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Ladies and gentlemen, thank you for standing by and welcome to the American Electric Power first quarter 2019 earnings call. At this time, all lines are in a listen-only mode. Later we will conduct a question and answer session and instructions will be given at that time. If you should require assistance from an operator, please press star then zero. As a reminder, today’s conference is being recorded, and we will give the replay information at the end of the call.
I’ll now turn the conference over your host, Bette Jo Roza. Please go ahead.
Thank you, Ryan. Good morning everyone and welcome to the first quarter 2019 earnings call for American Electric Power. Thank you for taking the time to join us today. Our earnings release, presentation slides, and related financial information are available on our website at aep.com.
Today we will be making forward-looking statements during the call. There are many factors that may cause future results to differ materially from these statements. Please refer to our SEC filings for a discussion of these factors.
Our presentation also includes references to non-GAAP financial information. Please refer to the reconciliation of the applicable GAAP measures provided in the appendix of today’s presentation.
Unfortunately Nick Akins, our Chairman, President and CEO is not feeling well this morning and will not be joining the call. Although he expects to be back at work soon, we wanted to go forward with this call as previously scheduled.
Joining me this morning is Brian Tierney, our Chief Financial Officer; Lisa Barton EVP of Utilities, Chuck Zebula, EVP Energy Supply; Mark McCullough, EVP Transmission; and Raja Sundararajan, President and COO of AEP Ohio. Brian will provide opening remarks and our executive team will then be available to answer your questions.
I will now turn the call over to Brian.
Thanks, Bette Jo. Good morning everyone and thank you for joining us today for AEP’s first quarter 2019 earnings call. We all wish Nick a speedy recovery and a quick return.
The company is off to an excellent start for 2019. We are pleased to report solid earnings of $1.16 per share on a GAAP basis and $1.19 per share operating, which compares to $0.92 a share GAAP and $0.96 per share operating for the first quarter of 2018. The positive drivers were fully realized outcomes from a multitude of rate cases from 2017 to 2019, increased transmission margins from invested capital, and lower O&M, mostly timing in this case. The company continues to excel and our employees continue to deliver on the execution of our strategy of being the premium regulated utility. Overall, this was a great quarter for the company.
There are a few topics we’d like to cover before moving on to coverage of our financial performance. First regarding the Oklahoma rate case outcome, this was an important case. While we didn’t get everything we hoped to achieve, we were successful in gaining our most important objectives: an improved ROE opportunity, riders for transmission and some distribution investments, and most of all, a much improved regulatory environment. The outcome of the case bodes well for our continued focus on renewables and hopefully natural gas at some point in the state. I will discuss the regulated wind RFP initiative later. We certain appreciate the constructive focus of the Oklahoma Corporation Commission, the staff and parties on this case.
Our acquisition of the Sempra renewables portfolio is now finalized and we are moving forward with our renewables build-out according to plan. We have extended employment offers which have been accepted by many of the members of the previous Sempra team and we welcome them to the AEP family. We are excited about the acquisition of the existing operational projects, the additional developmental projects, and the Safe Harbor equipment that can provide additional value.
In addition to that effort, we have significant opportunities for renewables in our regulated businesses. PSO and Swepco issued an RFP for up to 2,200 megawatts of wind generation. We have completed the bid process and received many quality responses. We are in the process of negotiating terms with the preferred bidders and plan to file with the state commissions in July requesting approvals to proceed. This should allow time for approvals in 2020 and for commercial operations of the projects by the end of 2021. As a reminder, these projects are consistent with our integrated resource plans and they are currently not included in our capital and funding plans.
Now to the Ohio Clear Air Fund legislation, the company is supportive to the Ohio House leadership’s focus and efforts on addressing key energy policy issues that have plagued the state for years. In order for the legislation to benefit all Ohio customers, there are certain issues that must be addressed. First, an elimination of the renewable portfolio standard should be replaced with the opportunity for utilities to voluntarily develop economic renewable resources in the state. In addition, contracts entered into under the existing renewable portfolio standard must be grandfathered so as to not punish utilities who are compliant with Ohio law.
Second in regard to energy efficiency, AEP is concerned about a rapid elimination of EE programs that have benefited our customers for many years. In lieu of immediate elimination of EE programs, previously approved plans should be phased out over the next several years. We look forward to working with lawmakers during the process to achieve a balanced energy bill that provides benefits to all Ohio customers.
Turning to the equalizer chart on Slide 5, AEP’s overall regulated operations ROE is currently 10.1% versus 9.7% last quarter, placing us at the upper end of our targeted range. The improvement in the first quarter of 2019 versus the fourth quarter of 2018 is due to rate case outcomes in several of our jurisdictions as well as timing effects of lower O&M and taxes.
Now let’s take a look at the individual companies. The seat-adjusted ROE for AEP Ohio at the end of the first quarter was 13.2% versus 13.1% in the fourth quarter of 2018. This year, we will only be showing the seat-adjusted ROE since the legacy items are rolling off throughout the year. We expect to end 2019 in the 13% range.
Appalachian Power’s ROE at the end of the first quarter was 9.5%, comparable to last quarter. APCo received an order from West Virginia at the end of February approving their settlement, which includes a $44 million rate base increase with a 9.75% ROE, effective March 6 of this year.
The ROE for Kentucky Power at the end of the first quarter was 8.6% compared to 9% at the end of 2018. The slight decline was primarily due to lower sales and usage driven by weather and an unfavorable tax adjustment.
I&M’s performance remains strong at 12.8% versus 11.4% at the end of 2018. I&M’s positive performance is driven by the favorable rate reviews that occurred mid-2018 as well as continued discipline managing O&M expenses.
The ROE for PSO improved to 8% versus 6.9% at the end of 2018. This primarily reflects the implementation of the 2017 base rate case, better weather, and the absence of Wind Catcher expenses. PSO received an order on its base case settlement in March 2019 approving a $46 million increase and a 9.4% ROE. Rates went into effect in April of this year. Importantly, the order contained a provision for full transmission tracker and a partial distribution tracker. PSO is expected to approach its authorized ROE by the end of this year.
The ROE for Swepco stands at 7.2% versus 6.5% at the end of 2018. This improvement is due to incremental rate relief and lower O&M expenses, also reflecting the absence of Wind Catcher expenses. We filed an Arkansas base rate case in February seeking a $46 million rate increase based on a requested 10.5% ROE. Swepco’s ROE continues to be affected by the Arkansas share of the Turk plant that is not in rates. This impacts ROE by 135 basis points.
The ROE for AEP Texas at the end of the first quarter was 7.6% versus 8.5% at the end of 2018. The expected decline in ROE is due to lag associated with the timing of annul filings and our base rate review that we plan to file with the PUCT on May 1 of this year. Continued high level of investments and timing of our planned comprehensive rate review will continue to impact the ROE in this year.
The ROE for AEP transmission holdco at the end of the first quarter was 9.9%, comparable to last quarter. The under-recovery of expenses that occurred in 2018 will be trued up this June. AEP transmission holdco is projected to achieve an ROE of approximately 10% by year end.
We are off to a great start in 2019, so let’s go through the financial results for the quarter, provide some insight on load and the economy, and finish with a review of our balance sheet and liquidity.
Looking at Slide 6, which shows that operating earnings for the first quarter were $1.19 per share or $585 million, compared to $0.96 per share or $473 million in 2018. Looking at the earnings drivers by segment, operating earnings for vertically integrated utilities were $0.63 per share, up $0.16. Favorable drivers included higher rate changes due to recovery of incremental investment, AFUDC and transmission revenue, as well as lower O&M. Income taxes were also a driver for the quarter but will not be for the year due to timing. Partially offsetting these favorable items were lower normalized load, unfavorable weather compared to last year, and increased depreciation expense.
The transmission and distribution utilities segment earned $0.32 per share, up $0.07 from last year primarily driven by the reversal of the regulatory provision in Ohio. Other favorable drivers included higher transmission revenue and rate changes. Partially offsetting these favorable items were higher depreciation, O&M, and unfavorable weather.
The AEP transmission holdco segment continued to grow, contributing $0.25 per share, an improvement of $0.04 over last year. This growth reflected the return on incremental rate base. Net plant increased by $1.4 billion or 19% since March of last year.
Generation and marketing produced earnings of $0.09 per share, up a penny from last year. Increases in retail and wholesale margins were offset by lower generation sales due to plant retirements and outages.
Finally, corporate and other was down $0.05 per share from last year primarily driven by unfavorable income tax adjustments and other consolidating tax items that will reverse by year end, other variance related to higher interest expense and lower O&M. Overall, we experienced a solid quarter and are confident in reaffirming our annual operating earnings guidance.
Now let’s turn to Slide 7. Before we dig into the detail for the quarter, let me highlight some minor changes to the slide. You may have noticed that our growth estimates for the 2019 forecast of commercial and industrial sales have changed from what we presented in the last earnings release, while total and residential sales remain unchanged. This is due to a reclassification between the commercial and industrial classes. There were no customer, tariff or revenue impacts, just geography and presentations between the two classes. For ease of use, we have adjusted the prior quarters to reflect the new classifications.
Now let’s look at the quarterly detail. Starting in the lower right chart, normalized retail sales decreased by three-tenths of a percent for the quarter compared to 2018. It is worth mentioning that retail sales were down at all of the vertically integrated utilities while each of the T&D utilities experienced modest growth in the quarter. Moving clockwise, industrial sales decreased by four-tenths of a percent for the quarter. Sales in the industrial class have been slowing in recent quarters as the impact of a strong dollar and a more restrictive trade policy have challenged export manufacturers within AEP’s footprint.
During last year’s first quarter earnings call, we reported widespread growth across all operating companies in every one of the top 10 industrial sectors. Now a year later, industrial sales grew only in our western operating companies and Ohio, and in only six of the top 10 industrial sectors. The majority of this came from the oil and gas sectors. I’ll provide more color on our industrial sales on the next slide.
In the upper left chart, normalized residential sales increased by nine-tenths of a percent compared with the first quarter of 2018. The growth in residential sales was partially due to customer count growth which increased by half a percent, while the rest came from growth in normalized usage. Incomes grew faster than inflation for the quarter, which provided our customers with more disposable income. I’ll provide more detail on the economy later in the presentation.
Finally in the upper right chart, commercial sales decreased by 1.7%. Commercial sales were down across all operating companies. The tightening labor market and rising interest rates have limited this sector’s growth in recent quarter.
Turning to Slide 8, I want to provide a little more color with respect to our industrial sales. The chart shows the disparity in sales between the oil and gas sectors and all other industrial sectors. The oil and gas sector load, shown in blue, mirrors the pattern in oil prices over time as expected. For the quarter, industrial sales in the oil and gas sectors increased by 5.1% while the rest of our industrial sales, shown in red, declined by 2.2%. We expect the growth in oil and gas to continue through 2019 as prices recover. In addition, our economic development team has identified a number of new oil and gas projects that are expected to come online throughout the year.
Now focusing on the red bars, you see the non-oil and gas industrials experienced robust growth in 2018 until the trade policy changes were announced at the end of the first quarter. Since then, a noticeable deceleration has occurred. Most of this slowdown can be traced back to export industries such as chemical manufacturing, which is down 9% for the quarter. As discussed on previous calls, AEP has a higher exposure to trade policy given the higher concentration of export manufacturers located within the service territory.
Now let’s turn to Slide 9 and review the status of our regional economies. As shown in the upper left chart, GDP growth in AEP’s service territory was 2.9% for the quarter, which is a tenth of a percent above the U.S. Outside of Kentucky, GDP growth for every operating company was within two-tenths of a percent of the U.S. for the quarter.
The upper right chart shows that the gap in employment growth between AEP service territory in the U.S. did not change in the first quarter. Job growth in AEP’s territory was still 1.3% with higher growth coming from the west, where most of the oil and gas activity is located. In fact, job growth in the natural resources and mining sector posted the strongest growth in the quarter at 4.3%. Other sectors that experienced robust job growth for the quarter include construction, professional and business services, education and health services, and leisure and hospitality.
The final chart at the bottom shows that income growth within AEP’s footprint improved in the first quarter while U.S. income growth moderated. For the quarter, personal incomes within AEP’s service territory increased by 3.7%, which was half a percent below the U.S. As described earlier, income growth is a key driver for residential and commercial sales.
Now let’s move on to Slide 10 and review the company’s capitalization and liquidity. Our debt to total capital ratio increased eight-tenths of a percent during the quarter to 57.8%. Our FFO to debt ratio finished the quarter at 18.1%. We expect this ratio to decline over the year as we flow back ADIT to customers, but expect the number to remain in the Baa1 range. Our net liquidity stood at about $3.1 billion, supported by our revolving credit facility. Our qualified pension funding decreased to 98% and our OPEB funding moderately increased to 131%. A drop in yields increased the liabilities for both plans but strong equity returns helped to offset the liability increases.
In March, AEP issued $805 million of mandatory convertible equity units. This issuance combines a three-year junior subordinated debt instrument with a three-year forward purchase contract for equity. This issuance de-risks our financing plan by providing required capital now and equity later when needed, and not sooner. It delays equity needs above our DRIP program until 2022. The issuance maintains our balance sheet strength, enhances our credit metrics, and allows us to invest growth capital for the benefit of our customers and for the recently closed renewables transaction.
Let’s try and wrap this up on Slide 11 so we can get to your questions. We will move forward with opportunities in the renewable space and continue to optimize our O&M spend. Our performance in the first quarter and the stability of our regulated business model gives us the confidence to re-affirm our operating earnings guidance range of $4 to $4.20 per share.
With that, I will turn the call over to the operator for your questions.
[Operator instructions]
Our first question will come from the line of Praful Mehta with Citigroup. Please go ahead.
Thanks so much, hi guys.
Good morning, Praful.
Morning. Maybe just the details on the mandatory convert in ’22, what are the terms in terms of what price at which you expect the forward to convert into equity?
It was priced at $82.98, and the company gets the benefit of the first 20% of upside, so to almost $100 per share, and we’re locked in on the downside from that price.
Got you, thank you. Then on the renewables side, wanted to understand a couple of things. Is there any exposure that the current renewable business has to California in terms of PG&E or Edison in terms of any PP exposure as counterparties, and also want to understand when you say move forward with renewable opportunities in the future, are you looking at incremental investments even in 2019 beyond the Sempra acquisition?
A couple things there, Praful. We don’t have any direct credit exposure to the California utilities on those. Most of those are direct third party consumers of that electricity, so we don’t have that exposure that others do.
In regards to the investment in the renewables portfolio, we had talked about a five-year spend of about $2.2 billion with certain projects, including the renewables portfolio from Sempra. We’ve spent about $1.5 billion of that commitment, so we have roughly $700 million left, and we’re looking at opportunities as they become available. We feel the Sempra transaction was at a very good value to the company considering both the existing projects and the developmental projects, and we were able--by making that acquisition early in the five-year period, we were able to solidify and de-risk that $2.2 billion forecast of spend. We’re on our way to meeting the $2.2 billion commitment, and we’re evaluating development projects with the portfolio and looking at other opportunities as well.
Got you, but you don’t expect to go above the 2.2, it will stay within that budget?
That’s our anticipation at this point, yes.
Got you. Very helpful, thank you guys.
Thanks Praful.
The next question comes from Julien Dumoulin with Bank of America. Please go ahead.
Hey, good morning everyone.
Good morning Julien.
Perhaps just to pick up where Praful left off, in terms of the incremental and the 2.2 versus the 1.5 commitment already, I understand that you have some inventory to assets that you acquired as part of that Sempra transaction. I’d be curious, how do you think about leveraging that for further investments on the repowering side? When would you need to provide some updates, obviously just given the limited window remaining here from a Safe Harbor perspective, and then separately if you can clarify - obviously the 2.2 is over a five-year period. It would appear that at least from a timing perspective, you’re ahead of what you’d introduced from a ratable improvement in the EEI side last November, I would think.
Yes, so Julien, I’m going to ask Chuck Zebula, who runs that business and who you know, to address those questions.
Yes, good morning, Julien. There are opportunities that we’re pursuing. As you know, we just closed on the transaction on Monday. We’re actively working with our new team members. The status of the development projects, even as we have taken over this week, there is some positive news coming out of a township vote in Michigan on one of our projects. There’s still additional due diligence. We realize that the time is ticking to reach 2020. We may reach the light of day on one or two of these by 2020, but I can’t commit to that at this point in time. They can turn into ’21 projects with some structuring and items we would need to do with other parties, but nonetheless there are opportunities here and they're relatively small bites as opposed to significant large projects, and that’s why we think a lot of these could get done within the $700 million that Brian had talked about.
Got it. Then in terms of timing for earnings?
Well in terms of timing, I think absolutely we’ll be updating quarterly where we are in some of this stuff. It’s a full push forward, so--but yes, as we pulled the transaction and the spend earlier, you’ll see the earnings from those contributions here in ’19 and beyond.
Got it. Just to clarify this point, obviously you have a number of other RFPs out there on the Wind Catcher 2.0 structure. That’s separate and distinct from any inventory to assets that you might have for repowering assets to meet the $2.2 billion bucket, right?
That’s correct, Julien, completely different efforts.
Excellent. All right, I’ll leave it there. Thank you.
Thank you.
Your next question comes from the line of Ali Agha with SunTrust. Please go ahead.
Thank you, good morning.
Good morning, Ali.
Brian, in the past you folks have talked about confidence level trending to the higher end or the upper half of the 5 to 7% range of earnings and growth that you’ve targeted. Are we still looking at it from that perspective, and also to clarify, that was based on the existing budget? That was not assuming new incremental capex, the existing budget could trend you in the upper half of 5 to 7? Is that correct?
That’s right, Ali. I think the way Nick has phrased it before is this management team will be very disappointed if we’re not in the upper end of that range.
Upper end of the range - got you. Okay. Then separately, these RFPs and other opportunities, primarily I guess in renewables, that you are working on, can you give us some sense of size? I mean, if these do come through and you’ve pointed out these would be incremental to the base plan, but what kind of cumulative size are we looking at in terms of that opportunity?
The regulated RFPs that we’ve issued in the market are for up to 2,200 megawatts, and the reason that that’s the number is that’s consistent with what our IRPs in those jurisdictions would call for, for renewables, so a significant amount not dissimilar to what we were talking about in terms of generation with Wind Catcher.
And that would be owned by AEP [indiscernible] if that comes through?
Yes.
Okay, and the timing around that again?
We’re shooting for the end of 2021.
Got you.
Ali, to your point, that is--those plans are not in our capital and funding plans today, but we’ll adjust those plans as we go forward and we firm up how much it is we’re talking about and confirm that the timing is at the end of 2021.
I got you. Final question, Brian, on the transmission front, you put out a very strong growth outlook to 2021 very specifically. As you look out beyond that, at least through ’23 since your capex budget goes out that many years, are you looking at a similar kind of growth over the ’22, ’23 period, or does it taper off? How are you looking at that transmission growth?
No, we see our ability to continue to grow investment in that space for the foreseeable future. One of the things when you have the largest transmission system in the country, you have the largest aging transmission system in the country, so there’s significant opportunity for us to continue to invest in our own assets, and then there’s also significant developments that we need to do on cyber and security and other efforts, where we’re just beginning to see the front end of that significant increase in spend.
Thank you.
Thanks Ali.
Our next question comes from the line of Christopher Turner with JP Morgan. Please go ahead.
Good morning, Brian. I have another question on renewables here, just broadly speaking. I think you talked about the value of the development portfolio within the Sempra purchase, but if you step back and think about the decision to buy that versus build it and the decision to kind of go in more of a wind versus a solar direction here, what informed those decisions and how do you think about your strategic edge in owning these assets versus others?
Christopher, Chuck and his team have been very selective in the assets that they’ve looked at, looking for high quality contracted assets with credit-worthy counterparties, so they’d been looking at that really on a project by project basis until this opportunity came along. What this opportunity brought with it was a lot of wind, some battery, contracted with high quality counterparties, but it also brought a team with it, and that team is something that we didn’t organically have from a development standpoint. So we got not just a team, but also development projects in the pipeline that we wouldn’t have had otherwise, so whether they’re repowering or the new project that Chuck talked about with the municipal, it takes our business really to the next level. Not to say we’re going to be the next NextEra, because I don’t think that’s our aspiration, but it firms up and de-risks our ability to put that $2.2 billion to work, like we talked about.
I think with Chuck’s existing commercial team, their conservative approach to making sure that we get high quality assets combined with the new development team that we get from Sempra, I think we have a pretty strong organization to go forward and execute against the strategic plans that we’ve laid out.
Is it fair to think about the returns that you’re going to get there long term as being pretty competitive with what you’re earning at the T&D businesses and the generation businesses today on the utility side?
Very much so.
Okay. My second question is a follow-up to an earlier one on the long term EPS guidance. I wanted to make sure I was properly understanding here. You have a situation where you’d be disappointed if you weren’t at the high end of the 5 to 7% range, and just year-to-date you’ve pulled forward that capex with the Sempra deal, you’ve had a constructive settlement in Oklahoma that’s going to allow you to earn a more fair return there, and you still have the potential for the RFP on the utility side with the renewables. Is there any timing shift within that 5 to 7% range that’s occurred here, or is still back end weighted for the high end of that range?
As we talk about this year, we believe we’re on track to be inside that $4 to $4.20 range, which puts us in the mid-part of that range I think as we execute against some of these things, it’s going to take time for them to cumulatively push us to the higher end of that range, so I’d say no change on this year, and as we look forward to future years as we execute both regulated and some of these competitive opportunities, I think that’s when we’ll be expecting to be in the upper end of that range.
Okay, that’s fair. Thanks Brian.
Thanks Christopher.
Your next question comes from the line of Paul Patterson with Glenrock. Please go ahead.
Good morning.
Good morning, Paul.
On the significant excess, the seat reversal, can you tell us--I apologize, what triggered that, because it looks like it was a 2016 item that reversed. Could you--?
Paul, it was a number of things. It was--2016 was the year that we had the global settlement in Ohio and there was some risk as to whether or not issues that were included in the global settlement would be included in the calculation of seat for that year. We believed they should have been excluded and that’s the basis on which we filed our 2016 seat. We had a unanimous settlement saying that there was no significantly excess earnings in 2016 and did not get an order on that until this year. When we looked at that, we had significant risk around that, were uncomfortable at that point given the risks that existed in taking that to income, made the reserve at the time, and now with the positive order on the settlement are able to reverse that.
Wow, they took that long for a settlement--for an order, excuse me. That’s non-recurring, right?
I want to be clear about that. It’s included in GAAP earnings and we’ve included it in ongoing earnings, but it’s an item that will not repeat next year.
Okay. Then with respect to the Ohio legislation, previously you guys, I think had concerns about AEP utility ratepayers paying for other companies’ nuclear plants. How do you guys feel about HP6 as it currently stands? I mean, I know you raised a couple of the issues in your prepared remarks. I was just wondering if you could give a little more color on that.
Yes, so we think if there’s a full package where all of Ohio customers can benefit, then it’s a worthy effort. If it’s just a bailout for one company or another, it’s not as beneficial to all Ohio customers, so there needs to be a full package of things that get addressed, and energy efficiency, the renewable portfolio standard, ability of utilities to invest in renewables going forward are all important things that need to be in the bill, and if they’re not, it’s not as beneficial for ratepayers in the state.
Okay, I got you. Then with the energy efficiency, if those changes did take place, do you think that would have a meaningful impact on your retail sales growth?
We do not.
Okay, thanks so much.
Thanks Paul.
Next, we go to the line of Michael Lapides with Goldman Sachs. Please go ahead.
Hey guys. Brian, thanks for taking the question. Just curious, can you remind us what the sensitivity to changes in weather normalized demand are in terms of meeting not just current year guidance but your multi-year growth rate? I ask, and I know it’s only one quarter, but some of the demand metrics on the commercial side seem pretty weak and that’s obviously--you know, you get a lot of demand from industrial but it tends to be lower margin, but commercial and residential tends to be higher margin.
We’re trying to look up what those sensitivities are right now. We think that we’re on track to get where we need to be for the year, even though we’re slightly off for the first quarter. Again, we make more from places where we sell integrated utility products than just the T&D side, but for changes--you know, 5% change in res--I’m sorry, half a percent change in residential is half a penny for T&D utilities. For vertically integrated utilities, it’s 1.4%. Commercial again is about half that, half a percent change; for vertically integrated utilities, it is seven-tenths of a penny. For T&D utilities, it’s a tenth of a penny, and for industrial sales half a percent change is the same as it is for commercial, seven-tenths of a penny for vertically integrated and a tenth of a penny for T&D utilities.
Got it, thank you. One other question - just trying to think about Texas. What’s driving the under-earning in Texas? I mean, Texas is a state where you’ve got both transmission and distribution cost recovery riders, so just curious what’s the biggest driver of the regulatory lag you’re experiencing now?
There’s a couple things going on there, Michael. One is the fact that we are investing so much in the state that even with those very timely recoveries, we just can’t keep up with the amount of capital that we’re putting to work in the state. Second thing is as we go in for the base rate case this year, we need to suspend those short term trackers for the near term until we get everything caught up in the base rate case, and then we can put those trackers back in the space. That is going to cause a little bit of lag this year and next year as well.
Got it, thanks Brian. Much appreciated.
Thanks Michael.
Next we go to the line of Andrew Weisel. Please go ahead.
Hey, good morning everybody. Congratulations on the PSO outcome. My question there is does this change your capex plan at all? With a transmission tracker, would you consider increasing capex at PSO, and would that drive an increase of the overall spending or would it be shifted away from other subsidiaries? I see the pie chart is unchanged, but just wondering how to think about that.
What this means for us is that Oklahoma is open for business again, so we had previously, when we were under that prolonged period of under-earning at PSO, we had shifted capital to more welcoming jurisdictions that allowed us to have higher ROEs and that had trackers. Now that we have appropriate trackers in Public Service of Oklahoma, we’re going to shift capital that had been shifted away from Oklahoma back into the state and have that benefit the ratepayers and customers in that state. It’s not so much a huge increase, although it is, but we’re shifting dollars back in that had been shifted out, and that’s positive for PSO.
Makes a lot of sense. My other question is on Ohio wind. My understanding is you’re able to own up to 450 megawatts out of the 500 planned. My question is for the portion signed through PPA, would you expect a debt equivalency cost mechanism? I know you have that for solar, but it’s small. How do you think about that for wind PPAs?
Yes, we would expect a debt equivalency on those as well. If our utilities balance sheets are being consumed to support PPAs, we need to be compensated for that, and the rating agencies ding us for those and we need to make sure that we’re filling in the gap that we’re getting dinged for by entering into those PPAs. We think debt equivalency is appropriate really on all renewable PPAs that we don’t own.
Okay. I know there’s not a lot of precedent - obviously Michigan just settled upon that. You used the word need twice in your answer there. Is that a nice to have, or a must have?
How can I say this? It’s appropriate to have them and it’s inappropriate not to have them.
Fair enough. Thank you very much.
Thank you.
Our next question comes from the line of Angie Storozynski with Macquarie. Please go ahead.
Thank you. I wanted to go back to 2019 guidance. The Sempra acquisition came earlier than expected, and you mentioned that it would be earnings accretive this year. The Oklahoma rate case settlement was better than expected, so what’s the negative offsets that you’re still in the middle of the range?
There’s a couple things going on. In addition to the Sempra acquisition, there are also some financing costs associated with that, so we do expect gen and marketing to be ahead a couple pennies, we expect corporate and other to be a drag as we finance that. Our AEP transmission holdco, while improving, is not going to be as strong as what we thought it was going to be when we provided guidance due to some tracking items on O&M and due to our inability to get everything into the capital base that we thought we would be the end of last year. So like any year, there are things that are positive, there are things that are negative as we work our way through the year, and we still anticipate being in the midpoint of the guidance range.
Okay. The Swepco and PSO renewables, can we assume that all of these assets would be rate based?
Yes, that’s what the RFP asked for - build, operate, transfer two PSO and Swepco projects, and that’s largely how people responded, and we would anticipate owning them and that’s how we’ll file with the commissions in July.
Okay, thank you.
Thank you, Angie.
As a reminder, if you do wish to ask a question, please press star, one. Our next question comes from the line of Mike Lonegan with Evercore. Please go ahead.
Hi, it’s Greg Gordon, how are you doing?
Hey Greg.
Just a follow-up on Paul Patterson’s question on the reversal of the seat test issue. When you initially booked that in the first instance, was that also considered an operating item, so this is kind of equal opportunity - it was a drag in that year, and now that you reversed it, it’s a help, but in all cases you’re consistently applying that methodology?
Absolutely, Greg. It was GAAP and operating in both periods.
Okay, thank you. Just wanted to clarify that. The second thing, just as a follow-up to Angie’s question, I just want to make sure that I’m not getting the implication wrong when you said that you’re going to be ahead in the renewables business but then you have the financing costs associated with financing Sempra. Is the implication that the Sempra transaction is not really accretive on an earning basis in ’19, and if not so, what’s the math there and how does that trend over time?
No Greg, it will be accretive in ’19, it will be accretive going forward. Remember the financing was larger than what was needed just for that one project, but it’s an accretive project in the current period and in forward periods, inclusive of financing costs.
Ah, I understand, but then part of that equity was allocated to just general corporate needs, and we have to think about it that way?
That’s correct.
Okay, thank you.
Thank you, Greg.
We have no further questions in queue at this time.
Okay, well thank you everyone for joining us on today’s call. As always, the IR team will be available to answer any additional questions you may have. Ryan, would you please give the replay information?
Certainly. Ladies and gentlemen, as you heard, this conference is available for replay. It starts today at 11:15 Eastern and goes through May 2 at midnight. You can access the AT&T replay system at 1-800-475-6701 and enter in the access code 466133. International participants may dial into the United States, area code 320-365-3844. Those numbers again - 1-800-475-6701, international is 320-365-3844, with the access code 466133.
That does conclude today’s conference. I want to thank you for your participation. You may now disconnect.