness of making sure that we're managing that portfolio in the proper way. That's probably longer answer than what you asked for, but I want ed to at least get all that out there.
Very much appreciate it. I'll leave it there. Speak with you guys soon.
Okay.
We'll next go to the line of Shahriar Pourreza with Guggenheim Partners. Go ahead, please.
Good morning, Shahriar.
Good morning, guys and congrats on Kentucky.
Yes.
Just a follow-up on Julien's question a little bit more. As we think about trigger points for another asset sale what's kind of a catalyst because the 10-gigawatts of solar wind that you're looking to build through '25. I mean, even if you assume a 50-50 on PPA structure could yield an incremental $3 billion rate of spending opportunities. And you obviously have a slope of IRP. So do you need to see affirmations with the various filings or actual approvals in GRC. So how should we think about how these could be funded, especially in light of where the stock trades. So, yes.
When you think about the way we're approaching the renewables fees, that the process has been, that we term the need for equity associated with those particular investments, when they actually come online and we get regulated recovery. So, we get the cash flow to support, those investments at the time they come online. That means, obviously our FFO to debt doesn't suffer as a result of that. So, if we continue that approach, and keep in mind too, I've always said that, for us to take a look at a regulated entity or other parts of our portfolio, doesn't match the future needs in terms of, where we are and where we're going as a Company.
Is there, if we have a chronically under-performing part of the portfolio, then it's important for us to take a look at. That may be temporary, it could be long term, but certainly we have to make sure that we're evaluating each one of these assets in a way that says, okay. It doesn't matter where it's located, as long as we're getting certainly the return expectation and also the forward view of the utility is positive as compared to with others. So, we have to compare in various parts of our service territories and that's where we make those decisions.
Perfect. And then just Nick, appreciate we're going to head into EEI we'll get an update here. But do you see the current renewable additions at least through '25 the 10 gigawatts, right, between solar and wind swinging materially with some of these counteractive items like federal policy benefits versus the input cost pressures we're seeing in the space impacting some project timings. So, do you see any of this swinging at all?
Yeah, I do. And in your -- when we'd actually go do the analysis and we've done analysis for all the jurisdictions, but conditions changed, low changes certainly PTCs, ITCs can change as a result, which changed the business cases were some may have been on the margins particularly in the east now become benefits to customers. So, I think those numbers will continue to change and I can tell you from what I've seen so far. Those numbers will change. And some will go out, some will go down. But overall, normally, it should be on path, what we've talked about.
And we'll have more to report on that. Probably during first quarter '22, because we'll have the integrated resource plans. And when those integrated resource plans are filed, that's where I mentioned today is you will have a more definitive view of what those projects look like because there will be the results of RFPs and there will be the results of actual projects that are put in for regulated approval. So, more definition, but I would certainly say that normally they will be in that category we've previously discussed.
And sure. What you should anticipate is when we go to EEI, you'll see a refreshed 5-year forward Capex plan, so '22 through '26, and you'll start to begin to see a little bit more of this renewable opportunity dropped in. So, stay tuned for that, and we'll be able to talk more granularly with you here in a couple of weeks.
Yeah. And I would say that when you see that, it certainly will reflect, I don't know if you call it a risk-adjusted approach or whatever, but it's a nominal view for us to make financing plans, and then just like with North Central, we make decisions on whether it goes up or down based upon our ownership.
Got it. Cheers to you guys. Congrats on the results. See you soon.
Thank you.
We will next go to the line of Steve Fleishman with Wolfe Research. Go ahead, please.
Hey, good morning. Can you hear me, Nick?
Yes. Yes. I hear you.
Okay, great. Thanks. Okay. One question that might be a bit premature, but there's obviously a lot going on in DC with the reconciliation bill and the like, and one of the provisions that's gotten more focused on this few days is the minimum tax provision. And I just be curious, how you're thinking -- for larger companies like yourself, how you're thinking if that has any impact for largely regulated utility like you or does it not really have much of an impact?
Well, I would say, and we've been vocal about this and the industry has been vocal about it, if you put a minimum 15% tax and a lot of us are, as you know, heavy on capital, and its growth capital, and it's also infrastructure-related capital. So, an increase with the minimum tax would certainly have an accruing effect on our ability to continue with not only development of infrastructure and having effect on that, not to mention customers’ bills ultimately because the taxes were passed through to our customers.
But also, the administration has a focus on green energy and it will have an effect on renewables transformation that's existing as well. So, I think I think they'll put a pail over all the utilities’ ability to continue invest in capital in the way that we are. Now, if we do that, then obviously there's customer impact associated with it. And again, it's a hidden tax on our customers. So, we're not for that provision. I think actually, we've been very worthwhile about this and trying to be an honest broker when we're talking about CEBP and all the other things that -- it was important for us to be able to make this transformation from a clean energy standpoint.
Certainly, the PTCs, ITCs with expansion of long-term storage, nuclear, and certainly in terms of wind and solar, are very important to continue those process, to move to clean energy economy, and we can go a long way there. This industry is very focused on doing that, and any kind of tax headwind that goes the other direction is not helpful. I think you probably hear that across-the-board.
Okay. More to direct AP things. Just on the approval for the Kentucky sale, could you remind us what the standard for approval is in Kentucky? Is it just in the public interest or that benefits?
Yes. But it's in the public interest, obviously. Because they have to look at the suitor and determine is that the right route approach. And as I've done in the proper way and actually there has been some discussions in Kentucky previously. I think it's probably gone past some of that now that -- I want to make sure we were operating Kentucky the way we should. And we've been operating it the way we always have.
So, we've been investing, we've been doing the things that we need to do. Whether we owned it or not. And I think certainly the buyer has recognized that and during the transition, we will continue to support a smooth transition to ensure that the services provided and things that need to be done to make Kentucky Power successful, we'll be there to do it. And of course, we'll support Liberty Utilities in Algonquin in doing that.
Great. And then one just quick question maybe for Julie. The proceeds from the Kentucky sale look like they're matching up one for one with reducing the equity need. But obviously when you sell an asset, you lose some cash flow, albeit Kentucky maybe wasn't having the best cash flow. So, are there offsets in other businesses that are making up for the lost cash flow from the asset sale?
Yes, thanks for the question, Steve. You're right. I mean, we do lose the funds from operations that relates to Kentucky and Kentucky Transco. Although, we got to keep in mind that we also eliminate about $1.3 billion of debt associated with those assets to because that goes away. And the marathon that we think through, just to take it a step further is if we avoid issuing equity, we avoid having to cover off additional dividends that were in our original plan.
So, another to a sidestep that as well. And that comes with, maybe also having some additional dollars to reduce debt. As I mentioned in my opening comments, anything above and beyond that $1.4 billion which channeled toward debt reduction that was otherwise planned for 2022. And then also, keep in mind that Kentucky Power had barely strained FFO - to -debt to begin with. So, to eliminate that piece of, I guess, drag to the overall average FFO -to-debt for their organization is also a net positive for us.
So, we are able to put these numbers together. And quite frankly, from an FFO - to -debt perspective, it is mildly beneficial and obviously a little bit of a cost on the debt-to-cap because we're not issuing additional equity. But the numbers all do hang together and coincidentally we'll be able to take literally that $1.4 billion of planned equity out of the plan, and again, you'll see that at EEI when we'll refresh the forecast.
Great. Thanks so much.
Thanks, Steve.
Well let's go to the line of Durgesh Chopra with Evercore ISI. Go ahead, please.
Morning, Durgesh.
Hey, good morning, Nick. Maybe just along the FFO-to-debt lines, my first question is to Julie. In terms of 2024, I'm thinking about your equity needs in my model shift used to target for FFO to debt. Actually, is it mid-teens or is it low to your [Indiscernible]? Because, obviously, that's going to dictate, right, how much equity you might need in 2024. So, any color you could share there?
Got you. You'll see 2024 when we rollout our EEI guidance, so 3 years forward. But, as we continue to say, we are talking about mid - to -low teens. And the reason I say that is, as I mentioned today, if you look at our FFO to debt on an adjusted basis, so backing out the yearly consequence, we have something like 13.6% on a Moody's basis. As you know, our target has been to be around that Baa2 stable rating.
That's why we talk about mid - to -low teens or low - to -mid teens. Obviously, our preference and our expectation are to start to push more towards what I would characterize as mid. It'd be nice to have at least a 14 handle on that FFO to debt, and that is absolutely the plan, but we'll be able to share more with you as we get to EEI and build that forecast, but I wouldn't change how you're thinking about it. So, thinking about mid to low teens as it relates to Moody's BAAT, with a preference towards 14 plus percent.
Got it. So, some of that moment to low teens through 2024 yeah. A big picture question, we've talked in depth about natural gas prices. So maybe just talk about your gas generation portfolio, fuel costs, any hedges in impacting customer bills?
I will take this from a customer rate perspective as I could, because that's how we think about it. Because ultimately this impacts our customers. When we think about, for example, a decent sensitivity analyses around, let's say a 10% hike in natural gas prices as we all know, they've gone up substantially. The impact to customer rates varies significantly from 1 operating Company to the next, depending on the field mix.
So, for example, if I looked at Appalachian Power Company, the average residential impact price in terms of the 10% hiking gas prices would equate to about a 0.9% increase in the customer's rate. Let's compare and contrast that to say PSO or SWEPCO, whether there's much more gas concentration. So PSO, we'd be talking about 1.6% increase in customer rates. SWEPCO, 1.5%. So, this is something we're very sensitive to, because as you know, overall, we're extremely sensitive to customer rate increases and the aggregate as we continue to execute on our general Capex program. I don't know if -- Nick, you had any additional comments.
I'd say certainly, your question actually shows the reinforcement of our renewable’s transformation because it's a perfect edge to natural gas of North Central were in place during the time of storm Yuri. It would have saved customers $225 million. So, when you think about the process we're going through, it's great to have natural gas it's -- and certainly -- but at the times where you can layer in renewables to do that, it turns out to be a significant benefit to consumers. So, it reinforces that. And I think probably this winter will show it.
Understood. Thanks, guys. I appreciate the time.
Thank you.
We'll next go to the line of Andrew Weisel with Deutsche Bank. Go ahead, please.
Good morning, Andrew.
Hey, good morning. Thanks for a lot of good updates here. One remaining question I had was after a few rate case settlements and expectations for several other outstanding cases to be resolved in the coming months, can you share your expectations around which sub we might file new rate cases over the next 12 months or so?
We are -- I'm trying to think of what else will you be filling because just down here with jurisdiction we got a case that we expect approval of and certainly a lot of cases they're still ongoing and just about all the jurisdictions. So, I'd say we're always reviewing that on a regular basis at this point. We are playing with active cases that we got to get across the finish line and then determine where we are at.
The other part here is looking at what happens with denominator because Julie mentioned, low is changing significantly and it continues to do that as we emerge from hopefully a post-COVID world. And if that's the case, then that would be a determinant in terms of when we would file for any case. I think, of course, if we do have tax changes that occur, then that'll force a whole new view going forward to many of these cases. Just like it did when we got tax reform last time around, except this one, maybe, on the upside.
Okay, great. So, would it be fair to say that '22 at least the other second half of '22 might be a quieter year as far as the regulatory calendar than what we currently have?
Probably quieter in terms of filings, but probably noisy in terms of results.
Alright. Thank you very much.
[Operator Instructions] We will go on next, one, please. We'll go next to the line of Michael Lapides with Goldman Sachs. Go ahead, please.
My name [Indiscernible] I'm fine. Rough year for your -- by you being goals this year. A lot of change. Hey, got a couple of questions for you. What the Kentucky sale and you guys have -- your slide number five. I think it says, over the years has done a good job of detailing how hard it's been on authorized in Kentucky.
Now that Kentucky will be offshore play, when you look at the other jurisdictions, what are the ones that we say, hey, we still struggle to own authorize here? What are the structural changes? Whether it's legislation and we've seen lots of utilities in places like North Carolina, Kansas, Missouri, go in and make structural changes via legislation. What are the structural changes you are going to seek, outside of just normal rate case filings, that could help improve authorized versus [Indiscernible] in those jurisdictions.
You're seeing a fundamental shift and all the remaining operating companies. We made a lot of progress on Ryder's and we have a lot of focus on getting concurrent recovery in cash in the door and what you're seeing really in terms of a lot of these lags, is the amount of investment that we're placing in these companies. But as well as you make the transition from certainly from wires related activities with Ryder's and then the renewables conversion that occurs, the way we're doing the renewables is commensurate with the recovery.
So, we should see the authorized -- our returns be closer to the authorized as time goes forward. We don't see any fundamental issues in any of the jurisdictions that are left that says that we have significant headwinds. I mean, the only thing you could probably point to is the Turk issue at SWEPCO, but other than that -- and actually, when you think about Arkansas, we keep saying we're not recovering the Arkansas portion of the Turk. That's not because of the commission. That is because of the Supreme Court of Arkansas.
So, we've got very good relations with the commissions and all the jurisdictions, and we feel like the fundamentals are there for continued improvement relative to that regulatory lag that exists. And because we're spending on more areas and our generation is really renewables, and that's helping out, every time we put an investment in, and the timing of the investment improves the FFO-to-debt, improves the returns of the individual companies. And I think we'll continue to make progress in that regard. So, I would be -- I'm pretty optimistic that we'll continue to make progress in all of these jurisdictions.
Got it. And just a quick follow-up, and just maybe a Julie one. Just curious when we think about your multi-year -- your guidance growth rate and the language around wanting to be at the high end, outside of the transmission segment, the standalone segment, what does that embed as an earned ROE at the rest of the regulated businesses?
Michael, we always -- as Nick mentioned, we strive to be in the upper half of the guidance range, not necessary the upper end, although that 'd be very nice. So just a point of clarification there. And as it relates to returns, as you can see, we've kind of been hovering around the 9% ROE return level. I think that's a safe place for you to assume that we'll kind of hang out there for a while until we get a little more traction.
And the other thing if I could, circling back to your original question, when we look at the equalizer chart, often times we get questions around AEP taxes and why the lower [Indiscernible] we relative to authorize there, and so back to your question around growth and how do you manage the business, AEP Texas, we continue to invest a significant amount of capital on an annualized basis.
And while we have very progressive rate recovery mechanisms in place that we really enjoy, I can tell you this, while the ROE may look a touch depressed relative to authorize, that Company continues to produce earnings growth and to save the 8% to 10% range. So that certifies our ability, back to your original point, getting that upper 1/2 of the range. So again, ROE, our system-wide average, assume roughly around 9% - ish and trending upward over time. And then around AEP Texas, k keeps in mind, the capital is intentional there as we continue to try to take care of the customer and grow that business. And it's paying dividends in 8% to 10% EPS growth out of it.
And another thing if we look at is, we haven't gone that pages is actually the increase in equity layers as well. So, you see improvement in the equity layers and then, we're still investing and still meeting the 5% to 7% and being the upper half and that kind of thing. And of course, we continue to manage the FFO to debt towards the mid-teens. So that -- all of the pieces are starting to fit together. And there's a lot of optimization that will occur for us to -- how to execute on to ensure that we're continuing to meet the earnings objectives. But at the same time investing in the right things and enable us to bridge that gap on the regulatory lag.
Got it. Thank you, guys. Much appreciated. Congrats to have Kentucky.
Yeah. Sure thing.
Thanks.
All right. Speakers, we have no one else in queue at this time.
Thank you for joining us on today's call. As always, the IR team will be available to answer any additional questions you may have. Allen, would you please give the replay information?
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