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FirstEnergy Corp
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Greetings and welcome to the FirstEnergy Corp. Fourth Quarter 2017 Earnings Conference Call. At this time, all participants are in a listen-only mode. As a reminder, this conference is being recorded.
It is now my pleasure to introduce your host, Meghan Beringer, Director, Investor Relations for FirstEnergy Corp. Thank you, Ms. Beringer. You may begin.
Thank you, Christine, and good morning. Welcome to our fourth quarter earnings call. Today, we will make various forward-looking statements regarding revenues, earnings, performance, strategies and prospects. These statements are based on current expectations and are subject to risks and uncertainties. Factors that could cause actual results to differ materially from those indicated by such statements can be found on the Investors section of our website under the Earnings Information link and in our SEC filings.
We will also discuss certain non-GAAP financial measures. Reconciliations between GAAP and non-GAAP financial measures can be found on the FirstEnergy Investor Relations website along with a presentation which supports today's discussion.
Participants in today's call include Chuck Jones, President and Chief Executive Officer; Jim Pearson, Executive Vice President and Chief Financial Officer; Leila Vespoli, Executive Vice President, Corporate Strategy, Regulatory Affairs and Chief Legal Officer; Jon Taylor, Vice President, Controller and Chief Accounting Officer; Steve Staub, Vice President and Treasurer; and Irene Prezelj, Vice President, Investor Relations.
Now, I would like to turn the call over to Chuck Jones.
Thanks, Megan. Good morning, everyone. Yesterday, we reported solid 2017 results along with 2018 earnings guidance and a growth rate that provides investors with visibility into our regulated opportunities through 2021. Our operating earnings results surpassed our original guidance for the year and are near the upper end of the revised range we provided last quarter. We have now achieved three straight years of meeting or exceeding the midpoint of the operating earnings guidance we provided to investors. I am proud of the financial discipline our entire team has shown over this three-year period.
Our 2017 operating earnings reflect the strong financial performance in our distribution and transmission businesses as well as the positive impact of our regulated growth strategy. Our GAAP earnings were impacted by impairments and plant exit costs at our competitive business as well as charges related to the Tax Cuts and Jobs Act. Jim will discuss these in more detail shortly.
We are gratified that our plans to transform our company into a highly performing, fully regulated utility earned the confidence of several prominent investors who made a $2.5 billion equity investment in our company last month to support this transition. I'll take a few minutes to walk through the positive impacts this transaction is having on our company.
First, it allowed us to strengthen FirstEnergy's balance sheet and improve our credit metrics. We used some of the proceeds to make a $750 million contribution to our employee pension plan, coupled with a $500 million contribution we made earlier in 2018. We don't expect any further required contributions to the pension through 2020. We also reduced holding company debt by $1.45 billion and, as a result, we are positioned for a sustained investment grade credit metrics through at least 2021. This transaction also eliminates the need to issue any additional equity outside of our employee benefit and stock purchase plans during our current planning period which runs through 2021.
Second, the transaction facilitates an accelerated growth in infrastructure investment improvement program for our transmission and distribution businesses. For 2018, we are introducing regulated operating earnings guidance of $2.25 to $2.55 per diluted share. This represents operating earnings from our distribution and transmission businesses, net of the corporate segment.
With those regulated operating earnings as our base, we're also introducing a long-term regulated operating earnings growth rate projection of 6% to 8% through 2021. This excludes the DMR in Ohio and is offset by the corporate segment. This growth rate reflects incremental investments in both the distribution utilities and transmission companies which I will discuss later for a total capital investment of more than $10 billion over that timeframe.
I will note that these projections are presented on a fully diluted basis reflecting the full impact of the preferred shares in 2018. Beginning with first quarter 2018 results, we intend to report on a fully diluted basis to provide you with a comparative view of the company's performance. Finally, our January transaction includes the formation of a Restructuring Working Group or RWG that will advise our FirstEnergy management team as it addresses any potential restructuring at FES.
The restructuring working group includes three FirstEnergy executives: Jim Pearson, Leila Vespoli, and Gary Benz, our Senior Vice President of Strategy; along with outside industry professionals, John Wilder of Bluescape and Tony Horton of Energy Future Holdings. The group has already started work, and they received a presentation from FES management to help the outside members become familiar with the business.
FES continues to meet with its creditor advisors, and we anticipate that the RWG will be involved in those discussions at some point as well. It's important to emphasize that RWG is serving FirstEnergy's management and that FirstEnergy Solutions board of directors will continue to make decisions about FES, including any restructuring decisions. Together, these actions are designed to transform FirstEnergy by allowing us to fully shift our focus towards the tremendous opportunities in our regulated growth strategy.
So let's review the very strong full-year operating performance at our regulated businesses and other developments across our company. In our transmission business, we saw higher 2017 earnings as we completed the initial phase of our Energizing the Future investment program. During the first four years of the program, we invested more than $4 billion to support system reliability and enhanced service to our customers.
For the second phase of the program, we're increasing the low end of our targeted annual investments by $200 million. This will bring our planned investments to $1 billion to $1.2 billion annually through 2021. During the second phase, we will continue expanding the program into the Eastern part of our service territory.
In December, JCP&L filed a settlement agreement with FERC that provides for rates effective January 1, pending a final FERC order, and also provides JCP&L the opportunity to file for forward-looking rates to be effective in 2020. We expect FERC to rule on that settlement as well as the MAIT settlement that we filed in October in the next several months.
In our distribution business, 2017 was a great year. Our results reflect the new rates that went into effect in several of our service territories last January, which more than offset the $0.19 per share impact of milder weather compared to 2016. We're also pleased with the load trends that emerged throughout the year. On a weather-adjusted basis, commercial deliveries were consistent with our forecast while residential load exceeded our original expectations. In addition, we have now achieved six consecutive quarters of growth in industrial deliveries, primarily driven by the shale gas, steel and petroleum industries.
Together, 2017 operating earnings from our Regulated Distribution and Transmission businesses, offset by the corporate segment, reflect an increase of more than 25% over 2016 or 14% when you exclude the DMR. As we look at 2018 and beyond, our Ohio utilities filed an application with the PUCO in December for a $450 million three-year plans to redesign and modernize portions of their distribution system to reduce the frequency and duration of power outages as well as prepare the system for smart grid technologies. The Distribution Platform Modernization plan will help our Ohio utilities to restore power faster, strengthen the system against adverse weather conditions, and enhance system performance by allowing remote monitoring of real-time grid conditions.
In New Jersey, the BPU approved rulemaking for the Infrastructure Investment Program in December. This creates a mechanism that allows utilities to accelerate certain investments that enhance reliability, resiliency, and safety. We expect JCP&L to make a filing later this year. Incremental growth initiatives represented by our increased transmission investment and filings in Ohio and New Jersey, as well as a modest distribution rate case in Maryland are the primary drivers of the increase in our projected regulated operating earnings growth rate to 6% to 8%.
Finally, before I move away from the utility discussion, I will note that Mon Power and Potomac Edison are evaluating alternatives to address their projected capacity shortfall in West Virginia. Given the outcome of our application to transfer ownership of Allegheny Energy's Pleasants Power Station to Mon Power, our purchase agreements was terminated in light of FERC's decision and the West Virginia Public Service Commission's conditions, which would have resulted in significant exposure to commodity risk at our utility. As a result, on Friday, Allegheny Energy notified PJM that the Pleasants Power Station will deactivate on January 1, 2019. We will continue to pursue opportunities to sell the plant while we prepare for deactivation.
Moving to other Allegheny Energy news, you'll recall that in December, we completed the sale of 859 megawatts of generating capacity at the Springdale, Chambersburg, Gans, and Hunlock plants for approximately $388 million in net proceeds. The transactions involving the Buchanan and Bath plants are each on track and expected to close in the first half of this year. After paying off all remaining long-term debt at Allegheny Energy Supply, including make-whole premium payments, the net proceeds to Allegheny Energy Supply from the sale of all six of these facilities are expected to be about $220 million.
Let's turn now to FirstEnergy Solutions. It is common knowledge that we were very actively involved in a multitude of efforts at both the state and federal levels to support our generation assets in a way that would have benefited our communities, employees and FES creditors. I'm personally disappointed that the endeavors haven't resulted in a meaningful legislative or regulatory support given the importance of these plants to grid resiliency, reliable and affordable power and the region's economy. FES will continue to look at all options regarding these units, and we will continue to support policy solutions. However, as Jim will discuss, we have fully impaired our nuclear assets because the inability to receive any form of legislative or regulatory support has increased the likelihood that the plants will not be able to operate until the end of their useful lives.
At the end of January, FES, its subsidiaries and FENOC were $46 million invested in the unregulated money pool. We expect that they will exit the money pool sometime between now and the end of March and draw down the $500 million secured credit facility from FirstEnergy. The current forecast shows FES to have money pool borrowings of up to $100 million between now and March 31.
As we prepare for our future as a fully regulated utility, we are continuing our efforts to ensure that our organization is well positioned to grow and prosper and that our cost structure is properly aligned, particularly at our shared services organization. Last year, we told you that we launched an initiative called FE Tomorrow to create this blueprint for our future. The FE Tomorrow team worked with Accenture to develop a variety of scenarios to achieve this goal. Now, as we move closer to our vision of becoming fully regulated, we're entering the next stage of that effort. A team of employees reporting to Jim Pearson has been charged to implementing the FE Tomorrow strategies over the next 12 to 24 months.
As we announced yesterday, Jim has been named Executive Vice President, Finance. While he will continue to oversee the financial organization, this new role will ensure he can give his utmost attention to FirstEnergy Tomorrow and the RWG. Steve Strah, our Senior Vice President of FirstEnergy Utilities, will be stepping into the CFO position, reporting to Jim. And Sam Belcher, our Senior Vice President of FENOC and Chief Nuclear Officer, will take over Steve's role as Senior Vice President of Utilities. These changes and several others announced yesterday strengthen our succession planning by moving key individuals into new roles that will broaden their knowledge of our business. We believe this will help ensure that FirstEnergy is positioned to continue meeting our commitments to investors and customers well into the future.
2017 was a great year for our regulated businesses. We're very excited about the transformation that is taking place at FirstEnergy and for the opportunity to accelerate our regulated growth and infrastructure improvement plans that will benefit our 6 million customers, as well as our shareholders.
Now, Jim, will provide a review of the fourth quarter results.
Good morning, everyone. As always, we have provided detailed information about the quarter in our consolidated report to the financial community which is posted on our website. Yesterday, we reported a fourth quarter GAAP loss of $5.62 per share that reflects asset impairment and plant exit cost at our competitive generation fleet and charges related to the Tax Cuts and Jobs Act. I will take a few minutes to discuss these items before I move on to fourth quarter drivers.
We recorded asset impairment and plant exit cost of $2.4 billion or $3.38 per share in the fourth quarter. This includes the impact of reducing the carrying value of the Pleasants Power Station, fully impairing our nuclear-generating assets and increasing our nuclear asset retirement obligations, given the outlook for the fleet. In addition, our fourth quarter GAAP results, include a non-cash charge of $1.2 billion or $2.68 per share related to the Tax Cuts and Jobs Act, which primarily impacted our competitive business given its significant deferred tax asset position.
We are working with all of our state regulatory commissions to determine the impact of the Tax Cuts and Jobs Act on utility customer rates which would flow through to our FFO given that we aren't a federal cash tax payer.
Shifting gears to the results from our operations during the fourth quarter, we had a very strong operating earnings of $0.71 per share. Driving those results was a $0.23 per share improvement in our distribution business compared to the same period in 2016. This primarily reflected the new rates that went into effect in January 2017 as well as higher weather-related usage.
Heating degree days were normal for the quarter but 9% higher than the same period of 2016. This drove a nearly 2% increase in total distribution deliveries compared to the fourth quarter of 2016. In the residential sector, sales were up 4%, while commercial deliveries were down 3%. On a weather-adjusted basis, fourth quarter residential deliveries were essentially flat, while commercial deliveries decreased 4% as a result of lower sales and energy efficiency efforts compared to the same period of 2016. Looking at industrial sales, the positive trends continued in the fourth quarter with growth of more than 3% compared to last year, driven by gas drilling and the recovery in steel.
In the transmission business, fourth quarter operating earnings increased as a result of higher revenues related to our Energizing the Future program. Fourth quarter operating earnings in the competitive business improved due to favorable depreciation and general taxes, partially offset by lower commodity margin and higher O&M expenses. As always, we will remain focused on meeting our commitments to our shareholders and executing our regulated growth plans.
Thanks, Jim. Now, we will move into the question-and-answer phase of our call. I want to preface the Q&A that we will not be able to provide detailed information about the status of negotiations with FES credit advisers or creditors. FES has been operating independently since early 2017, and neither I or the other executives on this call can speak on behalf of FES.
Now, let's take your questions.
Thank you. We will now be conducting a question-and-answer session. Thank you. Our first question comes from the line of Julien Dumoulin-Smith with Bank of America Merrill Lynch. Please proceed with your question.
Hey, good morning. Congratulations.
Hey, Julien.
Hey. So, first off, can you talk a little bit about the CapEx that you're reflecting here? How much of the latest JCP&L and Ohio efforts are reflected in that range that you guys just released here?
Yeah. Julien, this is Jim. At the upper end of our guidance, we've included the $450 million filing that we made in Ohio, as well as we anticipate that we'll make a filing later this year in New Jersey for the Infrastructure Improvement Plan. So, I'd say at the top end of the range, it includes the $450 million in Ohio, and it also includes some money for the Infrastructure Improvement Plan in New Jersey.
Excellent. And then turning back to the earned ROEs, can you talk about what's kind of embedded as you think on the outer years of that regulated guidance? And specifically, can you talk a little bit more to Pennsylvania and what your thoughts are there? I know that there are some deferred tax items in the regulatory filings there and that's created a little bit of obfuscation out there and truly understanding what the earned returns are.
Yeah. Julien, in Pennsylvania, the ROEs have not been defined since there was a settlement in those cases. When I think about Pennsylvania and I've heard a little bit of the questions that you just raised but we've just had two cases that have been fully tried in Pennsylvania. They've been before the staff of the Commission as well as the Commission itself. And I'd also note that when I look at our residential rates in Pennsylvania and compare them to our peers, we're about 13% below what our peers are in that state. So I don't see where there's any concern about where we're at in Pennsylvania.
And you are right on the deferred taxes. There's a number of adjustments associated with deferred taxes in a rate-making process versus what you look at just from a pure GAAP standpoint.
So I'll just follow on with that based on everything Jim said. There should be absolutely no concern in the market about us over-earning in Pennsylvania. And if there is any hysteria out there, you all are smart enough to know that there are people that trade off with the hysteria. But I just want to emphasize there should be no concern whatsoever.
Absolutely. And then overall, across the utilities, what are you reflecting out in the 2020/2021 timeframe?
As far as what, Julien?
Earned returns, just in the longer dated regulated numbers you just released.
I think you would see that we're assuming that our earned returns on all the utilities would approximate what we had in our filings out there.
Okay. Fair enough.
And again (00:23:22) but we're right in line with those.
Great. Thank you.
Our next question comes from the line of Stephen Byrd with Morgan Stanley. Please proceed with your question.
Hi. Good morning.
Good morning.
I wanted touch on tax reform and just when we think about the rate base numbers that you've laid out, how much of an impact upward in terms of an increase in your rate base could be attributed to tax reform? Has that been a material impact at all in terms of your overall sort of projected rate base or has that not really been a driver in the numbers that you've laid out here?
Hey, Stephen. It's Jon. I think we actually have a slide on that. But if you remember, the only thing that's really going to impact us is the elimination of bonus depreciation which was scaling down anyway under the original tax code. So that was 40% in 2018 and 30% in 2019. That would be about a $400 million uplift to rate base with the elimination of those two years.
Okay. And so that's the extent of it. I'm sorry.
Both on the Regulated Distribution and Transmission businesses.
Okay. Understood. And just on FES, I respect that we really can't get into discussion on the negotiations. I just wanted to understand from FirstEnergy's perspective, you know there's an upcoming bond payment due. Occasionally, there's concern raised about whether or not FirstEnergy might extend the period of effective ownership of FES or – I'm really effectively trying to just check with you all on your firmness for the timeline of exiting that business and just get your latest thinking on that.
Well, I said in my prepared remarks that I expect that they will be removed from the unregulated money pool between now and the end of March, and that will be the last tie that we have with that business. While I can't speak for FES, I will be shocked if they go beyond as far out some type of a filing.
Great, Chuck. And just, I guess, related to that, when we think about the management of the business after that, a key upcoming item is the May capacity auction in PJM. Who would be sort of responsible at that point for the bidding strategy in dealing with some of these assets that appear to be fairly economically challenged? How would that sort of, in practice, play out?
It's FES' decision whether and how to bid in that upcoming auction for the FES assets. It would be Allegheny Energy Supply's decision the same for the Pleasants Power Station, and it would be Mon Power's decision for the assets that are of Mon Power's.
Great. That's all I have. Thank you.
Our next question comes from the line of Greg Gordon with Evercore. Please proceed with your question.
Thanks. Good morning, guys.
Hi, Greg.
When we're looking to model out and sort of corroborate our comfort level with the earnings trajectory that you've laid out, I think what you're implying in the way that you've laid out your guidance is that we should assume that, at a minimum, you're getting incremental revenue requirement every year on the capital you're deploying through the rider mechanisms in the different states. But anything that's under a stated rate, the only sort of revenue increases outside of formal rate case would come from any organic revenue growth that you're able to generate. Is that fair?
And then, how do we think about O&M? I think you're saying that we should assume that overall you'll keep control of O&M flat. Just trying to come up with a set of basic modeling parameters that we can use to corroborate your confidence level at, let's say, the midpoint of guidance.
Yeah. Greg, you're right. And let me really be clear about what our guidance is. We have a midpoint of $2.15, and that is what the 6% to 8% growth rate is based off of, so it's a midpoint of $2.15 with a 6% to 8% growth rate. We do have baked in increases in revenues associated with any capital spend that falls under the riders, primarily our transmission spend as well as in Ohio at the upper end, the DMR that would fall under a rider, as well as we would expect the infrastructure improvement plan in New Jersey would. So stated rates, unless there is a filing, we would not get any increases from those other than on organic growth.
Now we do have a modest rate case built in for Maryland, but that's the only rate case that we have in our guidance right now. From an O&M perspective, yes, you're correct. We're going to hold O&M flat, and you'll see an improvement in O&M associated with our pension expense. And that's primarily the result of our plan generated an additional $500 million in earnings in 2017 compared to what we expected as well as the additional $1.250 billion contribution that we made in January. So I hope that helps, Greg.
It does. It does. And then the share count you've given us is fully diluted, assuming all of the preferreds convert, correct?
Yes.
So in actuality, in what year will that average share count be the actual average share count because in the interim, we're actually being impacted with lower share count but the preferreds...
They would have to convert by the middle of 2019. So you're right there. The $536 million is fully diluted and I think we have it probably growing to about $545 million by 2021, and that just assumes the incremental equity issuance associated with our dividend reinvestment plans.
Okay. So that's the actual share count more or less in 2020, and then it grows as you continue to use your plans.
That's correct. As we continue to issue through our plans, it would increase.
Okay. Thank you, sir.
Okay.
So I'll just follow on a little bit on the O&M. Our utility companies have done an outstanding job of managing O&M over really the last 10 to 15 years. And when you benchmark it, we have very low O&M costs compared to our peers, and that's one of the key drivers behind the fact, as Jim stated, in Pennsylvania, our rates are lower than our peers. And that's true pretty much in every state that we serve.
Okay.
Our next question comes from the line of Shar Pourreza with Guggenheim. Please proceed with your question.
Good morning, guys.
Hi, Shar.
So, most of my questions were answered. But just from a modeling standpoint, there's been some very healthy growth that the slides are showing on your distribution year-over-year into 2018. What's sort of driving this especially since we have an absence of rate cases?
What period are you looking at, Shar?
Just from 2017 to 2018, looks like distribution is growing a little over 15%.
Yeah. Let me take a shot at that, Shar. We have some revenue that will grow in 2018 compared to 2017. First, it reflects a full year of the Pennsylvania rate case. As you'll recall, that did not go into effect until the latter part of January, so we'll have a full year. We also have incremental revenues associated with the Ohio DCR. And then we have some growth in West Virginia associated with the industrial load that we've talked about where we expect some growth there.
From a expense side, we expect improvement in our expenses, and that's primarily associated with the pension expense that I talked about earlier. And then we also assume that 2018 will be on a normal weather year. So that that would drive about $0.06 in earnings when you compare it to 2017. So I think those are the primary drivers, and that's offset a little bit by additional depreciation and general taxes.
Got it. That's helpful, Jim, and then just normalize it after that. Okay. And then just real quick on sort of tax reform, there's some preliminary evidence from several commissioners around the regions that they may not necessarily need a lot of that cash back immediately in order to obviously mitigate some rate volatility, et cetera.
So when you sort of think about the plan you kind of laid out here, what's the base case scenario you're assuming in this kind of a growth outlook, especially given the fact that you're in multiple states? And then is there an opportunity, especially given the O&M leverage you have, in order to accelerate some of that distribution spending especially in light of your O&M levers and tax savings that you have?
Yeah. Let me take that. In our base plan, we have not recognized any benefit associated with tax reform. Right now, we're working with all five of the commissions to see what is the most appropriate way to handle this going forward. But when you look at our plan that we have out there, it does not recognize any benefits associated with tax reform.
Excellent. Thanks, guys. Have a good morning.
Our next question comes from the line of Paul Patterson with Glenrock Associates. Please proceed with your question.
Good morning. How are you?
Hey, Paul.
Just on that last point. So, in Ohio, you guys are not planning on any benefit associated with the lower tax rate flowing through to earnings, is that correct?
We have no benefit in our plan that we laid out, that's correct, Paul.
Okay. Because there was some filings, I guess, about how – there was some position that perhaps because it wasn't a general rate case, it was a base rate case that there won't be a true-up until 2024. Is there any – could you elaborate a little bit on that or what the difference is in that?
Well, we have a stay-out provision through May 31, 2024. So, technically, we will not begin to adjust our rates for any reason, whether expenses go up, whether taxes go up or taxes go down. I can say that we've already addressed the riders. The DMR and DCR filed for lower taxes there. But we have not done anything on the other side with Ohio other than in our plan that we've laid out, we have not incorporated any of those tax benefits.
Okay. So in other words, so just to make it crystal clear, the fact that tax rates are going down will not – they're not going to be benefiting your EPS in terms of the guidance that you provided, is that correct?
Right now, they will not be benefiting our guidance, right, and we're not flowing anything through. Those would be deferred at this point.
Okay, great. And then the FES, I understand that the auction decisions and what have you are going to be done by FES is your expectation. But you guys are obviously going to be very much apprised about what's going on in the wholesale market just from being a big utility operating in it.
What is your expectation or thoughts about – since you haven't gotten – since policy has not shown up to be supportive of the power plants? Incrementally, how many power plants, just generally speaking, do you think might be leaving, might not be participating or at least clearing the auction in May? Do you follow what I'm saying?
I mean, I know that you're not necessarily going to be making the decision there, but just in general, when you guys are looking out there and you're looking at supply and demand and what have you, just from a strategic perspective, what are you guys thinking might be the amount of capacity that fails to show up or to clear the auction, if you follow me?
Well, I'm not going to speculate about what others might do with their assets. I'll just give you my simple view of the future. Unless something is done to change the construct of these administrated markets which have been administrated in a way to disadvantaged coal and nuclear plants, over the long haul, unless the states step in to provide support, there will be no coal or nuclear plants left in these markets.
Okay. Thank you so much.
Our next question comes from the line of Chris Turnure with JPMorgan. Please proceed with your question.
Good morning, Chuck and Jim.
Good morning.
For the corporate segments, the guidance that you guys provided is a lot lower than we had been modeling. I'm wondering if you moved any corporate costs or other costs from FES or the unregulated segment into there and that is baked into the guidance range that you give. And then also if there's any kind of successful cost cutting baked into that as well as we go out in the plan?
Yeah. What we've assumed in the plan is that none of the costs that are currently being charged to FES are included, other than about $25 million associated with depreciation and that's associated with common systems that we have between FES and ourselves, and that would be accounting systems, payroll, accounts payable, something like that.
The other impact on the corporate side is we've lost some of the tax shield where the interest used to be deducted at a 35% rate. Now, it's a 21% rate. So, that's driving some of that difference. But I would expect, in the plan going forward, corporate would hold flat in about the $0.55 range.
Okay. So, you're including only $25 million of depreciation moved into corporate in the plan, but you think that given everything you know that's pretty realistic with all of your cost-cutting efforts to date and going forward at the corporate level?
That's correct. That's what we have built in there. That's right.
Okay. And then my second question is you've mentioned just no incremental equity needs going forward other than the internal plans that were previously part of your guidance. Anyway I just wanted to make sure that you're confident that you can fund the existing or the new CapEx program entirely with internal cash flows and debt.
Yes, we are comfortable we can do that and you'll see we do have some new debt built into the plan. But when you think of a transmission spend that is in the $4 billion to $4.8 billion range, typically about half of that is funded through debt as well as any new capital above what we have in distribution would be new debt. But yeah, we're very confident we can do that internally.
No additional equity through 2021. I can't believe its only one month after doing $2.5 billion that we're already getting that question again. But there will be none.
Okay. Fair enough, guys. Thank you.
Our next question comes from line of Gregg Orrill with UBS. Please proceed with your question.
Yeah. Thank you. Can you talk to the $450 million Distribution Platform Modernization plan in Ohio just kind of what sort of reception you've gotten since you filed it and what the process is there and any – how you thought about scaling it and if there's likely to be any change, up or down, to the program?
Well, up till now, we have just been answering questions from the staff about what it is, what it does, how it helps customers. And beyond that, I don't think we're in a position to really say. I'd ask Leila to add to that but...
So the impetus behind that, we had another filing out there for a more full-blown, if you would, grid modernization plan. That kind of got stalled when the Commission was having its different platform and then the discussions around the state. And so we looked at our system, and there are certain things that can be done and should be done that any smart grid system can be built off of. And so that's what we have in front of them.
So it's a way for the Commission to consider it, to not tie their hands. And quite frankly, as you're looking at the spend, to kind of phase it in. So – and discussions we had pre-filing, it was warmly received. And we'll see – we don't have a schedule yet in terms of hearings, whether they can meet the date we requested or whether it might have to slip a little bit. But the concept, in any regard, was warmly received when we shared it with the Commission.
Thank you.
Our next question comes from the line of Praful Mehta with Citi. Please proceed with your question.
Hi, guys. Thanks so much. So my question is on tax reform. And I understand that it's not really built into the forecast right now or the plan you've put out. But from a cash flow perspective, can you just walk through what you expect the cash flow impact to be because obviously revenue is coming down and you have DTL refunds as well. So what do you expect that cash flow impact to be and how is that impacting your FFO to debt?
When we look at the full impact of tax reform, Praful, if we had to adjust all of the rates, it would probably impact our FFO to debt by about 1 to 1.5 percentage points. And right now, our forecast assumes those cash flows are not there and we still remain at about a 13% FFO through 2021. So, I'm not concerned about that. But when you think about the stated – or the formula rates, they will reset whenever those dates are. For the others, they'll reset whenever there's another rate proceeding or commissions decide to actually.
As far as refunding customers, I think they'll follow the normalization rules, and ultimately those amounts will be refunded over the life of those assets, which is generally 30 to 40 years. So, any cash flows that flow through now that are not required to be flowed back to the customers immediately, then that's going to benefit our cash flow and it's going to further improve our FFO to debt.
I got you. That's helpful. So, in that refund, can you just break down the DTL portion of it? Is there a protected and unprotected portion and what is the assumption of refund on the unprotected piece?
Yeah. Praful, this is Jon. There is an unprotected piece. It's very small in the grand scheme of things. The excess deferred taxes was about $2.3 billion. 95% of that, if not more, was related to property which would be protected and be refunded over the life of those assets.
Got you. Thanks. And then finally, just to add the DMR to it, I'm assuming in your current FFO to debt, you're building in the cash flow coming in from the DMR. If the DMR doesn't get extended, plus you have the FFO impact of the lower revenues and potentially some DTL refunds even though it's small, can you tell us what that FFO to debt looks like excluding DMR and then building in the impact of tax reform?
That's right. As I've said earlier, Praful, we have built in the full impact of tax reform in our forecast. It goes through 2021. And also, we did not assume the DMR would be extended beyond 2019 and our FFO is still in the 13% range.
Got you. And the target for FFO is that level or is there a different target?
I think we're comfortable with the plan we have right now, and the amount of capital investment that we plan to make that the 13% range is appropriate. As time goes on, we would like to drive that up somewhat, but I think we're very comfortable with where that is right now going to a fully regulated model and the amount of capital investment that we're planning to do.
Got you. And just finally is the parent debt to...
Praful, we need to move on. We're running out of time and there are about six, seven more people in the queue to ask questions.
All right. I appreciate it. Thank you, guys.
So please limit your questions to one or two, not five or six.
Thank you. Our next question comes from the line of Paul Fremont with Mizuho. Please proceed with your question.
Hi. Thanks. When you talk about I guess O&M as being a potential driver, I guess, can you quantify sort of the pension benefit that you're assuming numerically? And also, is there any further reduction in O&M beyond sort of the pension?
The way I would look at the pension, Paul, is we probably have an incremental almost $1.750 billion and we're going to get a 7.5% return on that. So, the O&M benefit would probably be in about the $0.15 range. From an other O&M standpoint, we haven't built anything else in other than it would be flat.
As Chuck said earlier, we are really very cost-effective within our utilities. Any cost reductions within those types of rates would have to be adjusted either through the formula rates or else when we go in for any rate proceedings. On the corporate side, we will continue to look at those cost to see if we can offset that $25 million in depreciation that we're assuming from the competitive side that we do not have anything built into the forecast we've given you.
And I know it's been like gone over a lot. But just to clarify on tax reform, you're assuming that whatever potential benefit that would not flow through sort of immediately, you would treat, from an accounting perspective, as a deferral. So, from an income statement perspective, you would not be booking any benefit in 2018 or any of the other years? Is that sort of a reasonable way to think about tax reform in terms of your guidance?
At this point, in our guidance, yes, we don't have any of that benefit baked into our earnings. From a cash flow standpoint, any cash that flows through, it will be upside to us but we don't have anything built into that either in our metrics.
Okay. Thank you very much.
Our next question comes from the line of Michael Lapides with Goldman Sachs. Please proceed with your question.
Hey, Chuck. How are you thinking about the range of potential outcomes from Mon Power in terms of their supply needs? And when specifically are those supply needs really coming to a head?
Well, I think in the short term, Michael, they would just meet any supply needs from the PJM market. And we are reevaluating what we need to do there. In another two years, we'll need to file another integrated resource plan anyway. But we are not planning to take another attempt at Pleasants, if that's what you're asking.
Yeah. I was thinking more in the lines of either new build or acquisition of existing assets that are in the market today but maybe acquiring them at an attractive price for customer and ratepayers?
Well, at this point, as I said it's too early. We're going to go back and sit down, and Mon Power is looking at all the options. They may, at some point, do another RFP, and I'm sure in that RFP, if they do it, they'll address what FERC determined to be shortcomings in the previous RFP, but it's too early to answer that question.
Got it. And then, real quickly, how big of a step-up – and this may be a Jim or a Steve question, how big of a step-up in transmission revenue are you expecting in 2018 versus 2017? Kind of like what are you baking in, in guidance there?
At the low end of our guidance, Michael, we're assuming that we'll spend $1 billion in transmission. At the upper end, we would be at the $1.2 billion range. So I think in 2018 we'll have about a normal increase in revenues, as you've seen over the last year or two.
Okay. I was just checking because you referenced some of the settlements made in JCP&L, and I didn't know if they gave a one-time boost given the implementation of those this year.
No.
Okay. Thank you, guys.
Yeah, I would look at probably from a revenue standpoint, our rate base growth will be about $0.07 in 2018 when you compare it to 2017, and then a little bit with the stated rates in JCP&L, that would be about probably another $0.03.
Got it. Thank you, Jim. Much appreciated. Thanks, guys.
Sure.
Our next question comes from the line of Jonathan Arnold with Deutsche Bank. Please proceed with your question.
Yeah. Good morning, guys.
Hey, Jonathan.
Just on the New Jersey IIP filing, can you give us some insight into what kinds of things you might consider putting in there? Will it be similar to the $450 million program in Ohio, or is this different kinds of components?
Well, we are developing it right now, Jonathan, and it's too early to talk about. So as soon as we are prepared to disclose it, probably, we will.
Okay. So it's not necessarily it may or may not be the same kind of Distribution Modernization stuff to be up. Thanks.
I would say clearly, it will be projects and programs that are designed at improving reliability, improving resiliency, improving safety, security, et cetera, the types of things that the plan was intended for us to try to address.
And Jonathan, just as you may know, the rule itself provides for project eligibility so, obviously, will stay within the parameters of that.
Okay. And then, as we sort of think about scale with the sort of current relative sizes of CapEx in Ohio versus New Jersey be a good place to start thinking about this or not necessarily?
Yeah. I think, it'd be on the order with what we filed in Ohio under the Distribution Platform Modernization.
Okay, great. Thank you. And if I could just on this pension topic, Jim, I just want to clarify the $0.15 you just referenced, is that the sort of bridge between 2017 and 2018?
Yes. That's correct, Jonathan.
And is there any sort of quantifiable benefit from the assumption around slightly lower discount rate that it looks like you're bedding in as you go forward off of 2018 or is that fairly immaterial? I know you do the – your accounting's little differently.
Yeah. There's no benefit associated with the discount rate from an earnings standpoint. But we did, I think, provided a slide and showed what our assumptions were longer term on what the liability would be on a discount rate growing to 4.5%. And if we had to set that discount rate today, it probably already be at 4.25%. So, we think that's a pretty conservative estimate for the liability even.
But that's not driving the earnings guidance basically?
No, no, no. No impact there.
Okay. Thank you.
Thank you. Due to time constraints, our final question comes from the line of Angie Storozynski with Macquarie. Please proceed with your question.
Thank you. And I will literally have one question. So in Ohio, remember we met with the PUCO Chairman and he was emphasizing that your latest ESP included an understanding that the Ohio utilities will be investing in their distribution systems as called upon by the state. So in light of that, how does this $450 million Distribution Modernization plan compare to what this total investment opportunity here is, given what is perceived to be as years of under-investment for the distribution businesses?
The DMR was about $200 million a year. We just filed a plan to invest $450 million of that into the types of programs that the DMR was intended to contemplate. So, I think we are on track to substantially invest everything that they provided for us in that ESP.
Okay. Thank you.
Thank you. Mr. Jones, I would now like to turn the floor back over to you for closing comments.
Okay. Thank you and thanks for your continued support of FirstEnergy. This will end our call. Take care, everyone.
Ladies and gentlemen, this does conclude today's teleconference. You may disconnect your lines at this time. Thank you for your participation and have a wonderful day.