Our strongest ever Q4 . We are maintaining that momentum and delivering strong results for the Q1 of 2022, with operating earnings for the Q1 coming in at $1.22 per share or $616 million. Earlier this year, we made a number of refinements to our strategic initiatives and financial targets. We raised our 2022 operating earnings guidance range and increased our long-term earnings growth rate, and we have hit the ground running in 2022. Today, we are reaffirming our 2022 full-year operating earnings guidance. As a reminder, we are guiding to a range of $4.70-$5.07 dollars per share for 2022 with a $4.97 midpoint. We also reaffirm our long-term earnings growth rate of 6%-7%.
As you'll recall, we announced several significant developments in connection with last quarter's earnings. In addition to lifting our 14%-15% FFO to debt targeted range, we announced the decision to sell all or a portion of contracted renewable assets within the unregulated business. The announcement of this strategic divestiture allowed us to recalibrate our five-year capital plan of $38 billion, with a $1.5 billion shift to transmission and the elimination of growth capital in the contracted renewables business. We are already seeing the positive impacts of these initiatives in quarter one, and we look forward to continue to execute in these important areas throughout the course of the year. We also expect to maintain positive momentum in our economic outlook as we work collaboratively with states to drive economic expansion in our service territory.
There's more to come on all that, but I first wanna take a step back and highlight some of the other proactive work our team has done. As macro trends continue to affect our industry and the economic landscape at large, we are focused on de-risking our platform and elevating our strategy to enhance shareholder value. For example, given lingering global supply chain issues, we are diversifying our mix of suppliers in order to reduce the impact on our capital investment plan. As a result, AEP has experienced minimal customer or business disruptions to date. With these significant initiatives underway and a track record of thinking creatively, it is truly a team effort, and we are lucky to have one of the most talented teams in the business.
Regarding Kentucky, we expect to complete the sale of Kentucky Power and AEP Kentucky Transco to Liberty in the Q2 of this year. A regulatory timeline of the sale is on slide 7 of today's presentation. In 2021, we announced a comprehensive strategic review of our Kentucky operations, resulting in an agreement to sell those assets for $2.846 billion enterprise value. Both parties have been steadily working to obtain the necessary approvals to complete this transaction, which is in the public interest. The Kentucky Public Service Commission hearing was held on March 28th and March 29th. We know that Liberty is well-positioned to serve Kentucky customers and are confident our employees in Kentucky will continue to thrive within an organization that prioritizes safety and operational excellence.
Based on the statutory requirements, we continue to expect to receive a decision from the commission on the sale transfer no later than May 4. FERC approval on the sale transfer is also in process. Earlier this week, FERC notified us of a need for more information in the 203 transfer application. This request is not unusual as FERC looks to ensure its record is complete by seeking additional information. We do not believe this request will impact the closing of the deal in the Q2 . Once a decision is made by the state level next week, we will provide the requested information back to FERC. We'll plan to ask FERC to abide by the original approval timeline to ensure Kentucky customers receive benefits from this transaction in a timely manner.
Another significant regulatory milestone for the transaction is gaining approvals on the Mitchell operating agreement, which are a condition of the final sale transfer. Both Kentucky and West Virginia are aware that updated Mitchell operating agreement approvals are needed to put in place the commission orders on environmental compliance issued in 2021. The Kentucky Public Service Commission hearings were held on March 1 and March 30, and the Public Service Commission of West Virginia was held on April 7. Parties providing options allowing flexibility for both states to collaborate and reach a common agreement as Kentucky continues to wind down interest in Mitchell Plant post 2028. We expect to receive commission decisions on the Mitchell agreements on an expedited basis in May of this year. We plan to file the related FERC application after state commission approvals.
Throughout this process, we have established a strong record of benefits of this transaction, most notably the clear and measurable customer benefits that we see. Okay, now moving on to the contracted renewable asset sale. During our Q4 earnings call in February, we announced the decision to sell all or a portion of our unregulated contracted renewables portfolio to simplify and de-risk the company and allow us to focus on our regulated business. Our portfolio consists of 600 megawatts of unregulated contracted renewables, the sale of which will help facilitate the investment of 16,000 megawatts of regulated renewables through 2030. In the last couple of months, we have made significant progress on this opportunity, including working with an advisor, preparing outside consultant reviews of the technical and market aspects of our portfolio, and evaluating our sales strategy and timing.
Interest in the sale of the portfolio has been robust. The sale provides a unique opportunity to acquire a large operating wind portfolio complemented with some solar operations as well. We expect to launch the sales process sometime during the H2 of 2022, likely in the August-September time frame, and can be accelerated or de-accelerated as needed. Additionally, we are pleased to announce we have signed a term sheet to sell most of our wind and solar development portfolio, including five sites which are located in Southwest Power Pool. We have also executed an agreement to sell a solar development site here in Ohio. Financial details of these upcoming sales are confidential and will not be disclosed, but demonstrate our commitment toward that execution.
The reallocation of contracted renewables capital is assumed in our guidance, but utilization of proceeds is not yet reflected in guidance or our multiyear financing plan. We will seek to maximize transaction proceeds in the sale, avoid dilution, and direct the proceeds to investments in our regulated business as we continue to enhance the transmission infrastructure and move forward with our generation fleet transformation. Looking ahead, we will continue our track record of optimizing the portfolio and reallocating capital to our regulated business, where we continue to see a meaningful long-term opportunity for growth. AEP is making significant progress as well in our transition to a clean energy future. In fact, we already have several initiatives underway in line with our sustainability goals and through our regulated renewables execution. Details can be seen on slides eight and nine.
In March, we commissioned our third and final North Central wind site, Traverse Wind Energy Center, which is the largest single wind farm built at one time in North America and one of the largest wind facilities worldwide, completing the $2 billion trifecta investment that includes Sundance and the Maverick Wind Energy Centers. Combined, they are providing 1,484 megawatts of clean energy to our customers in Arkansas, Louisiana, and Oklahoma. North Central will save customers an estimated $3 billion in electricity costs over the next thirty years. In March, we also issued a request for proposal at I&M for 800 megawatts of wind and 500 megawatts of solar. Additional RFPs are in process simultaneously at APCo, PSO, and SWEPCo, with expected in-service dates of 2024-2025.
We expect to make a regulatory filing in the Q2 of this year related to the SWEPCO's June 2021 RFP. These are long-term investments, not just for our business and our local communities, but for the global environment as well. Through our current state of coal retirements, we are progressing towards our target of an 80% carbon emissions reduction rate by 2030 and net zero by 2050. Achieving this goal is an integral part of our long-term strategy to prioritize regulated investment opportunities and transition our generation portfolio. Our plans are very well thought out, continue the movement to a clean energy economy, but remain firmly grounded in the principles of resiliency, reliability, and affordability while recognizing the value of diverse portfolio of resources, particularly given today's world of energy-related volatility.
Last year, we set regulatory foundations in a series of rate cases across multiple jurisdictions. Regulated ROE as of March 31st, 2022, is at a steady 9.2% as we continue to work through regulatory cases and focus on reducing authorized versus actual ROE spreads. I&M obtained commission approval in February on our Indiana base case settlement. Oral arguments of APCo's 2020 Virginia base case appeal were held in March at the Supreme Court of Virginia with an anticipated final decision this year. We expect to see commission decisions as well on SWEPCO's rate cases this year in both Arkansas and Louisiana, and look forward to keeping you informed on that progress, too. Related to FERC, we commend the commission for moving forward with proposed reforms to transmission planning and cost allocation.
FERC's proposed rulemaking aligns with our goals of developing a more robust, reliable, and flexible grid of the future that ultimately reduces costs to customers and strengthens economic development in the communities in which we serve. We believe many of these reforms are needed to build the infrastructure necessary to transition our generation fleet in the most efficient and cost-effective way possible and achieve our carbon reduction goals. We look forward to continuing to work collaboratively with the commission on this and any subsequent rulemakings and with the RTOs on implementing any new requirements. At the conclusion of our Q4 call, I told you all that AEP stood poised to make even greater headway in 2022, and I think it's fair to say we are making good on that promise.
Capitalizing on our momentum from 2021, we have continued to execute against our strategic objectives steadily and successfully. As we think about what's next for this year and beyond, we hope to further modernize our energy grid in order to supply reliable, cleaner, low-cost resources for all the communities we serve. We will also consider further asset rotation through the lens of de-risking and simplification, and we'll evaluate any and all value-added potential activities as we focus on our regulated business. As I've said before, AEP is in a very unique position. The largest transmission system, one of the largest renewables build-outs, and a diverse territory to adjust from the risk of supply chain, load forecast, regulatory risks, et cetera. AEP is the very definition of consistency and opportunity.
We at AEP, as well as our shareholders and customers, hold ourselves accountable on the continual execution of all of these strategic objectives. To paraphrase a big hit by The Police, every breath you take, every move you make, every step you take, we'll be watching AEP. As our CFO would say, we've got this. Julie?
Thank you, Nick. Thanks, Darcy. It's good to be with you this morning. Thanks for dialing in, everyone. I'm gonna walk us through our Q1 results, share some updates on our service territory load, and finish with commentary on our credit metrics, liquidity, as well as some thoughts on our guidance, financial targets, and recap our current portfolio management activities underway. Let's go to slide 10, which shows a comparison of GAAP to operating earnings for the quarter. GAAP earnings for the Q1 were $1.41 per share compared to $1.16 per share in 2021. There's a reconciliation of GAAP to operating earnings on page 16 of the presentation today. Let's walk through our quarterly operating earnings performance by segment on slide 11.
Operating earnings for the Q1 totaled $1.22 per share, or $616 million compared to $1.15 per share, or $571 million in 2021. Operating earnings for the vertically integrated utilities were $0.59 per share, up $0.05. Favorable drivers included rate changes across multiple jurisdictions, normalized load, and O&M. These were somewhat offset by increased depreciation, lower off-system sales, and wholesale load. I'd like to take a second to talk about O&M and depreciation in particular. Because of a change in accounting related to Rockport Unit Two lease at I&M, we'll see approximately a $0.05 contribution of favorable O&M, consequent offset by $0.05 of unfavorable depreciation in each quarter of 2022, but no consequential earnings impact.
To be clear, this is entirely consistent with the 2022 guidance details we posted in our investor presentations earlier this year. I'll have more to share on load and load performance here in a minute, so hang with me on this. The transmission and distribution utilities segment earned $0.30 per share, up $0.07 compared to last year. Favorable drivers in this segment included rate changes in Texas and Ohio, normalized load and transmission revenue. Offsetting these favorable items were unfavorable O&M and depreciation. The AEP Transmission Holdco segment contributed $0.34 per share, down $0.01 compared to last year. Investment growth was favorable by $0.03, offset by $0.02 of mainly property taxes driven by the increased investment and $0.01 of income taxes. This is in line with the guidance that we provided to you earlier this year.
You'll recall that our 2022 guidance had this segment down $0.08 year-over-year as a result of the $0.12 of investment growth being more than offset by the annual true-up that will occur in the Q2 and some unfavorable comparisons on the tax and financing side. As you know, this segment continues to be an important part of our 6%-7% EPS growth. Generation and marketing produced $0.03 per share, down $0.03 from last year. The improvement in wholesale margins was more than offset by lower retail margins and reduced generation. You may recall that Winter Storm Uri had an unfavorable impact on wholesale margins in the Q1 of 2021. Finally, corporate and other was down $0.01 per share, driven by increased O&M, lower investment gains, and unfavorable interest. These were offset by favorable income taxes.
The lower investment gains are largely related to ChargePoint gains that we had in the Q1 of 2021. Turning to slide 12, I'll provide an update on our normalized load performance for the quarter. In a general sense, the AEP service territory is extremely fertile for economic growth right now. In fact, as of the Q1 , our load has officially fully recovered from the pandemic recession and has now transitioned into the expansionary phase of this business cycle. Starting in the upper left corner, normalized residential sales increased by 0.8% compared to the Q1 of 2021.
This growth was composed of growth in both customer counts and weather-normalized usage for the quarter. While results were mixed by operating company, the strongest residential growth was in the AEP service, AEP Texas service territory, which was partially influenced by the year-over-year comparison, given the customer outages driven by Storm Uri in the Q1 of 2021. A final data point to share regarding residential sales is that our Q1 sales were still 1.1% above their pre-pandemic levels over two years after the pandemic began. This is driven by a number of factors, including higher numbers of people who are able to work remotely that used to work in offices prior to the pandemic. Moving to the right, weather-normalized commercial sales increased by 4.2% compared to the Q1 of 2021.
While growth in commercial sales is spread across every operating company in most industries, the largest increase in commercial sales is coming from data centers, whose load was up 33% compared to last year. In addition, we continue to see strong recovery in the sectors most impacted by the pandemic, such as hotels, schools and churches. While real estate has been booming throughout the entire pandemic. AP's normalized commercial sales in the Q1 were 2.5% above their pre-pandemic levels, which shows that we've gone beyond recovery and are now in full expansion mode across the territory. If I can now focus your attention on the lower left corner, you'll see that industrial sales posted another very strong quarter, up 5.6% compared to last year.
Industrial sales were up at most operating companies in many of our largest sectors in the Q1 . We experienced double-digit growth in a number of key industries this quarter, including chemicals manufacturing, oil and gas extraction, petroleum and petroleum products. We also saw robust growth in primary metals manufacturing, coal mining, and food manufacturing. Having said that, Q1 industrial sales are still 1.6% behind their pre-pandemic levels. However, we have a large number of customer expansions that are expected to come online later this year and still fully expect to eclipse our pre-COVID industrial sales levels in 2022. We continue to be confident in our full year 2022 guidance for normalized retail load.
While we certainly did not anticipate the Russian invasion in Ukraine when we developed the 2022 forecast, I'd like to remind you that AEP's service territory is uniquely positioned to benefit from higher energy prices, given the concentration of energy production that is located throughout the AEP footprint. Energy producers in our footprint have responded to higher energy prices, which has resulted in increased economic activity throughout the service territory. Finally, when you pull it all together in the lower right corner, you'll see that AEP's normalized retail sales increased by 3.2% for the quarter. As I mentioned earlier, our load has gone beyond recovery mode and is in full expansion mode. For the quarter, every operating company posted higher normalized sales than last year.
Furthermore, our Q1 retail sales were up 0.5% above their pre-pandemic level, so 50 basis points above pre-pandemic levels. To use a sports analogy, I would say our load performance in the Q1 was in the zone. There are many factors outside of our control that could influence our results. I want to stress that the positive load story we shared with you today is largely the result of intentional efforts by our employees to promote economic development as a part of our long-term strategy to strengthen the communities that we serve. We're fully aware of the increased uncertainty that exists in the macro economy, but have put in the work that it takes to ensure that we continue to see growth in our service territory going forward. Let's go over to page 13 to check on the company's capitalization and liquidity position.
On a GAAP basis, our debt-to-cap ratio increased 60 basis points from the prior quarter to 61.5%, primarily due to an increase in equity from our issuance of AEP common stock in March, which is consistent with our 2022 guidance as the $805 million dollar, or the $805 million dollars of equity units we issued three years ago converted to equity. Let's talk about our FFO to debt metric. Taking a look at the upper right quadrant on this page, you'll see our FFO to debt metric stands at 13.7% on both a Moody's and a GAAP basis, which is an increase of 3.8% and 3.9% respectively from the prior quarter.
The metrics are calculated off of the 12-month rolling FFO total, so the increase in FFO to debt is mainly a result of the fact that the cash flow drag from February 2021 Winter Storm Uri has now dropped off the cash flow from operations calculations. This improvement has significantly narrowed the gap toward achieving our FFO to debt target range of 14%-15%. As we stated on the last earnings call, we anticipate trending toward this target range as the year progresses. Let's take a quick moment to visit our liquidity summary on the lower right side of slide 13. Our five-year $4.4 billion bank revolver and two-year $1 billion revolving credit facility support our liquidity position, which remains strong at $3.8 billion.
Switching gears, our qualified pension funding increased 1.6% during the quarter to 106.4%. The rise in interest rates that decreased plan liabilities was a primary driver for this quarter's gain in funded status. Let's go to slide 14. This quarter has provided a solid foundation for the rest of 2022, and we're reaffirming our operating earnings guidance range of $4.87 per share-$5.07 per share. We continue to be committed to our long-term growth rate of 6%-7% that we updated on our last earnings call. We're working through the Kentucky Power sale to Liberty and expect to close in the Q2 .
as Nick mentioned, we've signed an agreement to sell a solar development site in Ohio and have entered into a term sheet to sell five additional wind and solar sites in SPP on the unregulated side of the business. Additionally, we're preparing to market the unregulated contracted renewables portfolio in the H2 of this year and are receiving a significant amount of interest on this.
Beyond the portfolio optimization activities underway, we remain focused on the fundamentals, which are executing on the regulated renewables plan, disciplined capital allocation, and securing positive regulatory outcomes. Before we break, I want to mention one last thing, before we get to your questions, and that's to remind everyone that while we have not yet set the date, we will be hosting an investor conference sometime in late September or early fall timeframe to give you a broader AEP update. We surely do appreciate your time and attention today. With that, I'm going to ask the operator to open the call so we can hear what's on your mind and answer the questions that you have.
Certainly. Ladies and gentlemen, if you wish to ask a question, please press one, then zero on your telephone keypad. You may withdraw your question at any time by repeating the one zero command. If you are using a speakerphone, please pick up the handset before pressing the numbers. Once again, if you have a question, you may press one, then zero at this time. It'll be one moment for our first question. Comes from Julien Dumoulin-Smith at Bank of America. Please go ahead.
Morning, Julien.
Hey, good morning, team. Thanks for setting a lot to talk about today.
Yeah.
Congrats. Talk about it. Take your pick. Maybe let's start with this. Just in terms of the timing on the renewable sale here, can you talk a little bit about how the AD/CVDs could impact that? I mean, is that one on just your sense of the ability to get it done? Just any comments on that and/or implications? Again, I assume minimum. Separately and related, how do you think about the timing of proceeds here? Admittedly, this is a little bit faster than what we were, we had perceived. Just, you know, the proceeds from Liberty and this coming in, perhaps a little bit faster than perhaps the equity issuances in your forward plan, whether or not I suggest.
Yeah, Julien. Most of our assets are wind assets. As we go forward with the transactions, we don't see any issues with that. As a matter of fact, even on the regulated side, the timing of which we actually need assets for solar and that kind of thing, comes later. It's a 2024-2025 time frame. On both sides of the ledger, we're in good shape from that perspective. These assets, obviously, we're going to try to time it appropriately. As we talked about, the large portion of the 1.6 gigawatts or the 1,600 megawatts, they will be marketed the Q3 .
I'd say, you know, we're getting very robust. I mean, it's very robust interest on both sides, strategics and in terms of any type of private equity, that kind of thing. It's really throughout the process, we're continuing. There's nothing stopping us. We're in good shape from that perspective. Your second part of your question. Julie, did you have that part?
Julien, let me know if I'm not answering this directly, or if you need a little more granularity, specifically as it relates to dollar flows associated with any type of transaction that we enter into. Today, you heard us talk about the fact that we have a term sheet in place for five development sites. Those dollars are real small. We'll see those show up eventually, probably Q2 or Q3 in operating earnings, but obviously not even disclosing those, not a needle mover for us. We're not going to change the earnings guidance or anything like that, so not to worry on that front.
As it relates specifically to the broader unregulated renewables contracted portfolio, you know, we'll start the marketing effort in the H2 of this year. Obviously, we'll come to you as we have a little more detail to share. You know, we do have an upcoming investor conference, so stay tuned for that. We'll be able to navigate any you know, potential you know, proceeds from transactions. As you know, we don't even know exactly how that's ultimately going to look. Do we sell them as an entire portfolio? Do we sell them in different pieces? That's to be determined. Stand by on that. You know, obviously, we continue to work through the Kentucky process.
We had expected to close that, you know, or we're trending towards the Q2 . As Nick mentioned, and I mentioned in my opening remarks, that's already reflected as it relates to Kentucky, you know, bringing dollars in our plan. You may recall that we eliminated about $1.4 billion of equity that we originally had in our 2022 guidance. I think we're moving on track. Let me know if there's something I didn't address there.
Yeah. Since we're really moving on the universal scale assets, they're project-specific, so we can go through that process and time it any way that we wish to do it. That's actually pretty quickly. We'll go through that process, and we'll define that better, and that'll probably be part of our Analyst Day discussion.
Speaking of analyst day discussion, just super quick, if I can, an important point. How do you think about just approaching your customers directly, elevated energy price environment, doing well on industrials and C&I sales growth? Presumably, your customers are interested. We heard this from Entergy. Can you perhaps elaborate how you're thinking about that opportunity here in this elevated environment as a further angle to your renewable aspiration?
Well, certainly, the renewables are a key part of being able to really mitigate costs to consumers going forward. From an industrial standpoint and manufacturing standpoint, we're going to see a lot of that movement to our territory because when you think about onshoring, when you think about strategic reviews of supply chain actions that need to occur within this country, that's gonna occur within our territory. Our focus will be, and I think, from the renewable side, particularly the regulated renewable side, to be able to continue to progress on that is a benefit because a clear benefit for customers and certainly North Central showed that. I think from an industrial standpoint, it's gonna look very good for us. We have the resources for capacity.
When you layer in the renewables for the incremental needs of capacity, it's really the best of both worlds to provide a reliable, secure supply to our industrials and really at a competitive price. I think we're in great shape from that perspective going forward.
Thanks, Steve. Good luck. See you soon.
Yep, sure thing.
Next, we'll go to Steve Fleishman with Wolfe Research.
Morning, Steve.
Hey, Nick. Good morning. Can you hear me okay?
You sound enthusiastic.
No, that is enthusiastic for me. Sorry.
Yeah.
I think it's as enthusiastic as Julien Dumoulin-Smith is. Just on the Kentucky process, there does seem to be a decent amount of people that want different things on the Mitchell operating agreement process.
Mm-hmm. Mm-hmm.
Can you just talk to your confidence in resolving those issues by the Q2 ? Just maybe frame some of the issues and how you think they can get resolved.
Yeah. You know, obviously, there's been a lot of focus on the Mitchell agreements themselves. We've certainly tried to accommodate the multiple parties that are involved and made it as flexible as possible. Obviously, the issue is 2028 and how you reconcile that going forward. From a state perspective, I think we're in a good place because it does provide the flexibility to find whatever value proposition there is at that point. There also is optionality around the ability to potentially separate the units to allow each individual commission to make their own decisions relative to these units. I think it's positioned very well. There's been a lot of dialogue, lots of settlement discussions associated with that.
Of course, there's a lot of varied opinions. At the end of the day, we have to do this because we have two commissions that are going different directions relative to the life of the Mitchell plant. I think what we've arrived to is a very credible balanced view that allows the optionality that you know that the parties need going forward. Of course, you know, we certainly will continue to focus on the ELG and CCR expense associated with that in the appropriate manner. That'll improve the optionality going forward to where decisions can be made at the appropriate time.
I would say we're in a good place, and we expect the Mitchell approvals to occur very quickly after the transaction approval.
Okay, great. Thank you.
Yep.
Just, you've been pretty good and right about the federal BBB legislation kind of to get done or whatever you wanna call it these days.
Yeah.
Curious if you have any latest thoughts and updates there?
Yeah.
if anything changed.
I'll say this. Now, certainly Senator Manchin is at the center of all this, but there also is, I think from the original infrastructure package, a group of senators who are coming together to try to focus on some pretty substantial issues. Really when you think about, you know, Senator Manchin being on both the Armed Services Committee and the Energy Committee and knowing the Ukraine situation and the focus on energy as it relates to it, I think you're gonna see at least an attempt at a lot of focus on how to support natural gas, LNG, expansion for pipeline capability. Then, of course, he's also talked about the climate provisions.
You know, I think there'll be a lot of interest, too, in the technologies of the hydrogen hubs and particularly in West Virginia. You know, there's obviously Murkowski, Barrasso, there's others that are engaging in that discussion. The ITCs, PTCs, the climate provisions that the industry is looking for, I think there's some bipartisan level of support for that. The question really is can they get together before really before Memorial Day? If they're still talking after Memorial Day, it's probably a positive indication.
My own, you know, personal belief is, you know, if it's not successful, we'll probably see an eleventh hour type of at the end of the year relative to ITCs and PTCs and perhaps even expansion of those. I think you'll see an attempt at a smaller bill. You know, you'll still get hung up with the, you know, the pay-fors, particularly with Manchin wanting to get it paid for. Sinema is obviously a different view on that. But there's probably some element of recognition that something has to be done to have this country focus on the security of supply, not only for ourselves, that the Ukraine situation has demonstrated, but also for Europe and the rest of the world.
That's probably the impetus of getting something done. It'll define the framework of whether something gets done or not. If it doesn't, after the election, I think, like I said, it's eleventh hour or perhaps the IRS and Treasury make adjustments based upon what's happened relative to supply chain activities. I think that would be my view of where things are going.
Great. That's super helpful. Thank you.
Yep.
Next, we will go to Shahriar Pourreza with Guggenheim Securities. Please go ahead.
Hey, good morning.
Good morning.
I just, Nick, I just want a question on sort of the renewable comments. As we're looking kind of at your current RFPs that are in progress, there's sort of a fairly healthy mix between wind and solar and storage. As we're thinking about kind of the upcoming 2021, 2022 RFPs, how are you sort of thinking about the potential, you know, tail risks around solar with circumvention investigation? There's pricing uncertainties.
Yeah.
There's supply constraints. I guess, how does tail risk impact the mix for 2021 and 2022? And do you see any risk to the $8.2 billion you've allocated to renewables? I mean, we've already seen two peers provide some warnings around this, and one this morning as well as delays. So I'm just kind of curious how this fits in with your plan.
Yeah, you know, I don't see a lot of risk. The reason why is because ours is more, you know, to 2030. A lot of these projects will come into play in the 2024-2025 timeframe. We have time for not only the reviews of solar that's occurring with the administration, but also in terms of the supply chain activities to level out somewhat before we're actually back in the market, you know, acquiring these types of resources. We have a little bit of time. I think probably about Q1 next year we want to see things start to levelize so that we can get that process rolling.
In the meantime, we got the resource planning filings that are being made. Keep in mind, too, I made this point originally, these plans, you know, are really fungible from year to year based upon what we see in terms of the value proposition of each type of resources. So a lot of it's wind, some of it's solar. Solar picks up in the later years from a resource plan perspective, so there's time for the solar thing to get resolved. But even if it doesn't, that says there's probably gonna be more wind or other types of resources that are put in place to support these objectives. Because remember, they're driven by capacity requirements. We'll continue to evaluate that process.
I'll take a step further, too, on this. We've always said that if something were to happen, well, relative to the renewables build-out, we've got transmission. Transmission, we can soak up a lot of capital from that perspective, because of the focus on providing better customer service, more resilient, reliable grid. We have that optionality. But I'm not even there yet. I think we're 'cause, you know, the $8.2 billion we have in there assumes a certain percentage of those types of resources that we would own. That could be higher. Transmission could be higher. We have optionality around all of that. I'm not concerned from an AEP perspective.
Yeah, for sure the current gas price environment helps the economic argument.
Absolutely. Because the $3 billion for North Central was done on a previous gas forecast. If you looked at that today, it's probably much larger. I think it's really looking good for customers.
Got it. Nick, just from a financing perspective, as we're thinking about incremental spending that's gonna come from these future RFPs, can you just be a little bit more specific on your prepared comments around further asset sales? I mean, you like all your OPCOs that remain. I guess, what could a structure look like? What remains?
Yeah. The point I'm making is obviously we're going through the process step-by-step with the unregulated, contracted renewables part. There's different parts of that business. Of course, just, I think Kentucky was the first shot at it. There's a lot of optimization that can occur. We'll just have to evaluate against what the opportunities look like. If we have, I mean, if we have underperforming utilities that don't figure profitably into the clean energy transformation, where we're actually attracting capital and being able to provide higher levels of return, then, you know, we have to look at it. I'm just saying that process will continue regardless.
Not saying, you know, actually we're already too deep. I thought about the number too deep. In terms of sales, Kentucky, we still have to get across. Then, the contract of renewables, we still get across. Then we'll see where we're at that point based upon what we're getting in terms of the feedback of the RFPs. Because when these RFPs ultimately get approved, we'll know exactly what the ownership looks like, what the financial requirements are, and we'll do what we've always done.
We'll make sure that we're going through this process to invest in the right places. We will look at the portfolio and see what makes sense and what doesn't make sense for us to continue to optimize that for shareholder benefit.
Just one quick follow-up from Steve's question is, you know, obviously, we appreciate the confidence around the operating agreement and the Kentucky sale and reiterating the timing of the deal. But just to bookend it, assuming there's maybe an adverse ruling or something that's not palatable, can you just remind us, Nick, does Algonquin have a material adverse change clause? Is there a timeframe when they could walk away from the deal? As we're just thinking about a bookend.
You know, it's typical to have those kinds of provisions in that kind of agreement. But I can tell you that we and Algonquin are arm in arm getting this thing across the finish line. They very much want to own this property, and they've actually stepped up in a considerable way to provide customer benefits to make this transaction attractive to the policymakers and to our customers. Of course, you know, I think a seminal event here obviously is May 4th, where the commission will come out with an order. We will look at that order. We'll make determinations on what conditions are in place. At that point, Tom will make decisions on what it looks like.
I think from the public interest standpoint, the things that the commission ought to be looking at, this transaction is very good for Kentucky customers. I think everyone has to be sort of level-headed about all this because when you get through this process, you actually have a timeframe now for customer benefits to occur, substantial benefits. That's really a driver to get this thing done as quickly as possible, particularly in this energy-related environment. I really don't anticipate that happening, but if it did, we'll do what we always do. We'll figure out what the options are and what the possibilities are and go from there. Right now, we're not planning on that.
Terrific. Thank you, guys. Congrats on the results. Appreciate it.
Yeah, sure thing.
Next, we'll go to the line of Jeremy Tonet with JP Morgan.
Morning, Jeremy.
Hi, good morning.
Morning.
Just wanted to pivot a little bit towards transmission here. Given the MISO planning, maybe a little bit outside of your guys' footprint, but also, as you mentioned, the FERC transmission planning and AEP stepping up CapEx towards transmission here. Just wondering if you could dive in a little bit more as far as which specific areas, projects might materialize or any other color you could provide on specific transmission opportunities incremental at this point.
Well, typically, we've done this. We actually plan for around 130% of the budget for transmission. We have 30% more projects that are occurring that we already have planned, scoped, ready to go. Layering in these multiple projects is a way for us to not only, as opportunities arrive, as the metrics for financials continue to improve, we can layer in more of that. We can adjust to that based on projects that go one way or another. Then also, you know, recently we were awarded a large project in Texas that's also incremental. It was like $1.3 billion or so.
Those are the kinds of things that will come to pass. We have every bit of opportunity related to transmission, not only within our own system, but also in terms of the incremental systems around us. You asked about FERC and transmission. FERC obviously is taking the right step relative to long-term planning, getting the framework for long-term planning put in place. That's an important part of the process to speed up some of the planning aspects to ensure that we are making the right investments at the right places.
We continue, and I think FERC will continue to look at, even in parallel, these issues of cost allocation, of even the incentive mechanism, but also in terms of interregional planning, which AEP will bode well in terms of that, because just about everyone interfaces with us. So, as you look at some of these aspects, the more renewables that are needed, certainly the more retirements that are occurring across RTOs is also gonna bode well for transmission investment. We, you know, what we see today is not what we're gonna see tomorrow. If FERC is doing the right thing, which we think they are, it's gonna bolster the ability for us to have a more consistent, congruent clean energy-type system across this nation.
You can't do that without AEP.
Got it. Thank you for that. Just shifting gears towards O&M. Just wondering what trends you're seeing there. It looked like it was a nickel benefit in vertically integrated, a little bit of a headwind in transmission and distribution. Just wondering if you could dive in a little bit more as far as what different trends you're seeing in O&M across the business.
Yeah.
Yeah, happy to. Jeremy, this is Julie. I did call specifically out the O&M trend in vertically integrated utilities. There's a little bit of flipping and switching going on between O&M and depreciation associated with the Rockport Unit two. That's included in that 2022 guidance that we had provided to you back in February when we updated that page for you. Entirely consistent. Yeah, we're absolutely watching O&M as we continue to navigate inflationary pressures, et cetera. At this point, I would tell you, I think we're right in line with where we thought we'd be. You know, we're keeping our fingers crossed, and you know, the team's working like heck to make sure that we've got supply chain and supply chains being addressed, et cetera.
At this point, that guidance that we gave to you stands pat. Nothing new to report other than the fact that the team's working really hard to make sure that those numbers come in in line. You know, to the extent that we have any new developments, you know, we'll surely keep you apprised.
Got it. Thank you. I'll leave it there.
Perfect.
Thank you.
Next, we'll go to Durgesh Chopra with Evercore ISI.
Morning, Durgesh.
Hey, good morning, Nick. Congrats. This is a solid print here.
Thanks a lot.
Most of my questions have been asked and answered. I just had a quick clarification as it relates to the Kentucky sale.
Mm-hmm.
The May fourth is when we get the order for transfer and control. Do we need to get sort of the Mitchell operating plan agreement before then, or how does that play into the May fourth order?
No, that'll likely come after shortly thereafter. The way we've looked at it is, you know, obviously you want the transfer agreement done. As far as the Mitchell agreement approval, we expect that to occur shortly thereafter with both commissions because it's an important aspect of it and something I think that really helps for the transaction side as well.
I understand. They can actually issue an order, the Kentucky Commission can, before actually, on the transfer.
Yeah.
before resolving the Mitchell sort of ongoing debates.
Yeah.
with different things.
That's right. That's right.
Understood. Thank you so much, guys.
Yep.
Next, we will go to Sophie Karp with KeyBanc.
Morning, Sophie.
Hi. Morning. Thank you for giving me here a turn.
Yeah, sure.
I have a couple questions here. First on the load growth, right? Obviously very healthy numbers here, above other industrial regions in the country, probably at this point. I'm not sure if two quarters is a trend, but let's say, how long do you need to see those numbers, in this range, that it would be enough to inform maybe your reset in long-term expectations for what the load should be? Does that make sense?
Oh, yeah. That's a great question because, you're right. Two quarters doesn't make a trend. When you look at the economy within our service territory, we're seeing some very positive indicators for continued expansion and continued economic development that our economic development people are extremely busy with multiple opportunities that are coming throughout our territory, actually. We look at that. Sort of if you were to look at our pipeline of potential opportunities, it is extremely robust. That gives us confidence in terms of where we think the economy is gonna continue to go within our service territory.
Of course, we don't see an end to the work from home environment, so we're feeling much better about the prospects of a more robust residential side of things. Then on the industrial, it's like I said, the onshoring, the security aspects, the energy play within our service territory, the other aspects of what's going on within the territory with chemicals and manufacturing and so forth, that pace has picked up markedly with expansions and new developments. Some of them are still, you know, years away, like the Intel manufacturing here in Ohio, in our territory. It's substantial. There'll be 20-40 more companies associated with that. It'll be locations.
You see those types of prerequisites that are being put in place that gives us a lot of positive views about where we think the economy's going. We'll watch it. We'll continue to evaluate it. If we go through Q3 , see the same thing, and Q4 , the same thing, then you'll probably see, you know, some adjusting going on relative to, you know, the 2023 forecast. That's, you know, our load guy will have to tell us that. He's very objective, and he's a professor at one of the universities. Let me put it this way. He's probably more optimistic now than I've ever seen him. That's a good thing.
Nick, if I can just jump in there.
Yep.
with a finer point too as well. Sophie, as I made comments in my opening remarks, we are still about 1.6% behind pre-pandemic levels on the industrial side of the house. As I mentioned, and as Nick mentioned, we do see expansions that are gonna allow us to not only get past that 1.6, but to go beyond that. We do expect to be beyond the pre-pandemic levels. As a matter of fact, what we've seen so far this year in the Q1 is that six of our top ten sectors were up. That's a good indication. Looking forward, we expect to see strong growth in oil and gas as new LNG operations ramp up in Texas.
That began, you know, a few quarters back. We're gonna start to see the fruits of that efforts, as well. Stay tuned. As you know, we typically, if we're gonna revise guidance, we've historically done it, once we get past our peak season, which is summer. To be perfectly candid, we're looking at this constantly. We will be back to you if there's anything that requires us to get new information in front of you, because we'll definitely want to take advantage of that.
Yep.
Perfect. Thank you. My other question is on the RFPs, not to beat the dead horse, I guess, but I can appreciate the fact that the projects are expected to be commissioned in 2024, 2025 timeframe, which is a couple years away to sort out the physical disruptions of maybe, you know, equipment availability, et cetera. In terms of pricing, what should be... Like, people who bid into those RFPs, like, what do you think they should be assuming in terms of pricing? Does that make it difficult, the volatility in the pricing of equipment, particularly solar and kind of unpredictability really of where the solar market or storage market might be, you know, a year from now? Does it make the, I guess, the process more complicated or, you know, I just wonder about that.
Yeah, I think it will make it more complicated, but not insurmountable because, you know, whatever increases you may see from a solar perspective, the overall project benefits will still be positive. Now, it may change the relationship between wind and solar in the integrated resource plan. Solar may come later than what we thought because if wind continues to progress. As you recall, in our resource plan, a lot of it was wind to start, and then eventually, as based on pricing and everything else, solar would start to pick up and at some point overcome the wind asset, and then you move into other technologies. That condition may change based on that. You also.
I mean, you'll probably see that in the framework of increased gas prices, too. Really the renewables will be relative to each other, not in terms of relative to whether they'll get done or not. I really think we'll be in good shape from that perspective. The other part too is that when you look at the other resources, you know, really what you're doing is you're putting in renewables and you're also layering in some natural gas in the plan to really give it 24/7 supply. Natural gas also is a placeholder for other types of resources, whether it's hydrogen, whether it's modular reactors, whatever that comes about with new technologies.
The grid optimization itself will be a major part of that as well with transmission. There's a multitude of answers there that will occur. Yeah, you're right. You would suspect solar, there'll be some short-term perturbation from an increase perspective that we'll have to deal with. You know, in the overall scheme of things, when you look out long term, it'll still be positive.
All right. Thanks so much.
Yep.
Our last question comes from Michael Lapides with Goldman Sachs.
Hey, Julie. Hey, Nick. Thanks for taking my questions. I have two, and they're a little bit unrelated. I'm going through the appendices of your slide deck. I'm looking at what you used to call kind of your, I don't know, the money chart, the ROE chart for trailing twelve months.
Equalizer chart. Yep.
The equalizer chart. Thank you. One of the things that stands out is Public Service Company of Oklahoma. Just curious if you can talk a little bit about PSO and a little bit about maybe SWEPCO and APCo, where the earned ROEs are a decent bit below 8%. Just kinda how do you think about the trajectory of quote-unquote fixing the split between earned and authorized?
Yeah. At SWEPCO, we have rate cases there in two of the jurisdictions. In PSO, we will have a rate case as well. Keep in mind too, you know, we just brought in all the renewables in play, particularly a large chunk of it for PSO and SWEPCO. That's now rolling through rates. We expect that to continue to pick up. Those are really, when you look at the industrial and manufacturing economic development part of what's going on in those jurisdictions, they're still very positive. Of course, you know, we continue to invest heavily in those jurisdictions.
That's why, you know, we have an equalizer chart that some will appear lower until we file rate cases and when the investment changes itself. We're not concerned by that at this point. Actually we see PSO and the SWEPCO jurisdictions with Arkansas, Louisiana in particular, very favorable.
Got it. Okay. One follow-up, and this may be just a checking in on what was in original guidance. Just curious for the transmission segment, how much do you think, you know, noticing that it's evened down a little bit on a net income and EPS perspective year-over-year for the Q1 , can you remind me what you think the earnings growth trajectory is for just the transmission segment in 2022 relative to 2021 and kind of the drivers behind that?
Yeah. Julie?
Michael, I don't have my guidance sheet in front of me for 2022. It's in our presentation that we put out there in our Q4 call. Effectively, actually somebody's gonna hand it to me. Effectively what we were anticipating was that year-over-year we'd be off about $0.08. That was driven by investment growth being up $0.12. I mentioned this actually in my opening comments as well, and then we had a true-up that would occur and we knew that was going to be embedded. That's why we have it in the guidance that's associated with-
The true-up was positive the previous year.
It was. It was flipping back and forth.
It sort of double counted.
Yes. We had two reasons for that true-up. I mean, we had spent just a little bit under our budget for the prior year, and as you know, we got forward-looking rates, so that's a catch up there. We had higher load, so we had to catch up there, too. We get a little bit of a double counting there. That's why we had the $0.11 reduction in that true-up. We had other financing and income taxes that kind of brought that number back down to flip it to a -$0.08. In aggregate for 2022, we assumed that we'd have about $1.27 from that particular segment, again, driven by investment growth, offset by a couple of these other bucket items that I threw out there.
We are on that trajectory, and that's why I specifically called that out in my opening comments, because you know, if I was trying to model this, that's exactly what I'd be asking.
The kind of growth would be more back end of the year, would it?
I guess it's probably fair enough. You know, we're a little short on the Q1 , but yeah, I would just expect that we'll continue to see transmission investment, you know, continue to plug along for the remainder of the year. At this point, we don't have any changes as it relates to that specific guidance. You know, we have it out there year by year, in our guidance forecast and assumptions pages in our traditional investor relations materials. I'm happy to walk through it with you offline if you'd like to do that too.
I appreciate it. Thank you, guys. Super, super helpful and, much appreciated you taking the time to get to my questions.
Sure thing. Thanks, Mark.
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. Katie, would you please give the replay information?
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