Welcome to the Dominion Energy 2019 Investor Meeting. This is the general session. My name is Ridge, and I lead the Investor Relations efforts here. Thank you all for joining us, both those in the room and as well as those who are joining via live webcast.
Before we begin, I want to quickly point out the exits in the front and in the back. Note that stairwell B is immediately outside the exit nearest stage and stairwell C is immediately outside the exit in the rear. These would be your path of egress in case of a need to evacuate.
We're also
going to ask that folks get their refreshments during the presentation from the back rather than from the area behind the stage. Joining me on the stage this morning are Tom Farrell, our CEO, Chairman and President as well as Jim Chapman, our Executive Vice President, Chief Financial Officer and Treasurer. We're also joined by a number of our senior executive management, which I will now introduce and ask them just to raise their hand as I call out their name. Bob Blue is the CEO of Power Delivery Paul Koonce is CEO of Power Generation Diane Leopold is CEO of Gas Infrastructure Carter Reed is our Chief Administrative and Compliance Officer Rodney Blevins is CEO of the Southeast Energy Group Carlos Brown is our General Counsel Mark Webb is our Chief Innovation Officer Tom Wolfarth is our Head of Regulatory Affairs and we're joined by another of other Dominion team members. We'll proceed this morning with prepared remarks from Tom and Jim, the conclusion of which we'll have an opportunity to take questions.
We'll be posting a copy of the complete presentation on the IR website this afternoon for your reference. For those of you who are looking, it has not been posted. That's purposeful. So you'll listen to us before you'll jump to the end of the deck.
For those of you who
are joining via live webcast, please e mail your questions to our Investor Relations inbox at the e mail address here on the screen, investor. Relationsdominionenergy.com. And a quick technical note for those using the webcast, please be sure you're using the most recent version of Firefox, Chrome or the most recent version of Internet Explorer to make sure you avoid any issues with viewing the webcast.
Before I
turn it over to Tom, please take a moment to review the important note for investors on Slide 3. Our discussion today will contain forward looking statements and estimates that are subject to various risks and uncertainties. Please refer to our SEC filings, including our most recent annual reports on Form 10 ks and our quarterly reports on Form 10 Q for a discussion of factors that may cause results to differ from management's projections, forecasts, estimates and expectations. And with that, I'm pleased to welcome Tom to the Lecter.
Thanks, Steve. Good morning, everyone. Appreciate you coming. It's been 4 years since we
had our last Analyst Day
and obviously quite a few things have changed at Dominion Energy and in our industry for the country for that matter. I was going through some of the slides we presented in 2015 and 2 of them stood out for me to give you to show how far we've come in the last 4 years. 1 of the slides said that we were seeking regulatory approval for our Greenville County power station, which we of course completed late last year and that we reported probably that we were 77% complete on the engineering for the Cove Point liquefaction facility. And of course, that also was completed last year. But today, we're going to talk about the future, where we are today.
But before we do that, I want to give a little context about what we've been doing for the last decade. So just a few minutes on this, what we were thinking, what we actually did, what we accomplished with that, because that's the context of where we are today and why we are today. And I'll give you a few minutes on looking ahead. Jim is then going to come up and give you detailed look at our segment reporting. We understand we've had a lot of feedback about that.
He's going to talk about that. He'll give you a detailed capital growth plan
for each of the business segments for 5 years through 2023. And then the dividend policy we intend to recommend to the Board for starting in 2020. I'll get up then with a few concluding remarks, mention the Atlantic Coast Pipeline. There's nothing new with the Atlantic Coast Pipeline, just refresh you on the milestones. Nothing new since our quarterly call or what's in our Q.
And a few thoughts on our ESG session this afternoon. First of its kind, in the utility industry, certainly, we actually haven't been able to find any company in the United States that's done a session, analyst session devoted to environmental social responsibility and governance issues. It could be another one, but we're quite certain that utilities have not done so. And then we'll be happy to take your Q and A. So 2,007, many of you have followed us that long.
Company was about only 40% regulated revenue streams. 60% came from a very large E and P business, a large merchant generation business. And actually at that time, we had a technically deregulated Virginia Power Generation Business Unit, technically because it was still under price caps that were going to expire in 2010. So the Board decided at that time that we needed to be have a much more regulated content to our earnings streams. And we undertook to do that.
We've completed that process. Most of it was done in the early part of this. But over the last even last year, the last of it has been completed. So there's 3 ways to change the regulated content from unregulated primarily to regulated. You can increase your regulated content, you can decrease your unregulated content or you can do both.
And we of course did both. So we started with $40,000,000,000 of capital investment in our regulated businesses, new regulated power stations. There's a slide I'll show you. They're all captured on that slide. 1,000,000,000 of dollars of electric transmission investment over that period of time, regulated investment, customer growth initiatives, resiliency enhancements.
Cove Point liquefaction, dollars 4,000,000,000 project, the largest single project in the company's history, actually the largest single project in the history of the state of Maryland. We put this under regulated category because we believe regulated like assets, assets that have all the characteristics, particularly financial characteristics of regulated assets should be treated the same way, at least from our perspective in valuing their earnings streams. We also did about $20,000,000,000 worth of M and A in regulated activities, mergers with SCANA and Questar, acquisitions of the Carolina Gas Transmission System and increased our percentage ownership of Iroquois Pipeline, which is a pipeline is critically necessary to the infrastructure in the state of New York, as Con Ed and its customers are finding out in the New York suburbs now. It's nowhere near enough gas infrastructure in New York State, and I don't think there's going to be a whole lot of it built anytime soon. And we also sold $25,000,000,000 worth of unregulated assets.
Now this was largely the E and P business, which was about $22,000,000,000 of this, which we did primarily in 2,008 and then the last of our Appalachian assets in 2010. We sold some merchant generation, obviously as recently as last year and our partnership interest in the Blue Racer Midstream business. So where did that get us? So what it got us to was from 2,006 earnings as we entered 2,007 is $1,800,000,000 in operating earnings, a third of which was from our E and P business. So about $1,100,000,000 if you exclude the E and P business and only 40% regulated.
So as we enter this year, our regulated earnings will be 95% of the earnings stream of the company. If you look at that, include the E and P business, that's 5% CAGR. If you exclude it, it's a 9% CAGR in a tripling of the earnings. Do with it obviously what you see fit. But we have transformed the company from a highly commodity sensitive business to a predominantly overwhelmingly regulated business.
From our
Board's perspective, from our management's perspective, this was a lot of turmoil, lots of change. One of the most gratifying things, perhaps the most gratifying thing for us was we did all this without losing sight of our company's core values: safety, ethics, excellence, we could say 1 Dominion Energy, which means teamwork for us. So we improved in all of those areas as we were transforming the company. Most important to us is safety. I talk about this all the time.
You hear about it from us on our earnings calls. I don't know if other companies do that or not. We talk about it to our employees all the time. First thing I talk about at our shareholder meeting and whenever we meet with the financial community. So this is what we've done.
So in 2000 and 6, we were at 1.87 OSHA recordable rate, which is a rate of injuries per 100,000 folks over the course of a year, about 400 injuries that year. That was pretty good actually in the utility industry, but we didn't think that was very good for us because there in our experience, there's a direct correlation between how what your safety culture is in your company and the excellence of your operations, the culture of the company, both how you treat your fellow employees and the communities we serve. So we concentrated on that. We've improved our safety performance over that period of time by 70%, and our OSHA recordable rate is half of the peer average. And the peers we're using here is Southeast Exchange, which is the large fully integrated utilities in the Southeast United States.
Excellent operators, all of them. Excellent safety performance, all of them. But to get to where they are on average compared to us, you have to go back to 2010 was the last time that we had a safety OSHA recordable level at what our peers is in the Southeast. It's very important to us and we hope it's important to you. Ethics to us is obviously we have all these rules and regulations that we have to comply by and we take that very seriously, both the spirit and letter of those laws and regulations.
But that ethics to us is much more than that. And it's really what today's the afternoon session is about today. Is how we interact with communities we serve, where we live and work, whether it's in the environment, people we do business with, the communities we serve, philanthropy, etcetera. So for us, I just have a few examples here on ethics. You'll see much more of that this afternoon, a couple of hours of it this afternoon.
But over that course of the last 10 years, almost 1,500,000 volunteer hours by our employees, about a third of a $1,000,000,000 worth of charitable giving over that period of time, 60% increase in spend with diverse suppliers. This is something we look at very carefully and seriously. We're monopolies. The communities we serve have to pay us and it's very important to us that we give back to the communities in the way they give to us. And about a 50% reduction in carbon emissions over that last 10 years, last 12 years.
You've seen a 50% number before and you'll see that again later today. That goes from the slightly different time period that starts in 2,005. But this is twice the industry average. Okay. I know people don't think about Dominion very much in that context.
That's part of what this afternoon is about. We've reduced our carbon emissions, both our rate and actual tonnage of carbon emissions by twice the average of our industry. Excellence, I could give you all sorts of examples here, but I just thought I'd give you a chronological display of some of the things that we've done over the last 10 years. This is the Virginia City Hybrid Energy Center. It's completed in 2012 on time and on budget.
Warren County, at the time, one of the largest baseload gas fired power plants built in the United States on time and on budget, followed quickly by Brunswick, even larger. We completed the purchase of the Carolina Gas Transmission System. Questar merger occurred in 8 months. The Grid Transformation and Security Act was adopted by the Virginia General Assembly in 20 18 session. Cove Point, which I mentioned earlier, was completed in 2018, commissioned or at the end of 2017, commissioned in 2018.
Greensville County was completed last year. And then of course, the SCANA merger at the very end of last year as well. Lots lots of examples here. None of it would have occurred without our 4th value teamwork. And you can see here, I'm not going to go through all these with you, but none of this would have happened without an intense collaboration across all parts of our company, helping each other out to get all these things accomplished over that period of time.
Lots of it having to do with customer benefits, including the Grid Transformation and Security Act, which sets a template for improving service to Virginia our Virginia Power customers over the next decade. And Millstone, saving the Millstone power station, not only the employees jobs and communities there and their families, but the state of Connecticut. This produced over 90% this plant produces over 90% of Connecticut's carbon free power and half of its power, critically important to the state. Pleased that we could work that out with the governor and the local utilities there. So this all culminates in 2018.
2018 was turned out to be a fairly choppy year, you may have noticed, choppier than we had anticipated. Although some of it was self imposed for certain, we announced the SCANA merger on the 1st business day of 2018. It turned out to be quite a noisy proposition over the course of the next 9 or 10 months. And then in the middle of March, I think it actually was on the eyes of March, FERC issued its decision on MLP financing structures, which eliminated 40 years of precedent at MLPs with MLPs and necessitated that we completely rejigger a financing plan that had been 5 years in the making to finance the construction of Cove Point. So despite all that noise and all the things that were going on, new General Assembly in Virginia, brand new Governor, we set a new safety record, OSHA recordable safety record.
We increased earnings 12.5%, pretty good for a utility company, 10% dividend per share growth, actually did complete the SCANA merger. Grid Transformation Act was passed. I'll talk a little bit more about that in a few minutes. And then we had to redo our balance sheet. A dramatic change to ensure that we maintained our credit ratings, which we are deeply committed to and will continue to be.
Sold $2,500,000,000 worth of non regulated assets, reduced parent level debt by $8,000,000,000 and then, of course, got our ratings affirmed. So where does that bring us today? That's the context, where we were, why we were doing what we did. That brings us to where we are today. So mission was accomplished, 40% unregulated earnings to 95% regulated earnings over the course of about that decade.
So where are we today? Well, we're going to break this into segments for you and Jim will talk more about the reporting of that in a few minutes. But it starts with the core of the business, which is 65% to 70% of the earnings streams, which come from state regulated local utilities. State regulated local utilities in 5 states primarily, we're of course in 2 or 3 other states, West Virginia, Ohio Wyoming and Idaho. But if you start the primary states that we do business in for your purposes for financial purposes are Ohio, Virginia, North Carolina, South Carolina and Utah.
And the assets you see there are these fully integrated electric utility in North Carolina and South Carolina, here and here. The fully integrated electric utility, as I said, I said, it's out in Virginia, North Carolina. And then in South Carolina, the local gas distribution companies in North Carolina, Ohio and in Utah tracking down the I-fifteen corridor, 65% to 70% of the company's business. Then those are premier assets, we believe, in premier states for regulatory purposes. So if you look at the ratings that folks give to utility commissions in Virginia, North Carolina, South Carolina and Utah ranked in the top 20%.
Ohio topped 50%. But if you take a look at the fact that we're just natural gas there, Ohio is ranked easily in the top 20% for its gas regulation of local gas distribution companies. Electric, they've got the deregulation going on in Ohio, makes it a little choppy there. So 65% to 70% of the earnings from premier assets, we believe, in premier regulatory states. What's next?
25% to 30% of the earnings come from FERC regulated or regulated like gas transmission and storage. I'm going to spend a few minutes talking about this in a few more minutes, because we're not this is largely our responsibility, no doubt, about the way it's been reported to you financially and the way we've talked about it. We haven't talked about it enough. It is quite a bit different, this set of assets than a typical midstream set of assets. And I know that often, when we look at some of the parts analysis that they say, hey, those assets' earnings should be just compared to some other basic midstream assets.
They're quite different, at least in our view. You will obviously make up your own minds. But you see here, this is about 110,000 miles of pipes, varying sizes across these jurisdictions you see here, in their very important regional hubs. And I'm going to talk about that in a minute. But if you pay it's important to notice all the gas storage, these green dots are gas storage facilities, a 1,000,000,000,000 cubic feet of gas storage in this one region.
We own or operate about 60% of the storage in the mid Atlantic region. These pipelines, you can see, it goes up into New York State. I mentioned the Iroquois pipeline, which is this one here. So 1 third of New York State's gas, about goes through this pipeline system, onethree goes through this pipeline system. It's critically important to this region, South Carolina and the Utah region.
I'll talk about those again in a few minutes and what we mean by FERC regulated and regulated like. And then finally, we got to work on the name of this segment. Contracted Generation is not very exotic sounding, But it's largely, not largely, it's entirely the Millstone Power Station, now 55% under contract to local utilities and the balance is our contracted solar facilities you see across the country, all of which are under long term contracts to local utilities. So that's a little bit under 10% of the earnings, closer to 7%. So what's that give you?
It's a national regulated energy infrastructure footprint, 21,000 employees, about $100,000,000,000 worth of assets, which we believe, after all the winnowing, the additions and the subtractions are best in class and they operate at that level. So here's the asset base that we have today when you put it all together. We thought it was interesting, you may not, to contrast that with 2000 and seven's assets. In addition to having a little bit better graphic capability today than we had in 2,007, this is actually taken from an investor slide. And you see we have all these E and P assets out here in Canada and Gulf of Mexico, Permian Basin, heard of the Permian Basin, I'm sure.
Our largely coal driven merchant power fleet in the Midwest. That was the Kewaunee power station there. And really just one regulated utility that was twothree of which almost was in a deregulated mode because of Virginia deregulation. And this is my favorite, our LNG import terminal that we had in Cove Point in 2007. So we went from that to this, in that about a decade period, dollars 60,000,000,000 market cap or so, about $100,000,000,000 worth of assets, 7,500,000 utility customers, you see that broken down.
We have a few more than that. That includes not the utility customers, that includes our gas retail customers, dollars 3,500,000 electric, dollars 3,300,000 or almost 3,300,000 gas. This is about 100,000 miles of electric lines in Virginia, North Carolina and South Carolina and 110,000 miles of pipelines in the regions I saw you. Lots of local gas distribution companies, I'll show you a slide in a minute, 6th largest LDC company in the United States. 6th largest LDC company in the United States is Dominion Energy, when you put these assets together.
About 31,000 gigawatts of power plants, a third of which are carbon free. So that's the Dominion Energy of today. And the reason why we have them is because of the nature of the earnings streams and revenue streams. Premier state regulated assets, we believe premier critically necessary gas transmission and storage assets to the economies they serve and then our contracted generation business. Just a slightly different slice on this is how these compare to others in the industry.
We're not number 1 in any of these categories, obviously, but we have very large scale in all of them, very large scale in particularly in gas and electric infrastructure. Others are following suit. I'll show you that in just a bit. But we started down this path 20 years ago. This is going to be an extremely difficult set of assets to replicate for anyone else because of where they're located and how they came together.
So I want to spend let's look at it slightly different way. 95% of the earnings, cash flows, revenues are regulated or regulated like. This is our 2020 operating earnings. You get a full year of Millstone with its contract in 2020. It's why we're looking at that year.
It falls into these 3 categories, state regulated, FERC regulated. So what does that mean exactly? Well, state regulated, pretty straightforward. Virginia and North Carolina, fully integrated electric utility, one of the largest in the United States in a very good fair regulatory regime. 100 percent of the end use customers are utility customers, 100% of the customers end use utility customers.
South Carolina, fully integrated electric utility, 100% of the customers fully regulated. Gas LDCs, in 7 states, 100% of the customers are utility and use customers. So FERC regulated and regulated like. So the pipelines and the storage, gas transmission, gas storage. Actually 100% of the gas storage is under FERC regulation across our system.
And the vast majority of the gas transmission system is under FERC regulation and the end use customers are in almost entirely they are entirely in the storage business, almost entirely in the gas transmission business, end use utility customers because the customers of the gas transmission business, local gas distribution companies and electric utilities using the gas transmission to get fuel to their gas fired power plants. Very differentiating factor from most midstream companies. I'll come back to that in a minute. And then Cove Point. We qualify Cove Point as regulated light, because it has 20 year take or pay contracts, 19 years to go.
So we got a ways to go on those contracts, 19 years, 20 year take or pay. And where does the gas go? It goes to a local gas company in India and a local gas company and electric utility in Japan. It's the equivalent for a regulated customer in the United States. And then other, contracted solar.
Where do those revenues come from? They come from electric utilities. 100% of the revenue streams come from electric utilities. Ultimate end use customer is a utility customer. Millstone Power Station, you see the little half moon slightly more than half moon, 55% of that is now under a 10 year contract to 2 local utilities in Connecticut.
And then we have our gas retail business, which is entirely unregulated. It's very small now part of this business. So we start with premier assets. We believe they are in premier states, 65% to 70% of the earnings, FERC regulated, almost entirely FERC regulated, a little slice of the gas transmission business is not. But they go to end use customers and then Cove Point contracted solar in Millstone.
So I'm going to spend a few minutes talking about that middle block, which I mentioned a minute ago is it's often compared to other midstream businesses. This is not in other midstream business. We hear referred to as that way. So I just want a couple of handful of slides to show you at least how we view the differentiation. So traditional midstream, I saw a big banner walking in here.
So Oasis is ringing the bell this morning. And if you look at the kind of assets Oasis has, they fall right into the asset base of these traditional midstreams have. We just put up a couple of examples here, Williams, Kinder Morgan and EQM as examples. So what is their asset base? Well, it's gathering and processing a lot.
Most of them have about a third of their earnings come from gathering and processing terminals, lots of liquids pipelines, either oil or propane or sometimes ethane, etcetera, and gas pipelines. We are 100 percent gas pipelines, 100 percent gas storage, and our LNG facility that we have is 100% LNG export with creditworthy partners. They're really utility customers. Commodity exposure. Traditional midstream businesses have they're all about commodity exposure.
Often they will talk about how that's a positive for them depending upon the environment that they're in. They have it both in volumetric ways, indirectly and directly in price exposure. Volumetric exposure, if oil prices are low, you have a big gathering and processing business, your revenue stream is going to be low because there's going to be less to process. We saw that with our Blue Racer asset. De minimis exposure for us.
Customer profile, almost entirely supply side push in our customer base, it's demand side pull. Another way to look at this is midstream assets traditional midstream assets are almost entirely built for producers. They're built and operated to benefit producers. Our assets were built and they're operated to benefit customers. A very important contrast in the nature of the revenue streams that come into these two types of businesses.
Key drivers, management teams at Midstream Businesses are often talking about what's the price of oil, what's the price of NGLs, what's going to happen with gas, who's drilling, who's not drilling, where are they going to drill, what are the frac spreads. We never talk about that. That's just not something we sit and talk about. I don't have screens in my office that show what's going on with gas prices and frac spreads and basis differentials.
Doesn't mean
there's anything bad about that. Just that's not what drives our business in our gas transmission and storage business. What drives our business is what is the long term utility demand going to be? What about decarbonization? Who's going to need to close coal plants, replace them with natural gas plants?
That's a perfect example of what the Atlantic Coast Pipeline is about. It's about decarbonization. The largest customers are Duke, who is going to use it to close coal plants and then serve Piedmont, the old Piedmont and our base in Virginia and going up into Tidewater, Virginia, where they are tapped out in capacity on existing pipelines. Very different mindset. And then barriers to entry, if you want to add gathering and processing, that's very easy to do, very easy to do.
We did that frequently with our share of Blue Racer, just as an example. Permian Basin, you want to build a pipeline in Permian Basin, relatively easy. Look and remember where our assets are. A third of New York State's gas goes through our pipeline. I don't think there's going to be a new pipeline built in New York State anytime soon.
Our gas storage, 1,000,000,000 cubic feet of gas storage. Have you seen big dramatic announcements about increases in storage capacity in the Mid Atlantic or New York State or Pennsylvania, etcetera. These are scarce resources. And the importance of that is the certainty of the revenue streams. We're not going to have runoff from customers using these assets.
Another way to look at this is, 90 our asset base 90% plus is firm service revenues. Firm service means it doesn't have volumetric risk or commodity risk. We only have 1% of our earnings stream comes from gathering and processing in our Gas Transmission and Storage reporting segment. Typical Midstream has almost 2 thirds comes from only twothree from firm service revenues and about onethree from gathering and processing. Between the two, there's quite a contrast in the certainty of the revenue streams and the transparency of the revenue streams for years to come.
So now I want to take now just look at our where these assets are, in the which the special nature of them. Where they are is you'll see in a minute, the local electric and gas utilities literally cannot serve their customers reliably without these systems. That's why they were designed, built and that's why they're operated today. So look at the where we started with consolidated natural gas, merged almost 20 years ago we got into this business. And that gas business is almost 10 times larger today than it was when we merged with consolidated natural gas.
And you've got important part to notice here obviously is this network of pipelines. It's not a straw. These transmission assets are not a straw from a producing basin. They're not a long haul pipeline coming from the Gulf of Mexico, worrying about basis differentials. This asset was designed originally and it's the way it operates today to be a regional hub network for local gas distribution companies and increasingly electric utilities.
The gas would come in on long haul pipes from the Gulf of Mexico and from Canada, enter our system, come through our system, go into 1,000,000,000,000 cubic feet of gas storage and then come out in the wintertime, go to the local gas distribution companies, repeat the cycle. That is increasingly becoming also coming out of storage in the summertime as you get more and more gas peakers and baseload gas, particularly in the PJM region. This is going and if you look at the customers shown here, Dominion Energy Ohio Dominion Energy West Virginia, affiliates of ours Nashville Grid Eversource, local gas distribution companies who absolutely rely on this pipeline to get their gas and serve their customers. Very, very difficult to replicate, critically important to their neighborhoods, built for customers, operated for customers. So when we look to expand this network, we wanted the same characteristics.
We didn't want to buy a long haul pipe. Rockies Express is a good example of a pipeline that had a very bright future. I'm sure when it was built, things changed dramatically, impacted the value of that pipeline. Very well run, I'm sure, very well thought out originally, I'm sure, but the base is all of a sudden, we have all the shale gas shows up in Marcellus and Utica. That has dramatically changed the game for others, not for our assets.
So how do we duplicate that? We find the same structure elsewhere and we find it in the Rocky Mountain West. The old Questar system is exactly the same system built for customers, not for producers, built for customers since pipeline network get gas from the Rocky Mountains into the fastest growing state in the country, Utah. And you see the local gas distribution company tracks down Interstate 15 for those of you been to Utah for recreational purposes or others. 85% of the population lives within 100 miles of Salt Lake City and that's increasing.
You cannot operate the economy of Utah without this pipeline system operating properly, the same with the storage. And where else do you find that history purpose duplicated? In another regional hub system, which is the Carolina Gas Transmission System, gas comes in to these entry points and then is redistributed to the local gas distribution company, not quite as much to PSNC, quite a lot, almost entirely to the customer there at South Carolina, formerly South Carolina Electric and Gas. So very different pipelines, transmission and storage nature of them built for customers, not for producers. One anecdote that might show this to you is on our peak throughput days on this system, over half the gas is coming out of storage, not coming off of a long haul pipe.
That's how much the local gas distribution companies rely on this system. If we didn't have that storage there, half of what we produce, half of what's delivered to the customers would not be available. Very different nature to it. So why are the largest companies utility companies in the United States embracing scale in electric utilities, gas transmission and storage. And these are companies among the largest in the United States, obviously.
Berkshire Hathaway, people don't think about Berkshire Hathaway Energy, I don't think so much because they're thinking about big Berkshire Hathaway. People ask us sometimes ask me what company is most like you? And actually, I believe it's Berkshire Hathaway Energy flipped in the West. Very large gas transmission system. Now they have some long haul pipes unlike us.
Ours are all 3 of our systems are all regional hubs and electric utilities on scale, mostly flipped into the Western State part of the United States. Sempra Energy, long time operator of gas infrastructure, relatively small electric utility in Southern California now bulked up on their electric utility by when they bought Encore. DTE Energy, you're familiar, they've been doing quite a bit with gas transmission. NextEra is moving aggressively into the pipeline business. Duke Energy bought Piedmont.
They are our partner in the Atlantic Coast Pipeline and they have other pipeline assets. Southern Company bought Atlanta Gas Light and they're buying interests in pipelines. So why is this happening? In our opinion, 2 different broad reasons. 1 is sort of traditional utility risk mitigation.
Don't put all your eggs in one regulatory basket, simple way to put it, or one public policy regime. Think California on one public policy regime. You might think SCANA on one regulatory or public policy scheme. Spread your risk out among different places. That's a traditional reason for electric utilities to branch out from their base core operations in their home states.
Large projects, it helps you weather the storms of large projects to be larger. And climate related impacts, obviously, are impacting all of us. I think this is the primary reason, and I think this is going to continue for decades. Gas infrastructure is becoming or you may you could argue has already become foundational to the future of electric utilities. As decarbonization increases, utilities have done a lot.
We've done twice as much as our peers, not all of them on average, twice as much. But there's a lot more to do here. But the real decarbonization coming in this country is going to come from the transportation sector. It's coming. You can watch the big car companies, the ones that actually know how to make cars, are all going all in on electric and hybrids.
You see it coming. It's going to decrease the cost of electric cars and hybrids as we go into the next few decades. But and there's also a push, a huge push obviously for renewables for the same reason. Our customers want more renewables. All of our polling shows that.
Most of our policymakers, not all, most of our policymakers want more renewables on our system. We can accommodate that. Utilities can accommodate that. So you're going to see 2 things happening. 1, reduction, decarbonization of our electric utility industry has led to the closing of coal plants.
We've closed more than a dozen coal plants, replaced them with you saw Bear Garden, I don't think showed Bear Garden. Bear Garden was on there, Warren County, Brunswick County, Greensville County, very large baseload gas fired power plants. And then as more and
more renewables come on these systems,
you'll see this especially in California already. The intermittency of the renewables is going to require battery storage, storage at scale, does not exist today. You know that as well as I do. I don't personally don't think we're going to see it anywhere in the near term. I don't think we're going to see it in the midterm at scale.
There's only 2 effective ways to deal with the intermittency of renewables. And it was either Stanford or Berkeley professors about 6 months ago wrote an article about the only way California's lights are staying on, guess what, gas infrastructure. It's the only way California's lights stay on. So as we see more and more of this, you're going to see the 2 ways to store. Pump storage, we own and operate the largest pump storage facility literally in the world in the Virginia mountains.
And you'll see when Jim gets up that we have a plan to build more pump storage in the Virginia Mountains. They want it very much where we are. And gas peakers, fast start peaking plants. And the only way to do that is to have more gas transmission infrastructure, so the gas is available as the clouds come through and your solar farms start closing down, peakers through our gas transmission systems, which is going to lead to more gas transmission and certainly more valuable gas transmission and storage. Electric utility companies, understandably, are very concerned about reliability.
That's our lifeblood. It's what our customers depend on. The economies we serve depend on it. They want to own and operate electric transmission because that's absolutely necessary for the reliability of the grid. As we become more and more integrated with gas transmission and storage, providing the fuel of source, you're going to see more and more,
in my
opinion, electric utilities wanting to own and operate that critically necessary method of getting the fuel to their power plants. It's a different fuel than we've ever had before. Years ago, it was oil. You can deliver oil in a variety of ways: truck, boat, pipeline. Ours was largely delivered by trucks in Virginia when we had oil.
And then coal, if you get concerned about there might be some interruption in your fuel supply, you just put another 30 days pile on the put 30 more days on the coal pile. You can't do that with gas. You can't do that with gas. It's got to be there all the time. 50% of our throughput in the wintertime on our pipeline system comes out of our gas storage that we operate.
It's critically necessary for the reliability of these systems to have that available. I think you're going to see them like with electric transmission, wanting to own and operate gas transmission. I think that's why you're seeing all these large companies increase their investments in these areas. Competency and scale, you may have noticed that the permitting is getting a little difficult with gas pipelines. So you need a lot of experience with this.
You have to have a lot of fortitude and patience with this and you need scale.
So I think there's going
to be winners and losers in this as we go into the future. You're going to have to have capital access, cost and flexibility. Now this slide could show up in a futurist deck. We put it into our deck. And let's just I'll show you what these numbers are.
You put any haircut on this you want, obviously. But today or 2015 when this study was finished, 21% of the energy end use in the United States was electricity. Just think about that. Only 20% was electricity. It's gasoline, it's oil, it's natural gas, heating homes, businesses, etcetera, 21%.
You may have seen a couple of weeks ago, Shell at the CIRA Conference used very similar figures and they decided they're going to be the biggest producer of electricity in the world by I don't remember what year, 20 something, 50, 30, 2030. They got a lot of catching up to do, but they're big. So what's going to happen? These studies say that by 2,050, you're going to be almost 50% of the end use energy use in the United States is going to be electricity. And that's going to be driven by transportation sector going through decarbonization.
There is an enormous amount of electricity usage that's going to grow in this country over the next 2 or 3 decades. So put whatever haircut on you want on this. If it's only half, let's say it's only half, still 25% increase in electric demand over that period of time. Where is the electricity going to come from? New nuclear plants?
I don't see any hands going up for that. New coal plants? I don't think so. It's going to come from 2 sources: Renewable energy, supported by natural gas peakers, and it's going to come from more baseload gas, which is going to set necessitate an increase of somewhere from 20% to 40% in natural gas usage. Much cleaner than coal, obviously.
This is something that policymakers are struggling with. I absolutely understand the struggle. The physics here don't lie. The chemistry, which is how you store electricity, does not lie. It's not happening at scale in the foreseeable future.
So we're going to need to deal with the electricity transformation of this economy to less carbon by going through by doubling down on natural gas, in our opinion. You put whatever haircut on this you want. By the way, when Jim gets up, you're not going to see any little cars show up in the 5 year capital growth plan, okay? So we don't have any capital growth built into our model for the next 5 years based upon what we see is an increasing utilization of electricity use across the country as its end use grows. Okay.
Looking ahead, few slides here. A preview of this afternoon. I hope many of you will come to this. I think you'll find it very interesting. We're going to talk about our sustainability and innovation initiatives, environmental commitments and disclosure, our approach to engaging our communities' employees and what we believe is the best in class governance policies.
This is just one example of one of the things we're doing. Now you may have seen, I rattled off our 4 values earlier for you today. We have adopted a 5th value, which we did last fall, which is embrace change. And I'll talk about that this afternoon in more detail. All of our values have internal components and external components.
The internal component of Embrace Change is embracing the diverse nature of our workforce and the increasingly diverse nature of our workforce. Very carefully chose the word embrace, didn't choose accept change, tolerate change, guess you'll have to put up with change. It was embrace it. It makes all of us stronger. But we also have to do with all the changes in technologies that are happening out there, what's happening around us.
We need to know what's happening, see past the horizon. So we have our innovation team, Mark Webb will talk this afternoon, 3rd party technical advisors, senior management together form this Innovation Technology and Sustainability Council, which I chaired, reports to our Board of Directors and it's overseeing a variety of things and this is just one example. There are 15 blocks on here. You see the top line has 5 blocks. The bottom line says Project G through Project R.
Those are not placeholders. Those are projects. We have Sprint teams working on each one of these projects from all different parts of the company. We haven't put the other 10 on there and by the way there are scores of others. We haven't put the other ones on here because we some of these are pretty interesting and we just don't want all of our colleagues in the industry to know exactly what it is we're looking at.
Behind the meter, you're very familiar with that obviously. Solar, we're looking at all types of solar, community solar, utility scale solar, rooftop solar, Offshore wind, you're quite familiar with electric vehicles. How do we help our customers with electric vehicles? We'll talk about this this afternoon. If you look at our website, we just put on an app on our website.
I think it's an app technically, I don't know what it is. Technically, it's an app. Okay. It's an app. It allows you to look at what kind of car you have today, miles you drive.
If you converted that to electric and used our clean energy as the basis of your fuel source, what would happen to your personal carbon footprint? And you will see that you're going to personally reduce your own carbon footprint dramatically by changing over to an electric car. And it also has our rates in there and you're going to see a very dramatic cut in your cost of fuel in electric fuel by going to R, which we have, which is one of the lowest rates in the country. One example, that's up on our website if you want to see what your own carbon footprint is this afternoon. RNG, Renewable Natural Gas, we'll talk about that this afternoon.
That's our partnership with Smithfield Foods to capture methane gas from pig waste, convert it into natural gas that can be burned at home. So it converts it from methane, which is 20 times more powerful than carbon, takes the methane out of the air and converts it to carbon dioxide. And then marine LNG, you will hear more about that in the future. Now last piece before there's one other slide before Jim comes up. I mentioned this at the beginning.
These are the basic reporting segments we've had for most of 20 years. It's been a little different. Power delivery at one point we called it Dominion Distribution. It had LDCs and electric wires, small wires in it. We've had generation and pipelines together in different parts of time.
But basically, this is the structure, largely driven by the Generation Business Unit because we had regulated businesses a business in Virginia and we had this very large unregulated business, we wanted to make sure that we combine the operational excellence of the utility with the commercial instincts of the merchant operators. So they blended that thought process to be what we believe is among I know it's not I believe. It is among the best operating, highest efficiency, highest performance of any generation fleet in the United States. That has worked extremely well for us from an operational standpoint, but of course, you have to report as you operate. We have heard for a number of for years for many of you that, that makes it a little opaque.
It's not done on purpose. It was done because we wanted these operational efficiencies. Southeast Energy Group, we've added, and we've left that as a standalone business segment. So those operating segments are going to change, and Jim is going to take you through the detail of that in just a minute. So key investor themes for you, premium low risk assets and premium locations, primarily 5 regulated states, regulated and like growth programs.
You're going to see from Jim's presentation that 100% of our capital growth plan over the next 5 years goes into this 95% of the earnings stream, which is regulated assets. We have scale and diversity regionally and in businesses, the sustainability and innovation culture of the company, you're going to see the clarity and accessibility here in just a minute. We'll bring you to a balanced long term shareholder return for yield and growth.
And with that, I'll turn it over to Jim. Thanks, Tom. Good morning. I'm going to share this morning information on how and how much Dominion is going to grow its business in the next 5 years. I'm going to do that in 3 parts.
First, as Tom suggested, I'm going to talk about the way we organize and present financial information regarding our businesses. And we're making a change in that area in the hopes that a new style will be will make it easier to understand and easier to understand the growth prospects for each of our business lines. Next, I'll talk about our growth outlook by segment, which is our capital investment plan over a 5 year horizon, which is $26,000,000,000 in regulated and regulated like asset classes. And finally, I'll share color on our consolidated financial outlook and drivers and do a recap of our long term earnings per share growth rate, which is unchanged. So first, on our operating segments.
Tom and Steve and I over the last months have been listening closely to you and feedback on the way we present our financial information and our segment reporting, as Tom mentioned. And we get it that the way we do it, although it has served the purpose internally in operational excellence, it makes it difficult for you to understand, to model and maybe even to value the individual components that make up Dominion Energy. So we're making a change in response to that feedback. We understand that the way we do it now doesn't provide or what we hope to have, which is easily acceptable, clear and transparent financial information. We've decided to make that change.
I'm going to walk through the new segment structure right now. But keep in mind, we are after all in the middle of integrating the SCANA merger, which includes integration of various accounting systems. So this change to a new operating segment structure and our accounting statements will not be immediate. We plan to achieve that by the time of the 2019 10 ks, so published in February 2020. And in the interim period, between now and then, we'll begin to migrate and provide information in the Investor Relations space, reflecting the new structure where possible.
So what is the new structure? So here they are, 5 operating segments. 1st, premier consolidated vertically integrated electric distribution, transmission and generation utility in Virginia and North Carolina. This maps effectively to the legal and financing entity that is VEPCO, under which we do business as Dominion Energy Virginia. Next, Dominion Energy Gas Transmission and Storage.
This integrated service offering that Tom just described of gas transmission and storage supplying primarily to utility end use customers in our regions and Cove Point, which serves other end use utility customers outside of our region. Now the next business segment we talked internally about announcing the 6th largest LDC in the country, as Tom mentioned. And we wondered whether that was going to confuse people about maybe we're announcing an acquisition, which we're not. But it is the 6th largest LDC, Dominion Energy Gas Distribution. These existing states you're familiar with.
The inclusion, of course, of PSNC, very nice utility business that was part of SCANA Corp. Previously. Given the affinity between these last two segments and the integrated nature of the service offering from transmission storage to gas distribution. We're providing financial information on a purely segmented basis, given the affinity between the groups, they are managed by a single business unit CEO within Dominion. Next operating segment, Dominion Energy South Carolina, which is not the same as the SCANA assets.
It's one of them, the largest. This is the integrated distribution transmission generation and gas distribution utility in South Carolina. This maps to the legal entity SCE and G. Two quick things there. I mentioned gas distribution, which is within this entity managed on an integrated basis, 300,000 gas distribution customers.
So that's outside our gas distribution segment in SCE and G in Dominion Energy, South Carolina. And the other thing is, we're in the process of changing the name of the legal entity, SCE and G. So as of about a month from now, SCE and G will be renamed Dominion Energy South Carolina. But again, the financing is key and the operating segment will map to each other and align. And then finally, Dominion Energy contracted generation, which as Tom mentioned is Millstone and a little bit over a gigawatt of utility scale solar we have in our long term PPAs to utilities around the country.
So these are our operating segments. Look out for increasing financial information shown on this basis this year and it's transitioned to formal reporting on the segment basis at the time of the 2019 10 ks. Now I'm going to walk through each segment and talk about our growth outlook, reflecting the new segment structure And growth for Dominion, growth for the new style Dominion is no longer based on things like spark spreads, frac spreads, E and P drilling, IDRs, not our style anymore. So growth here is really driven by one thing, which is capital investment on behalf of our customers and our utility businesses across the country. So this discussion is going to be very focused on that $26,000,000,000 of growth capital and rate base I mentioned.
Now, 5 business segments, quite a bit of spending across multiple programs. I can't possibly go through it in detail in the time we have this morning. So following today's presentation, we're going to make not only these materials available, of course, but we'll also make available an appendix, which will constitute kind of a reference book that will provide more granular detail on every program I mentioned in summary form, which will allow you to understand it on a more granular basis and for your teams to model it and etcetera. So the first segment Dominion Energy Virginia, as we look at these in size of contribution to our net income. 1 of the largest and one of the premier electric utilities integrated electric utilities in the U.
S. And growth specific there across the top. Very strong regulatory framework for Virginia, has been for a long time, continues to be. Most recently evidenced in this GTSA, Grid Transformation and Security Act from early 2018, which set out long term path for sustainability and supply of resilient energy in Virginia and also set a visible path to capital spending on behalf of our customers that I'm about to walk through. Now the robust growth across customers and capital spending that we expect in the future in Virginia has also, as you know, existed for quite a time.
So for the last 10 years, think of the programs we've had to spend on behalf of our customers across transmission and distribution undergrounding and a number of generation riders in Virginia. So let's think of let's pause for a minute and talk a little bit about what that has meant for the customer bill and what we expect it to mean in the future for the customer bill given the continued pace of capital spending. Here we show what it has meant for the typical monthly residential electric bill in Virginia, 1,000 kilowatt hours per month. With all the spending in the last 10 years, that is reflected here. Since 2,008, the average customer bill has grown at a rate that's less than half of U.
S. Inflation. So it's good regulation, good project execution and it's good cost control that achieves these results. That's the last 10 years. So where does it bring us to today?
Here we have the U. S. Average typical bill $140 the South Atlantic average $122 You can see there that Dominion Energy Virginia and the smaller part that's jurisdictional in North Carolina has typical customer bills that are 20% below the U. S. Average and 5% to 10% below that regional average.
So again, good regulation, project execution and cost control. For the next 10 years, I'm about to walk through a number of spending programs. After giving effect to all of that. What does it mean for the next 10 years? We still expect customer bills to increase at or below the U.
S. Inflation rate in the next 10 years, properly prudently managed. So what are these spending plans? And the first is probably the best example of what we talk about in Dominion terms of a transition from projects or even mega projects to programs. And the largest project in our history, and Tom mentioned it, Cove Point export, dollars 4,100,000,000 completed, as you know, about a year ago.
Our transmission spend alone in the next 5 years is greater than the largest projects in our history, dollars 4,300,000,000 between 2019 2023 recovered FERC formula rates recovered under rider and Virginia legislation. Maybe I'll pause here for a second since the FERC was nice enough to make some announcements last week about a notice of inquiry regarding rates on these kinds of assets, which we'll all be watching. We don't have inside baseball on what that will mean. But we are comfortable with our current rate, which is 10.9% ROE. There's a 50 basis points adder due to its membership of an RTO participation in RTO.
But just as an example of what that would mean, the notice of inquiry, we don't expect change, we're comfortable with where we are. But if that 50 basis point adder were to disappear, and we don't expect, but just hypothetically, that would be somewhere less than a $0.02 earnings per share impact to Dominion. So we're watching closely, but not a major issue. The next spending program in Virginia is one of very significant political importance, where we've made a very sizable commitment, a material commitment, and that is in solar generation, where we've committed to by 2022 have 3 gigawatts of solar in operation or under development, Very significant spending, very significant level of importance to the policymakers and political leadership in the state. That spending will be recovered in various ways under rider, some in base rates And as set up in the legislation, a portion of it will be in the form of PPAs to non jurisdictional customers, counting those PPA megawatts as meeting the 3,000 Megawatt commitment by 2022.
So $2,400,000,000 and $1,300,000,000 Customer growth, new customer connects, service upgrades or blocking and tackling reflective of what we continue to see as strong customer growth in the state. Some of this is reflective of data center growth, where in 2018, we connected 18 new data centers, and we expect in 2019 to have roughly the same, if not more. And data centers, the trend in that area is larger in addition to the continued growth in numbers. That is base recovery. Grid transformation, a number of items fall into this.
Our AMR program, customer information platform, a number of intelligent grid devices and related technologies. This is actually $3,000,000,000 of capital spend over the next 10 years. $1,600,000,000 is an amount between 2019 and 2023. And some of you may recall or say, wait a minute, we thought you had made an application here and it was denied, which is not exactly true. We did apply for about $800,000,000 of this capital for the 1st 3 years and $100,000,000 of O and M.
Some of that was approved by our permission. Some of it was denied without prejudice with kind of a road map for us to resubmit the application, which is in process. So this $1,600,000,000 of capital is reflective of the timing of that resubmittal of approval for the 1st 3 years of grid transformation spend. But here maybe I'll just pause and say that I provided here these capital spend numbers for this 5 year period for these programs, But note that all of these programs have capital spend authorized in law that extends beyond the next 5 year period. So these and others I'll come to actually extend well through the next decade.
Next, nuclear relicensing, another example of that, dollars 1,200,000,000 We have 4 nuclear reactors in Virginia in rate base. This spend is reflective of the anticipated capital need related to the extension of the license of the Surry plant, which is 2 units, from 60 to 80 years, application already pending with NRC, expect approval of that next year. So that's replacement of generator, digitization of controls, etcetera, to support the extended life of Surrey. In total, the spend we expect to be $1,000,000,000 per unit, again 4 units, $1,200,000,000 of that in this time period and the remainder following. Offshore wind, dollars $1,400,000,000 of this is already in process and approved by the commission, pilot project.
The remainder is the next stage, which is a 500 megawatt addition expected to be in service by 2024, with this portion of the capital spend coming in 2022 and 2023, next phase being rider recovery method. Pump storage, Tom mentioned, we already have the largest pump storage facility in the world in Virginia, and 60% of it is owned by Dominion, Bath County. This is a smaller sister facility, Coalfields region in Virginia, for which again development will extend beyond this time period. Early development is underway in engineering. Dollars 1,000,000,000 is the amount of capital spend in Ryder in the public interest in law in this 2019 to 2023 time period.
And strategic undergrounding, another politically popular program where we identify lines on our distribution system that are particularly acceptable to outage based on trees or storms or what have you. And we underground them, which on the one hand is expensive, but on the other hand, it materially impacts our outage metrics, which makes it very popular with our customers, which makes it very popular with policymakers in Virginia. This is $175,000,000 a year, so $800,000,000 over this 2019 to 2023 timeframe recovered in rider form. Here again, I'll just pause. Every program I just mentioned, I've outlined capital spending for this 5 year period.
In each of these programs, there's a pathway to visible capital investment on behalf of our customers for the following 5 years as well. Environmental is compliance CapEx across fleet water, air emissions control technologies, rider and base storm. And finally, having talked about the significant investment in solar and significant the beginnings of significant investment in offshore wind, that is supported by renewable enabling gas CTs, where we have $500,000,000 planned, rider eligible between in this time period, that would be 1 installation in 2022 and 1 in 2023, 4.85 Megawatts. So what is the total? These are the material spending programs.
There are some others in Virginia. This is $17,000,000,000 from 2019 to 2023, and it doesn't reflect any one major program major project rather. Programmatic spending, we show 11 categories here, significant spending that results in a rate base, not capital spend, but rate base, going from $23,000,000,000 in Dominion Energy Virginia at the end of 2018 to $32,000,000,000 to $34,000,000,000 in 2023, CAGR of 7% to 8%, significant spending, significant customer benefit, ongoing rate competitiveness. The next segment is transmission storage. And we show here the general Tom touched on this a good bit, the general characteristics of the vast majority of this operating segment across Pipelines and Storage, Cove Point and the Atlantic Coast Pipeline, which are substantially all demand pull utility customers, a lack of direct commodity exposure and very long tenured remaining contract lives, 90% regulated, regulated like long term contracted assets.
And the 10% here is not a bad business, it's just not a regulated one, which is our gas retail across some pretty attractive choice states, Ohio, Pennsylvania, sizable in Georgia, low capital commitments, sticky customer base. That's the 10% that's not regulated like. And let's come back to that tenor of the average contracts across this business, which has 7 years here for the pipeline and storage business, which is attractive in its own right. But this goes back to what Tom mentioned of the unique physical direct and flexible delivery capacity that our pipeline systems have for their utility customers. Again, peak day, half the flow coming through our DTI system is coming out of storage, not replicable by competing pipelines.
And therefore, this 7 year average remaining life is effectively reflective of an evergreen contract position where we expect it to be much longer. If you add Cove Point, the weighted average comes to 11 years. If you add ACP, it comes to 13 years. So the total for this segment takes our rate base from $6,900,000,000 at the end of 2018 to $11,200,000,000 at the end of 2023, 10% CAGR plus color coded there by pipeline system in the upper left. ACP is, of course, part of that capital, but the capital investment in this business segment is certainly not only ACP.
You can see our base growth. There is the expectation of continued coal to gas switching on the power generation side in the West, new power generation in all of our regions, including the East and the West. And we expect, like our FERC regulated peers, to secure rider type treatment on resiliency spend at DTI in the coming year to 18 months, which will drive this 21% spend during this period on resiliency projects. Now Cove Point, in operation for a little less than a year and it's a great asset. We built it for 6 times EBITDA, completed on time and on budget.
20 year take or pay contracts, investment grade utility counterparties. On an operating basis, at times, this asset operates at greater than 105% of design capacity, operating very well. And one feature that I'll talk about here and come back to later is the free cash flow generation. Given the structure of this asset and its contracts, there's very little requirement for maintenance CapEx practically no growth CapEx. So here we have on the left an illustration of the free cash flow generation from Cove Point on a run rate basis, which is supplied to our parent company in support of our dividend as well, as I'll come back to.
That's transmission and storage. Gas distribution is a great business and part of our operating segment shift is intended to shine the spotlight on it. Dollars 7,000,000,000 of rate base, dollars 3,000,000 customers, great regulatory construct in its major states, decoupling weather usage, very active integrity management programs in all states, very important to political leadership in those jurisdictions. Safety, pipeline replacement and rider form is a major driver of growth in all these businesses and a major driver of safety in all these businesses, dollars 400,000,000 in total average rider CapEx in those areas. Some people are looking at a map for this segment, say, well, we get it, but Utah is kind of far away.
Why is that? And that strikes us as funny, because we think of the Utah business, it's a great utility, with 2.5% customer growth. We think it is being not only core to this area, gas transmission gas distribution, but also it's the headquarters for the management of this segment. The President of Dominion Energy Gas Transmission actually sits in Utah and the operations and the regulatory strategy, etcetera, are run from Salt Lake for all of our states as an aside. Here is an example of the commonalities across the major states for gas distribution.
We share the capital spend on average by state. And really the commonalities here are striking. All of them have decoupled revenue streams taking away volatility from the earnings profile. All of them have pipeline replacement programs in rider form. All of them have strong growth.
In North Carolina and in Utah, that growth is represented by customer growth, which is about 2.5% per year. And in Utah, which doesn't have that customer growth profile, there's a very strong throughput growth trend there that we expect to continue. So very attractive across the major states, West Virginia being the last. Here is the aggregate spend and increase in rate base for this segment, again almost $7,000,000,000 to $10,000,000 7.7 percent CAGR through 2023. We show on the right the breakdown between states, but the most notable thing here is that of the total capital spend, total growth capital in the next 5 years, the majority of it in this gas transmission gas distribution segment is in rider form, primarily pipeline replacement, spend that's authorized outside of the normal rate case cycle from a regulatory perspective.
So here's Dominion Energy South Carolina. We'll provide a little more color here because it's new for Dominion anyway, including these maps, some other basic detail. And when we look at this, we see a lot of similarities to Virginia. In Virginia, we also have a service territory map that's kind of Swiss cheesy like this, but it's not important to the square mileage. It's important that your service territory and state is in the populous and economically vibrant regions, the parts of the state, which is the case in Virginia.
And it's also the case in South Carolina, where Columbia and Charleston, the 2 largest most populous areas, Myrtle Beach are in our service territory. That's the largest utility in the state. At the bottom, we show generation by capacity. This also reminds us of Virginia in that just going back 10 years in Virginia, 40% of our capacity was coal. And in Virginia, where we've done the last 10 years, while we've invested a lot in solar, more to come, we've invested a lot in gas fired generation.
We've retired some coal units, which has brought that number for Dominion down to 13% in 10 years. So this looks like to us what Virginia was 10 years ago. And keep in mind that 30% of capacity that South Dominion Energy, South Carolina has today in coal fired units, 75% of that is kind of early 70s era generation. So here are similar stats around customers and growth rates. Among the most credit supportive utility jurisdictions, which has been true for a long time.
And there's a lot of drama in the last few years around new nuclear, of course, but that hasn't changed the fact that South Carolina is a very good place to do business and it's a very good place to be a utility entity, operating utility. Strong economic and customer growth we expect to continue. Now in South Carolina, around the electric business, $5,000,000,000 of rate base, the team, the management, prior management, has been obviously distracted by new nuclear, spending most of their time on that. It doesn't mean that the rate the core business hasn't been growing. It certainly has to support its customers.
But there hasn't been a base rate proceeding since 2011. Rates came into effect, Oneonetwenty twelve. So on that base business, dollars 5,000,000,000 of rate base, the current effective earnings is sub-eight percent versus authorized 10.25%. I'll come back to that in a minute. We expect to address that in our rate proceeding, which is next year with rates effective onetwenty 1.
So what does that and other spending programs I'm about to talk about mean for the customer bill in South Carolina, just as I did for Virginia, let's talk about So here's the same chart. U. S. Average $140 South Atlantic average $122 dollars There on the left in red is the STENG typical residential bill. Prior to the approval of the construct that led to our merger on January 1.
And then currently 11% lower than the U. S. Average, 2% higher than the regional average. But let's look at it on a little bit more granular basis. Regional average fine, South Atlantic regional average.
But what do you mean in South Carolina? Where is your bill now versus peers? And what's going to happen to it as you spend in response to customer growth and other programs. And the reality is that compared to the largest other entities, load serving entities in South Carolina, we line up pretty well. We're as low or lower than all of our peers based on the approval of the rate construct as part of our merger.
So we have owned, merged with, worked with Dominion Energy South Carolina for 83 days, not very much time. So I want to take a minute and talk about what we're up to near term and what we plan for the long term. So near term, it's blocking and tackling, focusing on customers and communities, things that a lot of our colleagues in South Carolina never stopped doing, but we are supporting in that effort and supporting them and staying out of the headlines basically after all the drama in 2018 that's underway. Those on the strength of the existing team and identifying and achieving cost synergies underway. Supporting the strong economic and customer growth, just the blocking and tackling of NewConnect and supporting economic and customer growth in South Carolina underway 83 days in.
In the near term, we're planning for the rate proceeding that I just mentioned to address the under earning position and to reflect all the spending that's happened in South Carolina in support of its customers since 2011 effectively. And there are capital spending programs that are identified and are underway, including in these areas, supporting customer growth, AMI, grid transformation, gas distribution investment, all active. So those are the items that we have on our radar and that are in our capital spending plan that I'm about to walk through for the next 5 years. A 6th item, longer term, is a transition to capital programs. So some of the things I talked about that our customers and our policymakers in Virginia have wanted, renewables and enabling gas generation, resiliency investments, etcetera.
These are not items that are in our capital spending plan. These are long term items that we expect will be of interest to the customers and the policymakers in South Carolina. So strategic undergrounding like in Virginia, nuclear relicensing like I talked about, transmission rebuild, could those be of interest and come to South Carolina, they could, not in our spending plan currently. So our spending plan is here, which reflects a 5% CAGR in this timeframe from 2018 to 2023, which you'll note is a lower CAGR in capital spend and investment than our other segments. But one thing to keep in mind is that 2 things are going to happen in this time frame.
1 is our business will grow and our income will grow based reflective of the capital spend, so this 5.0 percent CAGR. And the other thing is that through rate proceedings, by achieving a more appropriate return of and on the capital already invested and that will be invested for our rate case next year. That brings the net income growth to more like 10%. So the 5% is a number that's reflective not of the appropriate return on invested capital and not reflective of what we expect to have as longer term investment programs on behalf of our customers at a time that's more than 83 days from closing of our merger. The only thing I'd note here is the spend is there, electric and gas and by type on the right, it's a very programmatic type spend, no not dependent on major projects.
And finally, the 5th operating segment is contracted generation. We're thanks to Governor of Lamont and his administration. 10 days ago, as you know, the parties there after a long process of years reached a very common sense outcome on the future of Millstone, which we think has very material benefits for a number of groups. First, it has material benefits for the residents of Connecticut and those in the New England Power Pool. And those benefits, I won't read through, but they're shown here at the right.
They're environmental and economic benefits. And these are not our numbers. They're very significant. Not our numbers. These are from the Connecticut state regulators report regarding Milestone.
Just repeating them here. That's one category of beneficiaries. The second is 1500 families, 1500 employees of Dominion, whose jobs are secure based on this agreement. And the 3rd category is Dominion, where we received a 10 year fixed price contract at above forward rates, above market forward rates, which means we keep the contribution from Millstone, we derisk the earnings stream. We diminish what effectively is one of the last material remaining areas of commodity or market exposure from the Dominion family.
The pricing for that contract is not public. We expect it will be public. Submission for regulatory approval is happening next week. There's a 6 month process for approval, which we expect to go smoothly and we expect at the conclusion the pricing of that contract will become public and we'll discuss it at that time. And lastly for Dominion, it's also a modest financial benefit, an uplift to earnings, which is positive, but not a material enough uplift to change our existing earnings guidance as you probably noted in our press release 10 days ago.
The other portion of this operating segment is contracted solar, contracted generation. Over 1.1 gigawatts of net owned capacity across states are shown. We show here the time frame color coded at which we invested in this business. And you'll notice tapered off and not expect it to continue in that manner. This is not an investment area for us outside Virginia.
But we did this for a reason. And we went to these states where the progression of solar installation was at a more advanced state than in Virginia. And we gained know how by developing, constructing and now operating these assets. And as I just talked about, the development and ownership and operation of 3,000 megawatts in Virginia, we're bringing that back to our Virginia regulated service territory. That's it.
So what is in total well, consolidated financial outlook, let's talk about what that all means. Those are our capital spending projections. We've provided a rate base as well. In the appendix materials, we have a reconciliation between the 2 with ADIT and D and A and maintenance CapEx, etcetera. What is it in total?
$19,000,000,000 of rate base growth, 7% CAGR over that time frame shown here across our new segments and $26,000,000,000 of growth capital, again shown by segment. Interesting here that there's given the visibility of our spending programs, in particular in Virginia, this profile actually accelerates. In my mind, that's opposite of most companies where there's near term visibility and then it goes away. Ours is the opposite. So 4, 5, 5, 5, 5, 6, it increases over time.
And as I mentioned, there's a visible path for many of those programs beyond 2023. So how are we going to finance $26,000,000,000 of capital? First, let me talk about our credit, where, as you know, in 2018, we invested a lot of time and effort in supporting and improving our credit profile. And the results of that are reflected here, some recognition from Moody's and S and P and Fitch at the bottom of not only improvement in credit metrics, but also the de risking of our business risk profile, the improvement of our business risk profile, which resulted in a movement in the downgrade thresholds from S and P from 15%, where it had been for a long time, to 13%, and for Moody's from 15% to 14%. The recognition of our efforts, time well spent to improve our credit profile and we don't intend to squander that improvement in the way we finance that $26,000,000,000 I just mentioned.
Let's go through an illustration of the annual sources and uses of capital to finance that $26,000,000,000 dollars And this is an illustration using round numbers over 3 years. First is $7,000,000,000 of operating cash flow. So where does that number come from? Again, it's a 3 year average, rounded $7,000,000,000 Our cash flow guidance for this year in our 4th quarter call materials was 6,400,000,000 dollars We also built this with $3,500,000,000 of earnings, D and A including nuclear fuel was about 3,000,000,000 dollars Change in deferred taxes is a little over $500,000,000 so same $7,000,000,000 range. Dividends $3,000,000,000 this year on a run rate basis.
Investing cash flow $5,000,000,000 average, just walk through. Growth CapEx another $2,000,000,000 so that's $7,000,000,000 So where is the rest of the capital coming from? And all of this is already reflected in our earnings guidance, which as I mentioned earlier has not changed. And that is no marketed or block equity throughout the timeframe. Its dividend reinvestment program of $300,000,000 no change.
It's ATM issuance of $300,000,000 to $500,000,000 annually, up to as needed. Keep in mind that that's well less than 1% of our shares outstanding per year. We view that as a very prudent and non disruptive way to modestly support our spend with equity. And finally, debt. We show here net of refinancing, so $2,000,000,000 in the near term, as discussed in our Q4 call, the replacement of hybrid capital, which in this timeframe would be accounted for as a part of that debt issuance.
So when it comes to debt, where is that going to be? And how does that line up in our new operating structure operating segment structure? And this admittedly is a mess. This is the old structure that using color coding tries to tie our financing entities to our underlying businesses, which has never aligned very well. So last time you'll see this slide from us, you'll see in the new structure, the entities are aligned.
And they're aligned in different ways based on the structure of the financings at each segment. So for example, at Dominion Energy Virginia and at Dominion Energy South Carolina, the alignment is total. The financing entity is the same effectively, same economic footprint as the operating segment. At other entities, there are multiple potential financing vehicles. The debt and interest expense from which will be aggregated into the segment reporting, the segment financials.
So at contracted generation, for example, we already have over about $1,000,000,000 of non recourse debt, project debt at our solar facilities, which will be aggregated up to our contracted generation segment. There could over time be additional debt financings there that would also be aggregated up to that segment. Within transmission and storage and gas distribution, there are more entities, shown here, gold, border, where there's already your investment, your bond holder or lender. And that activity will also be the debt and the interest expense will also be reported in those associated aligned segments. The one exception is this Dominion Energy Gas Holdings entity, which has businesses within it that are across 2 of our new segments.
And there, what we're going to do is on an accounting basis, we're going to allocate the debt and the interest expense between segments. One other change upcoming relating to Dominion Energy Gas Holdings is we do plan to contribute this year into that entity our interest in Iroquois, 25% showing at the bottom and Carolina Gas, both within the transmission storage segment, both of which are currently unlevered, contributed to Dominion Energy Gas Holdings. One area of stock not related to the way we finance our business, but it's a driver of our consolidated financial results and financial profile is in O and M, where in September or so, we started talking about initiatives, flat O and M. And at the time, we didn't have numbers associated with it. So here's the same topic, flat O and M.
So this is on a normalized basis for riders and scanner, etcetera. What that means to take our O and M costs on a normalized basis from 2018 and continue it not just through 2020, which we said before, but to 2021 and comparing it to what we expect otherwise would have been the case, looking at historic growth rates on a normalized basis about 2%. So that's $200,000,000 of pre tax savings in this time frame, cumulative, between 2019 2021. We hope that might continue as well. And that is achieved through a number of things that are high profile items for the senior management team that's sitting in the front row.
It's a dynamic process of very intentionally going through each of our segments and each of our assets and each of our locations to find opportunities to lean into technology, to use fewer people, to improve business processes and to improve in areas like smart buying across our platform. In addition, last week, we've announced a voluntary retirement program. Every year, about 2% of our employees retire, so the normal course. As they do, the things I just mentioned in our cost cutting program are in place. Are we going to replace every retiree on a one to one basis?
Probably not. Are we going to use technology and business process improvement, etcetera, to find cost opportunities as people retire? We are. So a voluntary retirement program is effectively an acceleration in a way, well voluntary, acceleration in a way of that 2% to offer incentives to long standing employees where they take retirement early effectively. And we're able to utilize that to accelerate some of those cost savings that I just talked about.
So what does that mean for Dominion? We haven't done this in some time. I know other companies do it from time to time in different ways. The last time we undertook this program, 10% of our employees accepted. So it was a very material acceleration.
So this is an area where we've just launched it, just announced it with our employees in last week. We don't have results or guidance yet on what that means. It's something that would supplement the savings from our flat O and M initiative announced in September. And all these, we view as not episodic, but part of our long term earnings management, smart management of our O and M costs, which not only support our EPS profile, which I'll come back to in a minute, but also allow us to make room in the customer bill by diminishing O and M costs. It creates room for some of the spending programs without rate pressure, which is also an enabler of our growth from capital spending across our utility businesses.
So dividend policy. We show here the traditional support for our utility from all of our regulated and non regulated and regulated like businesses other than Cove Point, which in aggregate would reflect a payout ratio of 71%. And I talked a little bit about the very attractive cash generation characteristics of Cove Point, dollars 535,000,000 midpoint of our free cash flow illustration. So adding that to the other businesses is what takes us to our current position, which is about $3,000,000,000 a year in dividend, which is an 87% payout ratio. And as you'll see, that's higher than our peers, different than our peers because our asset makeup is different.
So we're comfortable with this area. But as we talked about on our Q4 call, we are going to change it, continue to grow our dividend, but at a rate that will allow us not to be an outlier and bring us more in line with our peers. So here's a look at history. 15 years of dividend per share increases, 8% back from 2017 to 2018. Then as we sat there in early 2017, I guess, we gave guidance of 10% growth in 2018, 2019 and 2020.
And the reason for that was we saw on the horizon the completion of Cove Point with the cash we just talked about, largest project in our history. And we saw at the time the vibrancy of the MLP markets and our plans at that time to recycle capital in that method. When the MLP markets went away, we said, okay, we're staying with our commitment for 2018 2019 and then we're going to change in 2020. In our Q4 call, I mentioned we're going to change in a way that will just migrate us to a something that's not an outlier versus our peers And that rate is 2.5%. So following this year, our dividend growth per share will be 2.5%, as always subject to board approval and will migrate us to the low 70s over time.
And the 69% was the peer average shown on the earlier page. But again, those are the average of peers that don't have assets with the cash flow generation of Cove Point. So low-70s is a comfortable area for us. And then finally, our operating earnings per share growth, which I mentioned in my opening statement is unchanged. But I want to provide a little bit of history here also.
So in early 2017, we announced 6% to 8% as our growth CAGR and EPS through 2020. It's actually at the midpoint of the range for 2017 was $3.60 Since that time, what's happened? Well, we grew earnings 12.5% in 2018 over 2017. And then we provided guidance, which is unchanged, for 2019, we narrowed this range to 35%, or $0.4 to $4.40 about 5% growth, a little lower non weather adjusted, a little higher weather adjusted 5% unchanged. And we said growth of 2019 into 2020 was also 5% range.
So this guidance from early 2017 of 6% to 8% CAGR with these more recent inputs reflects 6.7 percent CAGR. But that guidance is pretty stale. It's from early 2017. So you're not going to hear about it from us anymore. We're going to provide new but consistent guidance that's off of a more recent year.
And that is, again, consistent with our guidance range for 2019, 5% end of 2020, 5%, so no change there. And then 2020 beyond, 5% plus. Again, no change. So because it's not new, I've already had the chance to hear questions about it. So let me instead of anticipating these questions, let me just answer some questions that I've already received.
And one is, why not a range? All the companies that we cover provide a range, usually 200 basis points. So I've always said, well, why is that? Why is there a range for a 95% in our case, regulated or regulated like predictable business. Why do we have a 200 basis point range?
I haven't heard a good reason. So we haven't created one. We've kept to what we have, 5% through 2020, 5% plus beyond. And the other question is, what does it mean 5% plus? Some people say, well, I'm a mathematician, but 8% is 5% plus.
Is it 8%? So it's not. If it was 6%, if it was 7%, if it was 8%, if it was 4%, we'd say those things. Based on our analysis, based on this regulated, predictable business that DominionNow is, we expect our earnings to be 5% through 2020 and then 5% and a little bit more after that. So to summarize, and I'll hand it back to Tom.
We talked about 3 things. Changing our operating segments, we hope helps the visibility on the growth profile within these businesses second, dollars 26,000,000,000 pretty visible path to the capital spending growth by segment and the third, comfort with and little change to our view of the consolidated operating profile, including our long term earnings per share growth.
Thanks, Jim. So just a few concluding remarks. As I mentioned first, starting with ACP, nothing new here for you. Just a refresher and put in one place what the milestones are. There's 2 primary pieces put back all the permits have been issued.
Couple will be reissued, the Corps of Engineers, etcetera, going through some processes. So now it's really the courts. There's 2 primary cases, the biological opinion case, which has to do with a handful of species along small relatively small segment of the line. It's set for argument on May 9, and we usually hear from this court within about 90 days. To refresh you, this is a case that's already been to the 4th Circuit, sent back to the Forest Service to redo the biological opinion.
They followed the template of the 4th Circuit, redid it. And I know you'll be shocked to hear that environmental groups filed another lawsuit, but it's working its way through the process. We have a high confidence level that this case, the forest as does the forest service that they will be affirmed on this. This is the case that has to stay on the pipeline construction. So once that we get through that process, we expect the stay to be lifted and be back at work in the Q3 on at least the portions from Buckingham County down to Lumberton, sort of where the compression station is in Central Virginia, all the way down to the terminus of the line in North Carolina in the terminus in the Chesapeake Bay area of Virginia and in the West Virginia Mountains.
The other is the Atlantic Trail the Appalachian Trail Crossing. This is a case where the court said that the Park Service does not have the authority to issue a permit for a pipeline to go underneath Forest Service owned land. So very interesting decision. I'll just leave it at that. We will appeal that to the Supreme Court.
We have a high confidence level that the Department of Justice, Solicitor General's Office of the Department of Justice will join us in that appeal. Government, of course, gets a little bit longer to file appeals than everybody else. So we expect that appeal to be filed probably end of May, June, somewhere in there, looking at our General Counsel. And then you see the time frame on here. And you see the different time frames and costs associated with how you go through this different process.
That's totally unchanged from what you heard on the earnings call and is in the 10 ks. There are other methods besides reversal by the Supreme Court. The decision we'd like to pursue that though. The decision is problematic. The Atlantic the Appalachian Trail is almost 2,000 miles long.
And the effect of this decision for the first time of 50 years of people issuing permits underneath the Appalachian Trail is to basically block energy infrastructure from coming from the western part of the United States into the eastern part of the United States. Don't think it will hold up, but there are other processes. We are pursuing them, But we want to see this process get to the see what the court does with granting the hearing. And but we're going to we'll pursue both those other two alternatives. Both will get the job done if required to go do that.
It's very important though to get this precedent overturned. For others, there are almost 60 pipelines right now that go under the Appalachian Trail issued by all different administrations over the last almost 50 years. So a few words on the states where we do business. I'm starting with the states where we have traditionally done business now. Jim is taking you through these operating segments that we're now going to be reporting under.
I guess you'll see both sort of as we go through the course of the year until we get all the systems in place. Virginia, in Ohio, we've now been in Ohio, we've been there 20 years. You see, Virginia is highly ranked in all these categories. It's it has been number 1 for doing business, number 2 for doing business, now number 4 for doing business. Unemployment rate is quite low.
Population growth is good. GDP growth is good. Ohio, good state, good solid state. We've seen throughput increase. While we may not have seen GDP growth in Ohio, we're actually seeing throughput growth on our gas transmission system there because of the return of industrial activity to Ohio.
So good states. So where have we expanded over the last couple of years? First, Utah, number 3 or number 2 state in which to do business. Fastest growing state in the United States, relatively small base, but fastest growing in the United States, low unemployment rate, high GDP growth. These are 3 very good places to be utilities, very good places to be utilities.
Now where do we expand next? In the North Carolina and South Carolina, also very, very good places to be utilities. North Carolina, Forbes says it's the best state in the country to do business, strong population growth, strong GDP growth. And then you see South Carolina, very strong in all these categories. South Carolina for years was in the top states, top decile there or top 20%, top 10.
And it's my own view, all the Sturm and Drang around the summer situation and all the controversy there sort of made it fall out. I think you'll see it return. It's a great state in which to do business. And we are thrilled to be there, and we look forward to helping our customers and policymakers out there for many years to come. So just a few thoughts about each one of these primary states and then the FERC five zero one gs process.
Virginia, we've got lots of questions about Virginia. What's going on in Virginia? I read this headline and I read that headline and there's controversy around your water permit and your air permit, change out in the general assembly. What's going on there? I'd ask you to just look past the headlines and look at what actually happens.
Did we get an air permit? Yes. Did we get a water permit? Yes. Big change in the General Assembly came in the 2017 election.
What happened literally 2 months later? The Grid Transformation Act is adopted in Virginia with 75% approval from both houses or almost 75% approval both houses, evenly split between Democrats and Republicans. Our state is very moderate in how it goes about things. It's a center state, sometimes leads center right, sometimes leans center left, but in the end, it's center based. I put rural broad and that's where the new General Assembly, brand new governor, very significant piece of legislation passes.
It sets a template to benefit our customers for a decade to come. Rural broadband, I put this up here because and you all may not even know this happened. So if you go and talk to governors and policymakers around the country, you will hear and say, what are your biggest problems in this state? Many, if not all, certainly most will say, we don't have Internet access in the rural part of our state. It's not fair for the educational opportunities, for these kids in these schools.
There's you can't get economic development because there's no fiber. So that's been a huge problem in this country. It's a big problem in the state of Virginia. So what happened in 2,000 this year 2019? We devised the plan, which we presented to the General Assembly and to the governor, which was adopted almost unanimously to have us be the middle mile.
So stop all the alarms. We are not getting into the Internet business, okay, not getting into the telecom business. We are solving a problem. And the problem is the middle mile. How do you get from the urban areas into the rural areas and the cost of that being recovered?
Internet providers will not do it. Cable companies will not do it. Through our grid mod plan, we are going to be bringing fiber optics to all of our substations across our state into our region into these regions. We will provide extra cable fiberoptic cable Internet access to those substations. We will add to it.
And there's a wider recovery for this, dollars 60,000,000 annual cap on it. And there's an overall cap something, whatever the overall cap. Dollars 300,000,000 overall cap over 4 years, dollars 60,000,000 We have
to work with a partner,
which we have already talked to. This is going to solve a problem. I bring this up, and I think you're going to see this replicated across the United States. We can we know how to dig trenches and put in wire. We can get it to our substations and then turn the service from there over to the end use providers.
I'm pulling this up not because it's an earnings driver. It's a $60,000,000 a year capital program rider recovery. I bring it up because we get turned to the solve problems. There's lots of noise and there are people that don't like big utilities and people don't like anything big. This is
all going on all over
the country. It's populism on both sides of the political spectrum. We solve this problem. So our policymakers look to us to help solve problems. Coal ash legislation is another very good example.
It's a very reasoned, reasonable approach to dealing with coal ash.
And it's not a big issue for
us in Virginia. We only have 5 ponds, if you want
to call them ponds.
I'm not sure why they're called ponds, but the remnants of ponds, some of them are ponds, I guess. And this is a method for us to do complete we'll put them in line pits probably on our own property, a rider recovery for the capital expended with it, mostly O and M, but there is some capital expended with it, and there are caps and various things to make sure rates don't go up a certain amount. Very reasons typical Virginia solution to a problem. It's here because there's one thing I want to point out. There's a very small there's a piece of our original deregulation legislation allowed a very small segment of large customers to shop for their generation services, the cap on it.
When this call act bill was passed, there's a provision and it says, if you shop, this is a non bypassable charge. You aren't going to leave the state, big company, to get a little bit cheaper electricity and avoid paying this charge and let leave everybody else behind paying it. Very important precedent in our state. Another typical Virginia reason, moderate, balanced approach. In aggregation, there is some you were also allowed to aggregate big retailers.
They've been trying to do that. Our commission said, We're not going to let you do that and leave behind others to foot the bill. So again, moderate approaches to things in Virginia. I'd ask you to look past headlines that you see. Maybe there's nothing else going on in Virginia but to write articles.
Well, actually, a few things have happened politically since the last articles on us that we will leave for you to read on your own. Utah is one of the best states in the country to do business. It's the number 2 state in the country for innovation and starting new businesses, fastest growing state. This is we are thrilled to be in Utah. North Carolina, we expanded our footprint very significantly.
We have about 110,000 electric customers. Now we have almost 7 times that many gas customers in the number one best state for doing business according to one of the surveys. South Carolina, you heard Jim talk about, we're just going back to basics. I went and met with the political leadership with Rodney in the state right after we closed. All we want you to read about us in the newspapers is our folks went and worked on a Habitat for Humanity house.
Done. We're going to get out of the get lower the temperature. They have huge needs in that state for infrastructure. The governor, the leader of the Senate, Speaker of the House have all asked publicly for an extension of the Atlantic Coast Pipeline into what would be the Northeast part of South Carolina, which the part of the state that lacks in economic development. We don't have any contracts obviously for that yet, but we'll be working on that as we go forward with finishing the Atlantic Coast Pipeline.
Today, nothing in our plan, no commitments from anyone. Ohio has very good gas regulation, very large pipeline replacement program, and I mentioned the throughput growth. 501 gs, this is when the folks that are going to look at every pipeline ROE, almost every pipeline ROE. We're and that caused a lot of consternation with folks. We're about through that whole process with no significant changes.
So what do we have for you? A couple of thoughts as we turn to your questions. We think we have a compelling and very straightforward process, particularly with the new reporting that Jim talked about. 2 thirds to 70 percent of the earnings come from state regulated utilities that are premier assets, fast growing states, premier locations with very good regulation. 25% to 30 percent FERC regulated like a very different gas transmission and storage system than it is usually compared to.
FERC like is co point long term contracts, almost all end use utility customers. The simplest way in my mind to differentiate our pipeline system is it's a regional hub. Most Midstream was built and operated for producers. Ours is built and operated for customers. Very different transparency and reliability of the cash flows associated with these 2 different businesses.
And then finally, it's about 7% is long term contracted generation. So finally, just key takeaways. Low risk assets, 95% regulated or regulated like, quite a transformation from a little over a decade ago. Dollars 26,000,000,000 5 year growth capital plan, 100% of which will be spent on the block to the left, the 95% regulated or are going to be actually in the regulated portions, in regulated like. Scale and diversity, dollars 100,000,000,000 of assets across both electric and gas.
We have a sustainability innovation culture, Our 5th value that we embraced, which we adopted and embraced is we list now as the 4th value on here. You see embrace change, a lot more about that this afternoon. More clarity and accessibility on the reporting segments will yield, we think, a balanced long term shareholder return yield and growth for our owners and great benefits to our customers. So with that, we'll take your questions and answers and we'll provide the answers. Unless you want to provide the answers, turn it over to Steve.
So we're going to try and accommodate both questions in the room as well as questions via those folks who are on the live webcast, who have been submitting their questions to our inbox. And we've got a few folks around the room and we'll take as many questions as we have time for. Let me open and see if there's anybody in the room who'd like to ask a question.
Thank you. Good morning. It's Yeev Siegel with Neuberger Berman. I'm just curious in terms of your risk reward appetite when you think about the utilities and you think about the FERC regulated assets, are you indifferent in terms of incremental capital spending based on the opportunity set if it's state utilities or it's or if it would be midstream FERC regulated?
Our first capital spending always and I'll give a little bit more to answer your question. It always goes into maintenance. We got to maintain our machines for the reliability of our customers. 2nd spend, and that covers safety for us. 2nd spend goes to deal with our regulated customers in these utilities.
We have a mandatory responsibility to serve. We have to extend the lines. We have to make sure there's enough generation. We have to make sure there's enough electric transmission. Increasingly, we're going to have to make sure that there's enough gas transportation and storage to support what you're going to see, especially this afternoon, is going to become a much more have a much more intermittent source of generation in its system in these renewables.
I think from a financial standpoint, we're relatively indifferent, but you're going to see the capital being spent first in those areas. But you use an expression that we don't use inside the company. You use the expression straight regulated or in your midstream assets. We don't think about it that way. We think about it as being gas transmission and storage.
But I hope that answers your question.
Thank you. Jim, this one's probably for you. It's from one of our webcast years about one of the slides you went through on the fixed income, which is how the capital structure will effectively align under these new reporting segments. Can you just briefly touch again on what potential changes for Dominion Energy Gas Holdings as an issuer in the near term that you expect?
Okay. Sure. Yes, I went through that pretty quickly. So from an equity perspective, it's all within Dominion, of course. But it comes down to the financing vehicles we use for bond issuance and the like.
One of those is Dominion Energy Gas Holdings where we have about $4,000,000,000 plus of outstanding bonds to registrant, relatively frequent issuer. In the prior operating segment system, all of that, every business within that legal entity was within still is within gas infrastructure group. So no question. As we migrate to a new operating segment structure where we have gas transmission storage and separately in reporting space gas distribution, there are businesses within that legal entity that issuer that are within both. So from a security standpoint, from a cash flow coverage standpoint, from the perspective of a bondholder existing or perspective in Dominion Energy Gas Holdings, there's no change.
The change with one exception I'll come to. The change is really in the way the activity there is reported. And that's what I meant by the debt and the interest expense within that legal entity being divided within accounting world into allocated into the 2 operating segments for financial reporting purposes. The one exception is that we do have some other assets that are in the Gas Transmissions and Storage segment that are unlevered like the other assets that are currently within Dominion Energy Gas Holdings. And we plan to contribute those to the same entity, which will just increase the security and cash flow contribution within that financing vehicle this year.
And those were Carolina Gas?
Carolina Gas and our remaining stake in Iroquois Pipeline System.
Thank you.
Let's go with Michael.
Hey, guys. Michael Lapides from Goldman. Just curious, when you're looking at South Carolina, very coal heavy, very renewable light, what do you think the timeline and pace for a significant, I don't want to call it, maybe a generation conversion process down there would be?
Thanks, Mike. So if you look at South Carolina today, it's about looks a lot like our Virginia assets did about a decade ago. So first, as Jim pointed out, there's none of that in this 5 year plan, none of that in this 5 year plan. You can see it, it's happening all across the country. Customers want more renewables.
They believe in them. We can provide them. People have said utility industry is against renewable energy. That is completely wrong, at least not at our company, my experience. What utilities have been against is unreliable, really expensive electricity for the benefit of our customers.
That has changed. Solar is now in our region, onshore wind is not a useful resource. It is very useful in other parts of the country. So I think you're going to see it in this plan you've seen today, 5 years' worth of efforts of getting the rate base right. They haven't had a base rate we haven't had a base rate increase, I now say we, at that utility in most of a decade because
of the
summer cases that were going on. So there's some built up rate base there. We'll be spending more. We're going to get that all right sized, but we'll be working with policymakers. We're not going to try to impose our will on South Carolina.
Policymakers will take the lead, and we will follow them. But I think you will see it come in the next it will be probably in the next segment of the decade, more the second half of the decade, Some earlier, some later.
Thank you, Tom. We'll go back and forth again. The next question has to do with the coal ash legislation in Virginia. Is that capital upon which you're going to earn a return or is it O and M? How should people think about it in terms of being an earnings driver or not?
It's some it's modest of capital. Paul Koonce can give us the exact amounts. And the O and M is recoverable through riders separately outside of base rates.
Yes. Thank you, Tom. We have a really good plan in Virginia to take all the existing coal ash ponds and put them in line landfills either directly on the property we have or just adjacent to that property. We expect that it will take about $3,000,000,000 to get that accomplished over 8 to 15 year period. There is an annual cap of 225,000,000 dollars which is really designed to keep the ratepayer impact somewhere less than $5 per month.
But of that $3,000,000,000 dollars most of it's O and M. It's trucks moving ash from one place to the next. So out of that $3,000,000,000 a very small amount of that is capital, but the capital that we will spend, we will earn on. But it's predominantly O and M, just moving the ash from one place to the next.
Let's go to Michael.
Hi, I'm Mike Weinstein from Credit Suisse. How much is the dividend payout ratio target and the dividend growth rate projection past 2020 dependent on increased confidence in the Atlantic Coast Pipeline and the process there? And could there be a change going forward?
Yes. Our financial plan, our earnings projection, our dividend is all based on our expectation. It's unchanged that the spending and process around Atlantic Coast Pipeline continues. So we don't have an alternative plan. We have one.
You're asking, I guess, if the capital spending was lower on Atlantic Coast Pipeline, would we change our dividend rates? We don't have such scenarios.
NOI with regard to ROE. Do we have any thoughts about timing and potential outcome there that we feel like we can share?
I'll turn that to Bob Blue.
Go ahead.
So I think the first point is that incentives that have existed at FERC have been really good for our customers over the time that we've used them, allowed us to invest in reliability, reduce congestion, improve our system. So we would expect that any review of those kinds of incentives would find those benefits. The timeline, obviously, we don't know what the outcome will be. You would expect the timeline on something like this to be at a minimum a year as they do this kind of review. But overall, we feel like that there will be a very strong case.
It certainly makes sense to take a look at incentives, but a very strong case that the incentives have worked and can be beneficial going forward. And really for us, the incentive is the 50 basis point adder for being an RTO, very clearly been a benefit to our customers. We would expect to see that continue.
Steve?
Yes. Just a basic question. So I think the overall rate base CAGR is 7% and then the growth earnings growth rate is 5% plus. Just the difference there is just simply the equity financing needs over the period. Is there anything else that we should think about and the difference there?
The equity financing there is one factor, but it's a very small one and the delta between those two rates, the rate base growth CAGR and the earnings per share growth. The others would be that there's some elements of our business that
are just not reflected in
the rate base growth. One example of that would be Cove Point. The other would be the entire contracted generation operating segment. So those are the larger drivers in that delta, the businesses we have that are not rate based businesses.
We have an online question related to Santee Cooper and asking about our previous indications of interest associated with the management agreement. Is that something we'd still be interested in? Is the recent legislative activity in South Carolina change our perspective on that one way or another?
Yes, we would be interested in a management agreement, continue to be. I learned over the course of last year to just not make any quick judgments about legislative activity in South Carolina. We'll see it play itself out over the next few months.
Julien?
Julien Woll Smith, Bank of America Merrill Lynch. Just following up on Steve's question a little bit. Can you talk a little bit about the progression of regulated earnings through the course of this forecasted period? You talked about, I think you said roughly 2 thirds. By the time you get to 23, how are you thinking about that?
And then can you talk a little bit more specifically to that contracted gen piece? Know we're not going to talk about Millstone explicitly, but what else is in that bucket as best you can provide any initial details because I know I'll leave that aside pending the process, but also want to make sure we understand the solar contribution, tax credit contribution, etcetera.
Yes, a lot there. Let me address that. I think that, Julian, we provide the appendix material that provides, as I mentioned, a more granular buildup, it will be helpful to your modeling. We do expect that the contribution from state regulated utilities, which I think was part of your question, will increase over time, partly because of just the great visibility we have on the spending programs in Virginia. I think that's the most sizable piece and the income will track in our business now pretty closely with the spending.
So there's that. Contracted generation, you may have noticed, I know we flipped through it quickly, that there actually is not identified capital spending that's material associated with that segment. So it's a great business and great assets, but it's not a growth area for us in capital investment. So you mentioned tax credit. That's something that there's not really a significant amount of new business new capital to be invested in that area.
So not really a driver.
Right. So I think you said $1,300,000,000 solar, I think, at a certain point?
Correct. Now that is in a different business segment. That is all in Virginia, which is part of this GTSA, part of the commitment we have for 3,000 megawatts of solar in Virginia to be in operation or in development by 2022. Under the law, part of that is in base rates or rider form, part of it is in PPA. So those PPAs are to interested customers that are non jurisdictional in Virginia.
So associated with that, now I get your question, there will be likely some ITC, but broaden the lens a little bit on the ITC topic for Dominion and back up a few years. Going back to 2016 and beyond, if you think about what the contribution of ITC was to our earnings profile, it was $0.50 it was $0.35 then it was $0.10 or so. And that $0.10 to $0.15 range where we're going to be this year where we expect to continue to be for the next few years. It's not a growing area, and all of it is reflective of the PPA investment in Virginia as set out in the law.
Tom, if I can just quickly follow-up. I know there's been a lot of different permutations on ACP specifically. How do you think about an administrative or executive branch decision over the next couple of months?
We're working with the agencies, but we're going to keep the spotlight on the appeal for now as we work with the Department of Justice to get the appeal filed. It's important to have their support in that case. It's just not a good precedent for the next for the future of the eastern part of the United States to have in effect, a wall built from South Georgia to Maine. So I think it's an important precedent to pursue. There are avenues that will solve the problem, both legislatively and administratively, but that's not our spotlight right now.
Good question. Thank you. Next question online has to do with the early employee retirements, whether or not that's included in the flat O and M guidance or is incremental? And can you give any color about your experience when you went through a similar process about 10 years ago in terms of percentage of employees who were offered early retirement, how many took them and so on and so forth? What are you comfortable sharing?
Yes, it's early days on that. As I mentioned, we've just announced that program to our employees in the last week. And we do have some experience of almost 10 years ago, I guess in 2010, where we had a similar program, but it was an entirely different point in Dominion's history, it was a different market and our employees' 401s, etcetera. So we don't yet really have guidance because we don't know what the take up rate will be. That 10% take up rate from 2010 is one number we have, but we'll know more over the next few months as we see what the participation rate will be.
We do expect that the impact of that acceleration of the retirement and leading into replacement with technology and better business processes will be incremental to the flat O and M number, but likely not very helpful because we don't yet have really a feel for what the take up rate will be and what the impact will be, but we'll be providing that over time. Let's go to Praful.
Thank you. Hi, this is Praful from Citi. On the cash taxes point, Jim, if you could just provide some color on what do you expect the cash tax profile to be over the next few years, especially if you link it with your financing plan and your equity needs? How would that change if you increase or decrease, let's say, ACP or any other kind of big project that is currently still a little uncertain. If you could just provide some color on that, that will be helpful.
Yes. Our cash tax expectation is of course built into our guidance including on financing. But I would say that Dominion, we don't really expect to be a material cash taxpayer throughout this period based on credits available to us. So how that would change with different scenarios for spending? And I guess you're suggesting less spending, which would be more cash in a way at least in this period.
We don't have those scenarios, but regardless, the tax is not a big driver because we're not expected to become a material taxpayer by 2023. Got you.
And just a quick follow-up on the Cove Point side where you showed the free cash flow generation
from
that business. Did you include the debt amortization piece of the Cove Point project in that or is that before debt amortization?
Good question. There is no debt amortization at the Cove Point financing. So that is not reflective of any debt amort.
I got you. Thank you.
I think we have time probably for one more question. And this actually segues somewhat nicely into the afternoon session, which I'll plug 130 start and hopefully you had a chance to register for that. But can you talk
a little there was a little bit
of discussion around electric vehicles. How do you see Dominion playing in the evolution of the electrification of the transportation fleet in the United States?
The 2 ways. I think you're going to see, over time, larger vehicles, trucks, things like that, big trucks and fleets could well go to compressed natural gas. And because they you can have longer duration with that. And of course, that needs gas transmission and storage to work. And with EVs, I mentioned this earlier, traditional car companies, making cars, I don't make cars, but I know making cars is really hard thing to do, at scale and at a reasonable cost safely, reliably.
GM is doing it. Ford is moving into it. Volvo is moving into it. Mercedes is moving. They're all moving.
The Japanese are moving into more going into EVs. Utilities need to help lead that, not just respond to it. We have to look at rates. We have to look at charging stations, how do we get them into folks' houses. We're looking at relationships with I heard this anecdotal story.
Another CEO in our industry was at a function and a neighbor came up and said to her, hey, I just bought an electric car. And she said the CEO said to this person, hey, that's great. Where are you putting the charging station? And the person looked at him and said, what do you mean? What charging station?
They thought they were just going to plug it into the wall. There is a total disconnect between the utility industry and car dealerships and the automotive industry and consumers. So simple first step is working with our dealerships in our service territories. Let us know when somebody is buying an EV. We will get with them.
We will get them a charging station. There's different ways you can make that work over time to benefit the customers. It's good for our customers. It's good the more load we have, if you can spread it on, more customers you can spread it across, obviously good for the environment. We need to do a much more proactive job as an industry, and you're going to see Dominion doing that.
Thank you, Tom. Listen, we've run out of time, and we appreciate your attention for the last two and a half hours. And we want to especially thank the New York Stock Exchange for hosting us at this great venue and for you all coming downtown and for those who joined via webcast. Again, I'll remind you that the materials that we presented today, including a more fulsome appendix, will be available early this afternoon. And again, the ESG sustainability focus part of our day will start at 1:30.
And we'll actually ask that everyone unfortunately will have to leave the New York Stock Exchange, go grab your lunch and then reenter for that meeting. And with that, we'll conclude today's meeting. Thank you very much.