Hi, good morning. I think we're going to begin. Thanks for joining us this morning for PSEG's 2019 Investor Conference. We welcome you to the New York Stock Exchange, and we welcome everyone listening in on the webcast this morning. The presentation materials are also at investor.pseg.com. I'm Carlotta Chan, Head of Investor Relations at PSEG, and we have a full program for you this morning. We're going to begin shortly with Ralph Izzo, our Chairman, President, and Chief Executive Officer. Ralph is going to provide a business strategy overview of the company. Ralph will be followed by Tami Linde, our Executive Vice President and General Counsel. Tami will take you through our regulatory and policy priorities for the year and take related questions after her remarks.
Following Tami will be David Daly, President and Chief Operating Officer of Public Service Electric and Gas. Dave will also take related questions after his remarks. Following Dave's Q&A, we're going to take a 10-minute break and start back up again with Ralph LaRossa, President and Chief Operating Officer of PSEG Power. Ralph will bring you up to date on our power business and take your questions after his remarks. Finally this morning, we'll hear from Dan Cregg, Executive Vice President and Chief Financial Officer. Dan will provide a financial review and outlook. Dan will take your questions after his presentation and be joined by Ralph for any of your summary questions. We will begin, and I will turn it over to Ralph Izzo.
Thank you, Carlotta, and good morning, everyone. Welcome, as was already mentioned by Carlotta. I think we walked through the agenda already, but let me just remind you of the forward-looking statements that are part of the deck. I won't go through it in detail, as well as the fact that some of the financials that Dan and I in particular will show you are not in accord with GAAP, but we do believe reflect the financial performance of the company. The microphone refuses to stay up. It's just going to continue to list. If you can't hear me in the back, just wave or something. Laysor, I'll count on you to signal. We've walked through the agenda.
For those of you who are familiar with our story, just a brief reminder to those who are less familiar with the story, we are going to repeat today our expectations of a 7%-9% compound annual growth rate over the next five years in the utilities rate base, which will continue the trend of making the parent earnings more regulated than less. This year, at the midpoint of our guidance, that ratio looks like about 75% regulated, 25% unregulated. Very briefly, for those of you, as I said a moment ago, who are less familiar with the story, two principal subsidiaries you'll hear about today. Number one, our regulated electric and gas utility. Primary story there being the expectations that over the next five years, we will invest somewhere between $11 billion and $16 billion. Why such a wide range?
We have currently $6 billion in requests in front of the Board of Public Utilities, not exactly over that same five-year timeframe, thus the difference between the $5 billion of the 11 to 16 range and the $6 billion ask. If we were to be at zero, that would give you the 7% compound annual growth rate. If we were to get the full ask, which has never happened, we would be at the 9% growth rate. Secondly, you'll hear about our regional competitive generation business, which we are just about to put the final crossing of the T and dotting of the I on its substantial conversion to an even more efficient, even more decarbonized fleet. Ralph LaRossa will take you through the details on that PSEG Power business. I'll spend my time really talking a little bit about the past, the present, and the future.
The past and the present to give you context and credibility that the future is realizable. We'll do that by first talking about how we've changed the business mix, how in changing the business mix, we've created an investment platform that is both broader and sustainable. We'll talk a little bit about climate strategy because that has a large influence on those investment expectations, certainly in New Jersey, and I do think nationally. I'll talk a little bit about the transformation of the generation fleet, give you a bit of information demonstrating the ongoing commitment to cost control. Lastly, try to summarize what all of this means from the customer point of view, which is also a good news story. One doesn't often show 10 years of earnings where year 10 looks a lot like year one.
That's typically not a source of pride or something that one would boast about. The issue here more is the way in which those earnings are generated. As you can see, back in 2009, the blue part of the stacked bar were the earnings of PSEG Power, and the orange piece were the earnings of Public Service Electric and Gas. If I may remind you, the price of natural gas for what was essentially a nuclear fleet at that time was anywhere from $8 to $10 in MMBTU.
During the course of the past 10 years, as we've seen the robust use of shale gas in our region and the decline in power prices, we've basically been able to reverse the earnings contributions of the two businesses. By growing the utility through much-needed infrastructure replacement programs and watching power prices come down and having its effect on dark spreads that our nuclear plants realize. As I mentioned at the outset, we still believe that at this point in time, at the midpoint of our earnings guidance, the utility will contribute 75% of the earnings of the company. We have a capital program that I'll give you a little bit more detail in a moment, that for the next 5 years looks to allocate about 90% towards regulated operations. If we look back 5 years, that capital program was about three-quarters utility, one-quarter power.
I will remind you that during that period of time, we initiated and almost finished, we will finish this year, the construction of three combined cycle gas turbine plants amounting to almost 2,000 megawatts of clean, highly efficient generation. As we look to the future, in the absence of approvals of our two major filings in front of the BPU, the utility would still represent 11 of the $12 billion in the capital program that we anticipate, which would put us slightly over 90%. If we were to get all of our filings, then in that five-year period, the $17 billion would be 94%. A substantial amount of investment directed towards the utility and regulated assets being consistent with public policy in New Jersey that has both the reliability, resiliency component to it, as well as a green energy component associated with it.
If I take a look at how we were spending our money in the prior five years and how we're spending it now, and how we expect to spend it over time, and why I believe that platform for investment is sustainable, really the story in the previous five years was all about major transmission projects. You'll remember projects, if I rattle off some of the names, is the Northeast Corridor project, the Susquehanna-Roseland project, the Bergen-Linden Corridor project. Each one of those was close to, if you allow me to generously round, about $1 billion, some a little bit larger, some a little bit smaller. In addition, while we were doing that, we were just tweaking some of our existing combined cycle gas turbines, applying Advanced Gas Path upgrades to our Linden units, to our Bethlehem units, to our Bergen units.
Just beginning to invest in energy efficiency and renewable power supplies. Hurricane Sandy gave us a start on some of the resiliency and hardening of the grid. Really, I would say if you wanted to focus on one and one area only in the prior five years and capture most of the investment, that would've been in transmission. In the current period, you're going to see a bit of a shift. The large transmission projects are complete. We still have some upgrades of the sub-transmission assets that we have in the system, that we will take up to the transmission level, and it still remains our single biggest component, although not the dominant component as it had been in the past.
We went away from uprating our combined cycle gas turbines to retiring underperforming power assets and creating a brand-new fleet, essentially of combined cycle gas turbines in the current period, and in ramping up our investments in the clean energy agenda. As we look ahead into the future, we see climate change driving even more investment in the clean energy agenda, as well as adaptation to climate change, driving more investment in a more resilient grid, both the resiliency on the electric side, which is the more common of the two, as well as an aging infrastructure replacement program on the gas side, which will be a continuation of our Gas System Modernization Program. A much-reduced capital program at PSEG Power, with continued tuck-in of solar assets as we've done over the past few years that Ralph will describe further to you later this morning.
If you think about what that means, what those words mean in terms of the actual asset base at the utility, if you go back again 10 years, you could see that the asset base of the utility was dominated by the distribution assets, and in particular, the orange being the electric distribution assets being greater than the blue, the gas distribution assets. The gray, if you will, transmission, almost an afterthought. Over time, as we get to the end of the five-year plan, transmission is fully 40-plus% of the asset base. In fact, the distribution asset base representing 50%, equally represented by gas as it is electric, in fact, slightly more in terms of natural gas due to the Gas System Modernization Program, which was recently approved to the tune of $1.9 billion in calendar year 2018.
The new and significantly new component will be the 10% for clean energy, ranging from batteries to electric vehicle charging stations, to advanced metering infrastructure and beyond-the-meter services. A much more robust and varied asset base than what we were working off of in 2009, should current filings be approved. Why the emphasis? The emphasis is really about the change administration in New Jersey and the greater emphasis both in New Jersey and I think nationally and internationally, on the need for rapid decarbonization. We've committed to an additional 13 million ton reduction of CO2 equivalents by 2030. I'm going to show you in a moment that that's not easily done given our current clean energy profile.
The way we'll achieve that really is through significant energy efficiency improvements anticipated in our Clean Energy Future filing of about 2% reduction in electric use and 0.75% reduction of natural gas use, as well as adaptation investments, given the fact that New Jersey, being an old industrial state, has a lot of its infrastructure, including its electric and gas infrastructure, in low-lying areas that were typical of transportation corridors along rivers and waterways that need to be elevated. On the power side, let's go right to the power side, a very low-carbon fleet. Here you're looking at three separate lines, the top line being the national average for carbon intensity of generation. As you can see, PJM, which was a little bit more nuclear than the nation at large, in general, being slightly better than the nation in the prior 10 years.
As the nation collectively moved away from coal and towards natural gas, that gap between PJM and the rest of the nation really did vanish. However, we have been consistently 30%-40%, and now 50%, below the national average in terms of carbon emissions. Several factors have driven that. It's been the retirement of coal units, the addition of more efficient natural gas units, and the improvement of the capacity factor at our nuclear plants, led by Pete Sena and his senior team at our nuclear operations. That 43% decline over the last 10 years was not easily attained, and we are projecting another 13 million equivalent tons of carbon reduction over the next 12 years.
I can't help but remark that if you read the literature and the need for a 50% reduction in carbon emissions or an 80% reduction in carbon emissions, I can't help but say if the rest of the nation would join PSEG, we'd be there. We wouldn't have to do even more, we won't stand still. It is largely a function of our fuel mix. You may have noticed, see if I can go back. It won't let me go back. Well, if you look at your hard copy. Oh, there, it did. Thank you. Somehow. Did somebody magically do that, or was there just a lag? You'll see a slight uptick in our emissions in 2018 over 2017, that may look like just some randomness in the data, in fact, it is not.
It's an issue that I think the whole nation will have to grapple with. Much of the carbon reduction that was realized over the past few years has been the movement away from coal toward natural gas, you can see the difference between 2009 and 2019. Even for us, you see a much smaller relative position of coal, the gray, as a portion of the stacked bar than what it was in 2009. What I was showing you before was carbon intensity, not total carbon emissions. Coal being a less important part of the portfolio, it's not surprising that the emissions intensity would go down.
However, if I were to show you the difference between 2019 and 2018, what you would see is we generated a lot more electricity using natural gas with the startup of the Keys and Sewaren units in Maryland and New Jersey, respectively. As we've now reached what I call an equilibrium in terms of efficiency and overall heat rate balance between the remaining coal fleet and the newly constructed natural gas fleet, you will see carbon emissions increase as folks begin using more electricity. Something different will have to take place in public policy to bring those carbon emissions down now that the switch between coal and natural gas has kind of played itself out. In our case, that something different is our Clean Energy Future filing. In the rest of the nation remains to be seen what can and will be done.
A word about O&M, 10 years of very stable O&M, as you can see, basically zero change over that period of time, a slight negative. That was true at PSEG Power. It was true in our electric distribution business. The transmission business, because of the O&M required to operate the system while executing a very intensive capital program, did see some fairly large growth rates in its expenditure pattern. Fortunately, the FERC formula rate allows us to get a contemporaneous recovery of that transmission O&M spend. Again, that number was primarily driven by the fact that the operators need to make sure that the system is safe and stable while we're doing a significant amount of construction. Some good cost control in the electric and gas distribution system, as well as at PSEG Power. This is a daily area of focus for us.
You don't hear us launching programs every three years about O&M reductions. I don't know what that means about the intervening two years when people will announce those programs, but I'll leave that for you to question, not me. What does that mean for customers? I remember once upon a time when we would give these presentations, each one of these slides would have three backup slides, and some of you politely told me not to do that anymore, but you can't get me to stop showing at least one of them. From a safety point of view, in terms of our OSHA incident rate, you can see where we've gone from an average performer to a top quartile performer. Our nuclear input performance trends, you could see we were a bottom quartile performer. I'm looking at the upper right-hand slide now.
Bottom quartile performer to now being an average performer, but we are a far better than average performer. This particular statistic has anywhere from an 18- to a 36-month lag when something bad happens in terms of it being part of your calculation. As soon as that something bad happens, it immediately goes into the number, and it doesn't go away for, as I said, 18 to 36 months. The fact that our line was flat for the prior four years means nothing bad has happened in the prior four years. Whatever bad happened in 2014 vanished in 2018, thus the tick up. Pete and his team are driving that number up, and I have no doubt that we will be a top quartile performer and not just an average performer within a short timeframe.
SAIDI, for those of you who are not familiar with the system, Average Interruption Duration Index. It means what was the length of outage that the average customer experienced during the course of a year. There you can see we're a top quartile performer with a number like 50 minutes being the average interruption that the average customer experiences on an annual basis, and a top quartile performer in our J.D. Power Electric Residential results consistently over the five-year period. We're growing the asset base prior years at double digits. We're converting to a more stable earnings platform. We have a broader earnings platform. We're achieving some impressive operational metrics. What has happened to the customer bill? How did we afford to do all this?
The answer is, over the past 10 years, we've actually seen a 30% decline in nominal terms in the customer's bill, and a 40% decline in the customer's bill in real terms. Now, candidly, that is not our doing. That is just the eight to $10 per MMBtu gas price that I talked about several slides ago, tumbling to the $2.50 per MMBtu range today. The benefits of being a combined electric and gas utility have allowed us to take advantage of that consumer tailwind to improve the quality of the service and the quality of the asset base serving those customers, which has been an increasingly important part of our operations.
We believe that even with the fully funded GSMP II, which was approved last year, a fully funded Energy Strong II, which is still before the Board of Public Utilities, and a fully funded Clean Energy Future program, which is before the Board of Public Utilities, we can maintain flat rates in real terms, assuming a 2%-3% type of escalation CPI. We also took a look at the customer bill from a slightly different point of view, which is, what part of a customer's income does our bill represent? You would expect this number to decline by anywhere from 30%-40%, depending upon how income was tracking with respect to CPI. In fact, that is the case. We've seen our bills go from 4.2% of customers' income to under 3%, in fact, 2.7%, which I think is about a 36% decline over that time period.
I planned on bringing every one of these citations and reciting every one of them. They're only about two pages each, as you can see, there's no shortage of compliments that are given to us, both by industry measures, by organizations that look at how employees are treated and various other venues as well. Obviously, we'll not go through all of those. In terms of the dividend, back 10 years ago, the utility basically covering half of that dividend, now the utility well in excess of covering that dividend. That just gives us the confidence that we have the opportunity for consistent and sustainable growth in the dividend, which over the full 10 years has been averaging about 3.5%. Over a more recent time frame has been a number a little bit north of 4%.
We feel pretty confident in that continued utility dividend growth supported by the utility rate base growth. The markets recognize this. I would suggest that on a risk-adjusted basis, we've outperformed every major index, including the S&P 500, for the one, three, and five-year period. If you take away the risk-adjusted caveat, we've outperformed every one of those indices except for the S&P 500 in the three-year period. We have outperformed it over the one-year and five-year period, and certainly have outperformed the relevant utility indices. You'll hear more about the details of each of these topics that are on this slide as the day continues. Really, the business model has not changed. Our obsession, our focus begins with operational excellence.
If we operate well, we believe that our power plants will be available when called upon to run, our customers will be satisfied, and regulators will treat us fairly. Both of those will result in solid financial performance, a strong balance sheet, the ability to support the dividend, and capital allocation decisions that are consistent with our ability to operate assets with excellence is how we define disciplined investment. We think that over the past decade and looking ahead to the next five years, we'll be able to continue to deploy that strategy in a way that allows the utility to increase customer satisfaction, increase its reliability, increase its support of Governor Murphy's clean energy agenda. Power will be able to deliver on highly efficient asset base.
We believe the rest of the nation will eventually catch up to the need for a low-carbon fuel mix, Power will be well-positioned to take advantage of that. We're still working our way through some wholesale power market reforms that we believe Power has the potential to benefit from into the future. That we'll just continue on 112-year track record of paying dividends every year for over one century. I will be back, as Carlotta mentioned, after Dan's presentation. Right now, I'm going to turn things over to Tami, who will walk you through a myriad of regulatory issues that I'm sure you all have an interest in. Thanks.
Thanks. Good morning. I have the pleasure to speak with you today about some of the good progress that we have made and we continue to make on our regulatory and policy strategy. Specifically, I'm going to provide a recap of the settlement of our distribution rate case in 2018. I'm going to provide an update on our view on the good progress that the state has made in providing greater predictability and certainty in how they will approach and approve infrastructure programs. I'll also provide an update on the state's recent approval of ZEC's for our three nuclear power plants. I'll provide an update on the current status of the state's clean energy program, including our energy efficiency program that is pending before the BPU.
As well as moving over to the wholesale power market side, I will provide an update on the slow progress that is being made at FERC to improve wholesale markets. I will switch to a different topic. Switching gears, I'll provide an update on our focus on excellence in corporate governance, and specifically how that corporate governance ties back to our sustainability and our ESG efforts. First, let me start with an overview of what's changed since we were here last year talking to you at the 2018 investor conference, what we talked to you about and the progress that we've made. Last year at this time, we were in the very early stages of our distribution rate case.
We talked to you about that rate case and how it was proceeding through its schedule, and how we were focused on getting recovery of our prudently incurred storm costs and our capital investments that had been made since our last base rate case. Since that time, we had a settlement of that base rate case in 2018, and that settlement met our expectations. It was a settlement that was constructive for both customers and for PSE&G, and it provided long-term certainty and stability for our rates. We also talked to you about the state's recent, at that time recent, new program, the Infrastructure Investment Program, otherwise known as IIP, and our settlement for GSMP II, which was the first infrastructure program to run through that new IIP model.
We found that new IIP model to provide an increased level of certainty on some important issues that were major obstacles in previous regulatory filings, including things like how long the state was willing and able to approve infrastructure programs. Was it three years, four years, five years? The IIP provided certainty that the programs could be approved up to five years. We also saw in the settlement of the GSMP 2 case under the IIP that the state was under the new model, being more clear on what types of clause recovery mechanisms could be put in place for infrastructure programs. As a result, our GSMP ended up with a five-year program approved with biennial rate roll-ins, and it was a constructive outcome for us and for customers.
Since last year, we have filed our Energy Strong II infrastructure program under that same IIP model, and that matter is currently pending before the BPU. I'm going to talk a little bit more about that as I continue. There was also a new priority for the state when I was here last year, and that was the focus on a clean energy agenda. The Clean Energy Act had been passed, and the state was focusing on advancing clean energy, including preserving nuclear power as part of that clean energy agenda. As you know, in April of this year, the BPU applied that clean energy strategy and awarded ZECs to our three nuclear power plants. I'm going to get into some of the details of that award and what's next for that ZEC process as I continue.
The Clean Energy Act also enabled us to file our Clean Energy Future program, including the energy efficiency filing that's currently before the BPU. Dave Daly is going to explain to you some more of the details of that program, and I will talk about some of the important regulatory components and where they stand. Switching to power markets. Last year, I talked to you about our parallel efforts to have either the state or the federal government recognize the value of the environmental fuel diversity and resilience attributes of our nuclear power plants. We are proceeding in parallel. We were making good progress on the state efforts, but we weren't giving up on the federal programs and PJM's ability to include these attributes in their markets.
I mentioned, you know, the great progress we made on the state front, but unfortunately, not surprisingly, the federal government has yet to recognize and make any real progress on valuing these important attributes. However, there has been some advancement and some progress. Although it's been slow and delayed, there has been progress in improving the energy markets with the recent approval by FERC of the Fast Start pricing. In the meantime, looking forward, this is all what's happened since we were here last year. Looking forward, you'll hear both in my presentation as well as some of the other presentations today, our focus is advocating for policies and rules that can enable us to invest in needed infrastructure while making sure that we preserve our customer bills and keep our bills as low as possible.
As you heard from Ralph Izzo, we've been successful to date in investing in needed infrastructure while keeping bills as low as possible. Over the past year, the New Jersey regulatory and policy front has been extremely busy, unusually busy, and the state is clearly working hard to make itself a leader in clean energy. As the focus and the clean energy agenda is clearly in the forefront and getting a lot of attention, we do continue to see some needed focus and constructive outcomes on traditional utility matters. For example, our distribution rate case, which was a constructive outcome, was resolved in the middle of all of the state's efforts to advance its clean energy agenda.
The settlement resulted in a 9.6% ROE, an increase of our equity level, and also as part of the IIP model, we agreed to a rate case commitment to come in for our next base rate case no later than December 2023. That settlement positions us well for that next base rate case. On the utility infrastructure side, we're also seeing needed attention on these important infrastructure programs at the BPU, and the new streamlined recovery mechanism is definitely providing greater certainty, whether it was for the GSMP investment or for the Energy Strong 2 program, which we currently have pending before the BPU. As you know, in our Energy Strong 2 petition, we have asked for $2.5 billion of investment to modernize and to harden and add more resiliency to our electric and gas grids in the state.
That Energy Strong 2 program is currently pending before the BPU. It's proceeding through its procedural schedule, and we're currently in confidential settlement discussions with the state, and we have evidentiary hearing scheduled for June of this year with an expected decision of the matter in the third quarter. There is little doubt that the BPU has a lot going on right now, and they have an unusually heavy agenda. I've listed some of the notable items here that the BPU has before it. For example, they have an expected June release. It's a little bit delayed, but a June release of their draft Energy Master Plan. This Energy Master Plan we expect it to be an important document where the state really lays out how it's going to implement Governor Murphy's energy strategy, including some of the details.
We expect that to be issued in June with a final EMP, Energy Master Plan, issued by the end of the year. The BPU is also working hard on its first-of-a-kind New Jersey offshore wind solicitation, and that is expected to be released this summer. This is in addition to the many other targeted deadlines and goals that are set forth in the Clean Energy Act for the BPU to implement, and our filings for energy efficiency and clean energy, as well as some of the important elements of that, including decoupling. The BPU has a lot on its plate, and we're mindful of how much they have on their plate and how limited their resources are.
We're continuing to work through our typical traditional paths of working with the BPU, working constructively with the staff and the other stakeholders to end up with outcomes that are reasonable for our customers and for our investors. As I said, New Jersey is working very hard to become a leader in clean energy. There's still a lot of detail that needs to be worked out. As you can see here, these are some of the clean energy programs that are currently working their way through active processes at the BPU. It's a lot.
Whether we focus on energy efficiency, which PSEG has for a long time viewed as an underutilized, untapped resource for our customers, or whether we move down to the changes in the renewable portfolio standard, where the state is looking to increase the RPS to meet the state's Clean Energy Act agenda goals, or whether it's to their effort to change the Solar Renewable Energy Credit model to lower the cost of solar. Each of these things is under active consideration. With respect to energy efficiency, our filing put forward a path that we had been working on for quite a long time, a very clear path for how the state's goals to reduce energy usage, both in electricity and in natural gas, can be achieved in a manner that is cost-effective and good for our customers.
That proposal, which Dave will get into some of the details of, is currently pending before the BPU. It does meet the state's objectives. As I said, there's quite a bit of detail that the state is still working through. In order for energy efficiency and our proposal, in particular, to be successful, it's important that the state work through things, including questions like how utilities will recover on and of, and over what time period they recover for energy efficiency investments, as well as the important policy initiatives on decoupling and how decoupling will be implemented. We think these elements are clearly permitted under the Clean Energy Act, and our proposal, we believe, is very consistent with the Clean Energy Act and will help the state achieve its stated objectives.
We understand that there's quite a bit that still needs to be worked out, and these details that need to be worked out in these state proceedings on energy efficiency are very important to the success of the program. Many of these ambitious targets, as I said, are still in quite active consideration, and we're participating and working through each of these proceedings to try to shape reasonable outcomes that can be good for our customers and help the state achieve its goals. We have, for more than 100 years, worked very cooperatively and constructively with the state on common goals, and I believe that this environment that we're in right now is exactly that type of constructive and cooperative interaction between us and the state, looking for ways to help the state achieve its climate strategy and its efforts to address climate change.
This slide shows that alignment very clearly. Whether it's the continued recognition of the need to preserve carbon-free nuclear power through the ZEC program or whether it's our proposal to work to support offshore wind on the transmission and other supporting elements of offshore wind or any of these other important aspects of the state's clean energy agenda. For each one of them, we've put forward a proposal that is currently before the BPU that will help the state achieve its goals and do so in a manner that is good for our customers, keeping the bills low, and also good for our investors. We continue to work through this BPU process to advocate for reasonable rules and constructive outcomes, and our ability to do that has historically been quite effective, and particularly in these complex regulatory environments.
I think that success was very evident in the recent decision by the New Jersey BPU to approve Zero Emission Certificates for our three New Jersey nuclear plants. The ZEC law, passed in 2018, provided a safety net, but we knew that that safety net had to be implemented, and there had to be a thorough review of our books and records to prove that our plants satisfied the different requirements in the statute. The statute that was passed in New Jersey had a lot of detail for the BPU to implement, and it had a lot of consumer protections to ensure that the review and ultimate approval of ZECs was consistent with the best interest of our customers and the state. Some of those protections for consumers include a three-year review for the ZEC applications.
It also provided for a very specific dollar amount to be paid for the ZECs, and that dollar amount was established by the legislature in order to ensure that customers would never be paying more than the emission avoidance level of those plants being retired. Lastly, on the consumer protection front, the ZEC law provided an additional requirement that each year, once a nuclear plant is awarded ZECs, that there be a certification that the nuclear plant is not receiving payments from another source for those same attributes, the environmental, fuel diversity, and resilience attributes that are being paid for through the ZECs. The importance of that annual certification is to ensure that customers in New Jersey are not paying twice for the same attributes.
The same day that the New Jersey BPU passed or issued its decision awarding our three nuclear plants ZECs, the New Jersey Electric Distribution Company started charging customers for those ZECs. Everything was prepared in advance so the tariffs would be effective that same day. The same day, April 18th, customers started seeing on their bills the charge for the Zero Emission Credits, and that same day, our three nuclear power plants started to accrue on our books the payments that we will receive through this ZEC process. I note here that the last day to file a legal appeal of the New Jersey BPU decision is June 3rd, and many of you probably already know that one appeal has already been filed. There may be others. We're not quite sure.
We do know that the Zero Emission Certificate process has been opposed and contested from the very beginning of the legislative process and is likely to continue to be challenged legally. I am very confident that our application that we put forward met all of the requirements of the ZEC Act and that we, through the very robust process that we participated in in the BPU, that we provided all of the different requirements for the BPU to make the decision. While legal proceedings are never completely predictable, I do think that it is clear that the facts demonstrated that we met the requirements of the ZEC Act. The recent decision by the United States Supreme Court for the other ZEC programs in New York and Illinois further reinforces the state has the right to engage in these types of ZEC programs. They have the right, they have the law.
The majority of the BPU agreed that the application satisfied the law. I think we have a very good road forward to defend the BPU decision. We've already started to prepare to defend, to help the state defend its decision. We've already started to prepare for the next steps, for the next cycle of the triennial review process. Undoubtedly, this was a very unique, one of its kind proceeding before the BPU, but at the end of the day, the BPU made the right decision based upon the facts and the ZEC law. Carlotta thought it would be helpful for me to point out some of the misconceptions or misstatements that have been made about the ZEC. The list was much longer. We cut it down to some of the things that we thought would be of particular interest.
But there has been, because of the confidential nature of this proceeding, some myths that have been created or misstatements, and I will just touch on a few of those right here today. First, there is no doubt that the preservation of our three nuclear plants was the best cost-effective solution for the state. Rather than letting those nuclear plants retire, the payments that are being made to the nuclear plants is the right economic decision for the customers. The New Jersey Legislature got this right when they established their payment level. In fact, we believe the payment, looking at the other states, in Illinois and New York, could have been quite a bit higher and still reasonable. New Jersey established a rate that they felt was appropriate to pay for that emission avoidance level.
So there is no doubt, and there has been no credible evidence to the contrary, that it would have been better for customers to let these plants retire. Second, the preservation of these three nuclear plants is consistent with the state's clean energy agenda. There is quite a bit of good solid data behind the fact that these plants are the most significant source of carbon-free generation in the state. Without these plants continuing to operate in the current climate, it would have caused increase in emissions and would have been inconsistent with the state's clean energy agenda. In fact, it would have been a step backwards for the state as they pursue efforts to improve the clean energy format in the state.
Third, one that was quite controversial in some of the press reports is that there's no doubt in our mind, in my mind, that PSEG proved the financial need for the plant. Preserving these three nuclear plants required that we demonstrate our financial need as need was determined and defined in the ZEC Act. There's some very specific language in the ZEC Act that says exactly what we're supposed to demonstrate and what type of information that we needed to provide. We provided all of the required information. That information was provided in the detail that was requested by the BPU, and it was ultimately decided that we did satisfy the financial need. The consultant for the BPU, as you all likely know, determined that we did not meet the financial need.
A careful review of the consultant's report, however, makes it clear that the consultant had a different view of how financial needs should be defined, a different view than the ZEC Act, the ZEC law actually provides for. As a lawyer, I'm very confident that at the end of the day, the courts will look at what does the law say, not what does a particular consultant believe the definition should have been. I think this is a myth. The BPU ultimately decided, based upon the record and the actual language in the law, that we satisfied all of the criteria, and I'm pretty confident that they got that right. We also hear from a lot of critics that these are merchant nuclear power plants, and they focus on the merchant. They're not rate-based, they're merchant.
Why don't you just rely upon the market, and if the market doesn't supply the necessary revenues for you as a business to continue to operate, let the plants retire. Not an illogical comment, but it completely ignores a couple of really important factors. First of all, the current market, particularly PJM's, was not designed to value environmental, fuel diversity, or resilience attributes. PJM doesn't make any disagreement with that. They agree that those things are not valued in the market. Their market wasn't designed to value those things, and FERC hasn't required them to value those things. Second, if you look at what New Jersey has decided and what the courts have said that states may decide, New Jersey has decided that those attributes are important to the state. They're not willing to ignore and accept the fact that the markets don't value these things.
New Jersey does value environmental and fuel diversity and resilience attributes, as was spelled out in the ZEC law itself. When you look at the fact that the current market design doesn't value it, you have a state that the Supreme Court has found does have the right, that states have the right to value these things. There's a real mismatch between what people say we should rely upon and the reality of the facts that we have today. I'll also comment on this last note, which is that fuel diversity is a important factor to the state, and we believe should be an important factor to the wholesale market. There was a lot of discussion in some of the public hearings and in some of the briefs filed in this proceeding that if the nuclear plants retire, we'll still have plenty of fuel diversity.
PJM said they have lots of fuel diversity. The reality is, if you look at the facts, what would have taken the place of our 3 nuclear power plants if they retired was most likely going to be natural gas. Ralph LaRossa, during his presentation today, will show you exactly what happened when the Oyster Creek Nuclear Plant retired last year. The data that is publicly available shows that the Oyster Creek Nuclear Plant was replaced with natural gas-fired generation. The facts speak for themselves. If the nuclear plants retire, at the current time, there's not enough fuel diversity out there to satisfy the needs of these number of megawatts that would need to be replaced. Instead, it's most likely we would see an increase in natural gas operations.
New Jersey made the right decision, all of these misconceptions were considered, we believe, and rejected based upon the law and the facts. With respect to wholesale power markets, as I said earlier at the beginning, we continue to try to influence the wholesale power markets to improve the energy markets so that they properly value the generation that is being relied upon through price reform activities. While we're seeing continued slow backlogged activity on market issues at FERC, we were very pleased to see that the FERC finally issued its Fast Start pricing rules both for New York and PJM, we see that as a positive development. It was also positive that PJM took control and recently filed at FERC an important improvement to their market design for the Operating Reserve Demand Curve. Those are isolated activities.
Not everything that needs to be done, nonetheless, important steps in improving these wholesale markets. On the capacity market side, as you all know, there is still quite an amount of uncertainty as to what is going to happen with the timing and the terms of the upcoming capacity auction. PJM has said that they're going to go ahead with the auction in August, we're prepared to participate in that auction under the existing rules, that if those rules go ahead and those are the rules for the auction, we will bid our nuclear units without being subject to a Minimum Offer Price Rule. It is certainly an unusual situation to participate in an auction where the rules have already been found by FERC to be unjust and unreasonable. Nonetheless, we will proceed, we will participate in the auction that is run.
In the event that FERC does act prior to the auction there is a delay, or if there is a new set of rules that is published or issued by the FERC, which I think is unlikely in the summer months, certainly possible, in that scenario, we will comply with those rules. We are ready for either scenario. In the event that our nuclear plants are subject to a Minimum Offer Price Rule, we're confident that the state does have the ability to provide for a Fixed Resource Requirement, or otherwise known as FRR-ACA, which would allow the capacity revenues for those nuclear plants to be paid through the state mechanism rather than through the capacity auction. The state has not acted on those ideas yet, on those potential, certainly there's no need to because FERC hasn't acted decided what it's going to do.
If FERC does act and a MOPR is put in place, we're confident that the state would have the ability to act appropriately. What will be important is that they have enough time to do so, and that the FERC recognizes the importance of giving states like New Jersey the time that they need to proceed. In other regions, we are a smaller player, but we do monitor the activities and make sure that we understand what's going on, both for the impact on our generation fleet in New York and New England, but also to monitor how those things might impact or benefit what's going on in PJM, where we have a much larger fleet. As you can see here, there is some interesting activity. New York ISO is looking at how to price carbon. We think that is very beneficial if it can be done.
ISO New England also has some activity going on, which could be very beneficial for the long run of wholesale markets. As states become more active in the pursuit of their own clean energy agendas, however, there is definitely a new interaction, a new interplay between the states and the RTOs and FERC. We're starting to see that even with this capacity market auction that is going on in PJM, that New Jersey is taking a much more active role in monitoring, and reviewing, and advocating for rules that are consistent with and don't interfere with New Jersey's goals of a cleaner energy portfolio in the state. Let me switch gears for a moment and turn to corporate governance. As with regulatory, the rules are important, and your governance and how you approach things for the long term are important.
In a regulatory environment, you don't go in and you don't show up just when you want something, and it's the same with running a business. You have to be there for the long run. You have to plan. You have to have good corporate governance, and we've known that for a very long time. Our good corporate governance, as with most companies, starts with our board of directors. Recently, we had a new lead director that was put in place, Dr. Shirley Jackson, and I've had the pleasure to work with Dr. Jackson over the last couple of years, and she really is committed to corporate governance and has a tremendous amount of background and expertise in this area. She was actually just recently recognized by NACD for excellence in corporate governance. Each of our chairs of our committees is independent.
All of our board members are independent, with the exception of Ralph Izzo. This independence is important. It's important also to have a diverse set of board members. Diverse in gender, which we have. We have three women on our board of directors currently. Diverse in ethnicity, which we have. Diverse in skills, and diverse in tenure. If you look at our proxy, all of these details are spelled out. I think we have the type of board that provides the long-term sustainability and direction to ensure that we are being held accountable for smart, reasonable investments. That we're being held accountable for good operations. They take their jobs very seriously, and not only on operations and on investments, but on sustainability and ESG. Our corporate governance committee has a regular review of ESG trends.
Every meeting of our corporate governance committee, we look to see what's happening out there on ESG. They're also very focused at the corporate governance committee about what we're doing on ESG issues and how we can be a leader in this space. Our board and management take ESG and sustainability very seriously, and I'm very proud of the work that we're doing in this space. The regulatory and policy initiatives that I spoke to you about today, and there were many of them, and many of them are heavily focused on what's going on in New Jersey. They are all tied back to our value proposition. We continue to make good progress on our regulatory front.
We continue to recognize the importance of working cooperatively with our regulators and our policymakers, whether it was the resolution of a constructive rate case or our other programs that I spoke about today. Across the regulatory and policy front, we have continued to deliver, and we're working hard to continue to deliver in the future on our strategic plan. Thank you.
Anyone has any questions for Tammy, just raise your hand. Paul?
Thanks. You mentioned confidential settlement discussions for Energy Strong.
Yes.
Are you optimistic that you're going to be able to settle the case? Where do you stand with energy efficiency?
Sure
schedule.
I'm a lawyer, so I'm always a little bit cautious about being optimistic about settlement. It's really too early to say. The settlement discussions are ongoing. I think they're constructive. I can't predict the outcome. I do know that in June, we have evidentiary hearings, and that will be an important gating function, whether we end up pushing those hearings back to continue settlement discussions as we have in past proceedings, or whether we let the evidentiary hearings go through and then pick up settlement at the end. I've been involved in regulatory proceedings where we've followed both models, and I've seen success in both models. We really have to take it day by day and ensure that we are working cooperatively and looking to get a reasonable outcome. On energy efficiency, as you probably know, it's under a particular statute which has 180-day clock.
That is further along. On previous 180-day clocks, there have been extensions. I don't know whether that's going to happen here. We have already had the evidentiary hearings for energy efficiency, and those hearings are public, unlike the confidential settlement discussions. There wasn't really a lot of pushback on the specifics of our programs. I know that the major question in those hearings was, are we ready for this now? Is this the time? As I noted on the slide where I had all of the different items that the BPU is working on, one of the things that they're working on is how they should think about implementing the energy efficiency goals in the Clean Energy Act. We're working in parallel.
We put forward a package in our energy efficiency filing that Dave will get into the details of that provides a clear path on how to meet the goals in the statute. The BPU hasn't quite figured out yet. They still have some time to figure out in this active stakeholder process exactly how they want the energy efficiency targets to be implemented. I think there's a potential that there might be a mismatch in timing, but it's too early to see. What I'm not seeing is pushback on the actual merits of the proposals, which is positive.
Great. Maybe just one quick follow-up. The Energy Master Plan delay, does that play into the energy efficiency filing at all?
I think the Energy Master Plan delay is evidence of the really busy plate and agenda that the BPU has. They have a lot going on. I've been working with the BPU for 29 years, all different BPUs, I've never seen such a busy agenda before this particular agency. They've got a lot. They just finished the ZEC proceeding. They have other rate cases going on. It's pretty impressive. It's very impressive how much they're tackling, I think they're working very hard. I can't speak for them exactly why the Energy Master Plan was delayed, but that's my interpretation of what's going on.
Hi, Michael Lapides of Goldman Sachs. Can you talk about the offshore wind, really the tenets of the offshore wind program? First of all, how material the state tax credits from the EDA would be. Second, do those flow back to customers? Do those go directly to the developer? Third, how does the state or how does the BPU shield the customer from any potential cost overruns or cost inflation on these kind of first-of-a-kind projects?
I'm going to let Dan talk about tax. I stay far away from tax, not a tax lawyer. On the shielding of customers from overruns, that is something that will have to be addressed in the ultimate decision by the BPU. It is something that is front and center in the discussions at the BPU, ultimately will be decided by their decision and the contract that they issue. There's a lot of back and forth in the stakeholder discussions, a lot of good ideas on how much the customer should be protected, how much risk the offshore wind developer should take. I think we'll all have to wait and see what happens later in June. They have a special board meeting, which I think they'll be addressing their offshore wind decision, those details will be hopefully firmed up at that point.
I'll let Dan talk about your tax and respond to your tax question.
Part and parcel the same. We'll all find out in June what that comes down to.
Okay.
It's part of the same.
Okay.
The answer, Michael, really in June, we're going to find out what the entire picture is going to be. Certainly, there will be a customer cost to it, the full details about what's going to be done should be determined in June of this year.
Hi, Praful Mehta from Citi. We have to, I guess, ask about capacity markets, given all the uncertainty and all the news going on around it. From a timing perspective, if there is a decision by FERC at some point, how much time will it take for New Jersey to figure out how the capacity revenue needs to be procured, whether it's through BGS or otherwise? If you can just lay out the process of how you're thinking about that.
Sure.
Given obviously we don't know where FERC's going to come out, but at least want to figure out that process.
Sure. It's important to remember that the capacity auction is three years forward, so no $ are going to be paid out until three years out. That three-year window, New Jersey can't wait, and I don't think they would wait until the very end. The BGS auctions, as you know, occur every February, and they have a three year out period. There's not a specific date by which the BPU would have to act, but it has to be mindful of those two deadlines. I would have preferred that it was already done, but that's a conservative lawyer talking. I am confident that there is still time.
If the FERC issues a decision in the fall or in the winter, there will be adequate time for the state to take whatever action it decides, if it decides to modify the BGS to include the FRR through the BGS. If it decides on another path, a legislative path, that could take a little bit longer. It does have those options of proceeding if it chooses to proceed with an FRR mechanism and continue to preserve the nuclear plants, which we have no reason to believe they wouldn't want to do that. Not a clear answer, but I hope that provides some bookends of the timeframe. There's still time, but not endless amount of time.
Got you. Thank you. It really seems like PJM is going to conduct the auction in August. They seem pretty clear on that. Do you expect a decision by FERC to say we won't cancel the results of the auction, or how do you see FERC responding during this interim period?
I would be very surprised if FERC acted to say that they are not going to invalidate. I think that would be wonderful if they did, and we would certainly like to see that. We continue to think the current auction rules make sense. We were never supportive of the need to have a MOPR for existing generation to begin with. With the current activity at the FERC on these issues, I think it's unlikely, but not impossible that FERC doesn't issue something. Another factor is if the auction goes ahead with these rules that are already determined to be unjust and unreasonable, the question is, what will happen next? Will someone file a complaint? Many of the advocates in the marketplace for continuing to have the auction and having it now and not delaying it are the same ones that were complaining about the rules in the past.
Will then they turn around and file a complaint? I don't know. There is clearly an uncertainty that has not existed in previous auctions. PJM will either go ahead or change its mind between now and the August date, and we will be prepared for whatever they do and whatever FERC does.
Thank you. Next up is Dave Daly, who is President and Chief Operating Officer of PSE&G.
Good morning, everybody. Thanks, everybody, for coming. I'm going to talk about PSE&G and PSEG Long Island. I'll start with PSE&G and our strategy there. It's a very exciting time at PSE&G and the strategy we've got for the next five years. We have a super team. They got a track record on delivering. The investment opportunities are very significant. They're aligned with New Jersey state policy. They're around investments in infrastructure, electric distribution, gas distribution, and clean energy. When you combine that with a very strong focus on operational excellence, O&M cost control, keeping customer rates manageable at the rate of inflation, so flat in real terms, the outcome of that is a really strong story, strong growth and strong returns. I'll tell you a little bit more about the details of that overall. I won't spend too much time on this one.
Tammy covered the fact. When I was here last year, we were in the middle of the rate case. We settled it. The first full month of rate relief was November. 2019 is the first full year of rate relief. We got a good outcome. It was fair and reasonable. We're recovering our investments, including some storm cost that we had amortized over time. Net of the various tax adjustments, basically the impact on customer rates was flat over time. That piece on the bottom is another important component that we have five years to go back in for another rate case, and that really is our plan, is to make the investments over this time period, manage costs very tightly, and not be back in for a rate case for at least five years.
A little bit about, I just mentioned the track record. This is a slide looking at our rate base. The bars on this slide are our rate base. This is going back to 2014 on the far left through 2018. Over that period, we invested $14 billion. Very strong investment performance, on time, on budget performance. That $14 billion investment grew the rate base from the bar that's all the way on the left, which was at about just over $11 billion, to the far right at the end of 2018 to over $19 billion. During that same period, although we didn't have any rate cases, because we had almost all of this, 90% of this investment being done with contemporaneous or near contemporaneous returns and some good cost control, you see that the earnings, which is the line on that chart, also grew at 10%.
It mirrored that growth in rate base. The earnings grew from 2014. They were just over $700 million, and in 2018, that line is over $1 billion, about $1.067 billion. On the bottom, there's another important point there as well, that the jurisdictions that we operate in and we make these investments, they're about evenly split between the federal level. The gray area and the bottom stack of that bar across those years is our transmission portfolio, FERC-regulated rates, and then the orange and the blue and what's above are at the New Jersey state regulations. We have some diversity in our regulatory environment as well. That was looking backwards. Now looking forward, this chart looks at our capital plan from 2019 through 2023. Ralph mentioned this as well, that our plan is to invest between $11 billion-$16 billion.
The difference between the 11 and the 16 is a function of how much of the Energy Strong II program we get approved and how much of the Clean Energy program. Just to explain this chart, just to make sure it's clear what's being depicted here. If you just look at the far right bar, which is 2023, you see that the first three stacks on that bar are solid, and then you have the hatched sections above. The first three sections are parts of our capital plan that are firmed up. The bottom piece, the gray bar, is our transmission investments. That's across the five years, about $5 billion. That's $5 billion of the 11. Next, which is the orange, is our electric distribution.
You can think about that as investments in base capital within depreciation levels coming out of the rate case and new business. That's about $2.4 billion. Then the blue is our gas distribution base capital spend. The blue also includes the GSMP 2 program that's fully approved, where the first year of that program is 2019. Those bottom three stacks, they're in place, they're firmed up. If you summed those bottom three over the five years, that gets you to $11 billion. Then the hatched sections, which over the five years, the Energy Strong II is about $2.5 billion. The Clean Energy within this five-year period is about $2.6 billion. It's about the $5 billion that gets you to 16. The Clean Energy does have another $800 million or $900 million in 2024 and 2025, which isn't shown in this period.
It's depicting the capital plan. If we got nothing out of Energy Strong II and Clean Energy, we'd be at $11 billion. If we got all of it, we'd be at 16. We are hoping to be somewhere between those two. Just a couple other things. The lines that you see on the left, the line on the bottom, that's the last three years of the five-year plan back when it was put in place from 2017 to 2021. The line that's above that is the last four years of last year's plan through 2022. Once we get firmed up on Energy Strong and Clean Energy, we'll strike a line somewhere through that hatched section, and that'll be this current year five-year plan.
Then that last point in that box above the bars that says, I mentioned it on the previous slide, that this capital plan involves 90% of this capital going in with either contemporaneous or near contemporaneous returns. What I'll just do is walk through very briefly the components of this capital plan, starting with the transmission. As I said, the gray stack on the very bottom is our transmission plan. It's about $5 billion. FERC-regulated formula rates, ROEs of 11.68%. It really is driven by the PJM planning process in four major areas. Reliability criteria violations that PJM identifies, hardening the transmission system, what we call transmission life cycle, which is age and condition-based investments. Some of these assets are actually approaching 90 and even 100 years old. Lastly, our 69 kV program, which is basically upgrading sub-transmission at 26 kV to 69 kV.
The next piece is our gas system investments. From the bar chart we just went through, these investments over the 5 years are about $3.5 billion. A big component of that is the GSMP 2 program. GSMP 1 is completely finished. That was a 3-year program. That was 2016, 2017, 2018. That's done. We settled a 5-year program for GSMP 2. It's $1.9 billion from 2019 to 2023. We'll be doing about just under 900 miles of cast iron main replacement under that program. The other component of the gas spend here is, as I said earlier, is the base distribution and new business. Think about that as contemporaneous because we're spending within depreciation level amounts on the gas program.
Moving over to Energy Strong II, a program that is not yet, we talked about, Tami just mentioned, is still before the BPU. This is a $2.5 billion program, has an electric component and a gas component. The electric component you can see on the left is $1.5 billion, the gas component shown on the right is $1 billion. I'll just walk through each of these pieces. On the electric side, the $1.5 billion, there's really 4 components to it. The first is flood mitigation. We have 16 stations left. We did 26 stations in Energy Strong I. That program is completely done. These are the remaining 16 stations that we have that are below the FEMA 100-year flood level. We take these stations, we raise them to the new FEMA 100-year levels, plus another foot.
In this picture here, it may be difficult to see, but you can see it in your book. The picture's on the left. This is some of the work we did in Energy Strong I. That picture on the left is our Ewing substation down in the southern part of our service territory. That's a picture from last March when that station flooded. The left-hand side is kind of the copper gold enclosure. That's the old 4 kV switchgear enclosure. In the right, in the background, is the raised substation that last year saw no problems when this flooding occurred. On the right, that's just another picture of our Sewaren station, which is another station we raised during Energy Strong I.
This component of the program, it's a little over $400 million, is going to do the final 16 substations that are still below that FEMA flood level. The second component is also within the stations, this is our life cycle based on age and condition. We have 84 of these stations that are aged. They're 4 kV stations. They range on average between 60 and 90 years old. We go in there based upon a prioritization of condition, we basically change out the switchgear, the breakers, the regulators, the bus work, we do an upgrade to this equipment that's aged. That's another just under $500 million to do those stations. The third piece of it is what we call the outside plants, now we're moving out from the substations. We have 7,500 miles of pole and circuits running down the overhead on our streets.
This is looking at the bolstering that overhead circuit. The first component is what we call spacer cable, excuse me, spacer cable with new poles. We go into these circuits, again, if you can look in your book or you can see it on that screen, the picture on the left is an existing 13 kV circuit. It's three-phase. That's an old pole, and that's some old hardware. That conductor that's up there is not insulated, called bare wire. What we're going to move to, we're going to do about 500 miles under this program, is the picture on the right. That conductor is fully insulated, and you can see that it's secured within a bracket.
The bracket is held up by a solid steel wire, and it's attached to a new hurricane-resistant rated pole with a steel bracket. It's much more secure. It can much better withstand the impact of trees coming down, and if it does end up coming down, it can go up much faster. The second part of this program is what we call a smart grid type of investment. If you think of our circuit, our grid, I said we have 7,500 miles, and you can think of that 7,500 miles in sections. What this program is all about is taking those sections and making them smaller by putting in advanced technology. Basically, when you do that, what happens is if you have a problem anywhere, the problem is confined to a smaller section, and therefore less customers are impacted. That's what that program's all about.
Between this spacer cable, the new hardware that's rated to much higher wind speeds, and this smart grid technology, you're going to have less outages and much faster restoration. We have the last component of the electric side of Energy Strong II, which is more smart grid modernization. It's a system called ADMS. It's an advanced distribution management system. It does a couple of really powerful things for our operators and our folks in the crews. It integrates several of our systems, our outage management system with our GIS system. It provides real-time monitoring and control of the system, both on day-to-day operations and during storm operations. For the future, it will help integrate distributed resources. That'll bring a lot of benefits as well. Those are the electric pieces of Energy Strong II. They add up to $1.5 billion.
The gas side of Energy Strong II is about $1 billion. What this program is all about on the gas side is there's a map of our service territory, our gas service territory on the picture. Think of going to the west on that map of four major pipelines coming in from Pennsylvania and coming in from the south and the southeast. Those are the four gas transmission pipelines which serve our territory. The biggest part of this program, it's $700 million of the $1 billion, is basically planning for contingencies on those gas transmission pipelines.
If you think about four pipelines coming in from the west, coming in at the north, in the central, and the south, basically what the biggest part of this program is about is saying, for example, if we lost the pipe coming into the northern part of our territory, what we want to do is make investments inside our territory so that we can move the gas that's coming in from the three that are still operating and move it to the north, or vice versa if we lose the pipe coming in from the south. It's investments we're making inside our territory to run pipe, high-pressure main between our stations so that we can move gas around more effectively in the event that we lose some of this gas transmission supply. There's an LNG plant. It's a similar type of play.
If you lose a pipeline and you have an LNG plant in your territory, the gas is already there. It's not a long-term solution, but it's a cushion in the event, again, on a loss of gas pipeline supply. The last piece there is there's some life cycle and some stations that need to be raised as well. That's the gas piece of Energy Strong. Energy Strong Two, $1.5 billion electric, $1 billion gas, $2.5 total. It's before the BPU now, as we just talked about a minute ago. We're in settlement discussions. We have talked about the timing of Energy Strong Two being the third quarter. I think we're still on track for the third quarter to get to a settlement on Energy Strong Two.
Moving over to Clean Energy Future, the other component on that early bar chart that was in the hatched piece. Tremendously exciting program. $3.5 billion, six-year program, has four major components. I'll walk through each of those, but there are energy efficiency, which is driving savings in residential and commercial industrial, electric vehicle infrastructure, energy storage, utility scale batteries, and what we call the energy cloud, acceleration of our advanced metering infrastructure. Just to quickly touch on those programs, starting with the biggest component of that $3.5 billion program, which is the energy efficiency. This is by far the lowest hanging fruit that's out there, $2.5 billion. Positive cost benefit tests, saves money, creates jobs, cleans the environment. This is a four-time winner, this program. As you can see on the right, it is focused around residential programs, around commercial industrial programs, electric and gas.
There's a total of 22 programs. I'll just talk a little bit about those, briefly. On the residential side, there's seven programs here. Basically, I won't go through all of the details on these slides, but for example, the first row there is a program called Efficient Products. These are rebate type programs, where we go into single family residential homes, and we offer rebates for our customers to purchase ENERGY STAR and other high efficiency equipment, electric and gas equipment. Anything that uses a kilowatt hour or burns a therm of gas, there's a more efficient device out there, whether it's HVAC, water heater, smart thermostats, appliances, lighting, and so on. It's a great program. That's the biggest part of the residential. The second row is an important piece, too. It's income eligible.
All of our energy efficiency, clean energy programs across the board, we're making sure that these programs are available to our low income customer base to bring the benefits of clean energy to them as well. Down in the middle, there's a program there called Behavioral. There's types of programs where we go in, we do audits, we do reports. We provide information to our customers that kind of give them insights, transparency around what they use and how they can save money, which then would direct them to some of the offerings under these programs. New construction, incenting builders to build them more efficiently, multifamily, and so on. It's a great program. We've got trade allies developed. In most cases, we offer on-bill financing. We can do the installation services and so on. There's a bigger opportunity just because the loads are bigger.
The opportunity to save is bigger, the opportunity to invest is bigger on the C&I side. There's a number of programs here, and they're very similar. They're just on a bigger scale with bigger numbers. The top row, for example, is our Prescriptive Program. That's kind of like the energy efficient products piece on the residential side. It's basically rebates to put better equipment in. When you get into the C&I, you'll see there that you start to see things like refrigeration, compressors, pumps and motors, and those types of things. It's the same idea. The next one down is a really interesting one. It's our Engineered Solutions. That's where we go into hospitals, universities, schools, and these are the types of loads that they're rather significant loads, but they're the types of customers that don't normally have energy managers on their staff, like a hospital.
They have equipment down in the basement that uses a lot of power or a lot of gas. We go in under this type of program. We do a full audit. We give them all the engineering. We kind of give them a guided experience to a holistic solution. We pay for the entire upfront cost, and they pay us back on bill over time. It saves money. It saves kilowatt hours. It's a win-win-win all the way around. It's a great program. Another great one there is this Custom Program in the middle, where we go into customers that just have very unique processes, and we understand what their processes are, and we understand how they can save kilowatt hours or therms. We pay them on a per kilowatt hour, per therm saved basis. Street lighting, new construction, very similar types of programs.
In all, this $2.5 billion investment in both residential and commercial industrial is just a real big winner. Lowers the bill for the customers, creates jobs, cleans the environment. The next components of the clean energy filing after EE are the electric vehicle and the grid scale energy storage. On the vehicle piece, it's about $260 million. There's four basic components. It's all about putting electric vehicle infrastructure out there to seed the market. There's about 25,000 EVs in New Jersey today. We're projecting that that would grow to 250,000 to 300,000 by 2025. Part of how we'll get there is to seed the infrastructure through these, basically through charging infrastructure. The four components here, there's a big component related to residential chargers, and we'll put the residential charger in.
These are smart chargers. We basically enlist the customers in this program to give us information about when they are charging and their use patterns. We give them incentives to charge at the right time. We see how their behavior is influenced by these incentives. There is a multifamily workplace, overnight lodging type program where we will be putting out 2,200 chargers in 600 different locations. A third component is on travel corridors, on the New Jersey Turnpike, on the Garden State Parkway. That would involve 150 different locations along travel corridors. There is a pilot program on vehicles. On the right-hand side, the energy storage. Again, as with all the clean energy programs, very consistent with the governors and New Jersey policy. The policy goals for energy storage are to get to 600 megawatts by 2021 and 2,000 by 2030. This is to get that moving, 35 megawatts.
Basically, this play is all about benefits of putting energy storage in the right place to accomplish solar smoothing, distribution upgrade deferrals, microgrids for critical facilities, outage management for some of our substations, and so on. That is about a $100 million program. The last piece of clean energy is our energy cloud AMI program. It is about 2 million, 2.2 million electric AMI meters that would be installed. A $600 million investment. Tremendous benefits to the customer in terms of bill savings and transparency for the grid operations, particularly during storms, for operational efficiencies and labor savings, and for our asset managers, to get them better data so they can make better decisions on where to make investments and how to make investments in the system. It is a great program, brings tremendous benefits.
It takes energy efficiency and brings the benefits of energy efficiency 2 or 3 levels greater. The map on the right is a situation where we stand today. New Jersey is not leading the nation. At this point, it is between us, West Virginia, and Rhode Island. That is where we stand today. The good news, though, is that there are two things that have happened on the AMI front. One is that there was a moratorium in place in New Jersey. There is a moratorium in place. While Orange & Rockland did a pilot to put in 70,000 smart meters. They finished that pilot. They have submitted their report. They have submitted their filing to recover those costs. That filing explains the benefits that they got. It is a positive report. The BPU is under that moratorium process, evaluating Rockland's results. That is ongoing.
Secondly, coming out of the storms last year in 2018, the BPU asked all of the EDCs to present proposals for AMI and how AMI would help in storm response and any other benefits it would provide. Our filing basically accomplished complying with that request from the BPU. When you think about AMI, the BPU is working on it, both in the Orange & Rockland moratorium pilot case and by asking everybody to submit information. I am cautiously optimistic that our color on that map is on the path to changing. That is the Clean Energy Program. In total, $3.5 billion. The biggest piece, energy efficiency, $ two and a half billion, electric vehicle, energy storage, and AMI. In terms of timing around Clean Energy, I just talked about AMI.
The timing on AMI right now is around the BPU examining this Rockland pilot and around evaluating the submittals that they asked all the EDCs to put in on the benefits of AMI. That's kind of what's happening there. With regard to the other three programs, the EVs, the storage, and EE, we are primarily focused right now working with them on EE. As I said before, it's the lowest hanging fruit. It's the most valuable program to start with. We are working very closely with them. We've gone through the process on the procedural schedule. Tammy mentioned that we've had hearings. As Tammy said, they are very busy, the timing of getting to a resolution there is a little bit unknown. The BPU's backlog did result, as someone, I think, asked earlier, in their delaying the energy master plan.
I think some of these pressures that they're under, in terms of all the things that are on their plate, are at play with everything that we have in front of them as well. The timing is a little bit unknown. We don't have any better information than that, but we're working with them, and we do understand how much is on their plate. We're offering to help in any ways we can to move these things forward. You put all those investments together, and over the next five years, you get a rate base growth pattern that looks like this. The far left is where we ended 2018. That was $19 billion. This chart is constructed the same way as the previous one.
The solid three sections building up from the bottom, those are firmed-up programs that we're going to be investing in transmission, electric distribution, and gas distribution, GSMP2. The hatched areas are the two programs that are still out there, Energy Strong and Clean Energy. The $19.2 billion rate base that's in place today, at the end of 2018, will grow over this time period to somewhere between $26 billion, if we got none of the hatched, to close to $30 billion, if we got all of the hatched. You're seeing very strong rate base growth. That range represents 7% to 9% if we got nothing to getting everything. We don't normally get either of those, but that's kind of constructed in the same way.
I mentioned up front, Ralph mentioned it in his presentation, we do have a very strong culture and discipline around operational excellence. It's a foundation that allows us to pursue these opportunities to invest. This chart shows safety across the top and reliability on the bottom. Ralph had a couple of these slides in, but these basically show very strong performance on safety, both the number of injuries, the severity of injuries, and reliability. 17 years in a row, the most reliable utility in the Northeast. We also focus on customer satisfaction. This chart here shows four versions of how we measure customer satisfaction. On the left side, we measure electric residential on the top left and electric business on the bottom left, and gas residential and gas business. There's very strong results here on the electric side and on the gas residential.
The bottom right shows a little bit of a dip on the gas business component. We're working hard to address that dip there. We know gas businesses really focus on price. It's one of the reasons we need that energy efficiency program. Gas businesses will save tremendous amounts of money with that energy efficiency program, and that'll do a tremendous amount to improve their customer satisfaction. We're working on that. O&M, track record of controlling O&M costs. That's our plan to do over the next five years. I mentioned that we've settled this rate case. We don't plan to be back in for at least five years, and part of what that's all about is focusing on O&M cost control to keep customer rates down and to make sure that we're earning our returns.
We're also finding increasingly that to be efficient and to control costs and to improve service quality to our customers, there is increasingly technology solutions that are coming our way, and we're very aggressively pursuing those. There's some of them listed here. The voice computing on the top, we're the only utility in the U.S. that provides the functionality through Alexa to transact with the utility and pay your bill. The analytics and machine learning, particularly in our customer area, we're implementing a Salesforce advanced intelligence machine learning application that's going to bring tremendous benefits to our customers. We have a number of robotics applications that have been put in place in our back office areas to perform some routine back-office work.
The bottom 2 items around mobility and automation are just tremendous opportunities that are out there to bring efficiencies to our field crews, reduce downtime, reduce non-productive time through better planning and scheduling, through route optimization, and a whole range of technologies that are allowing us basically to become more productive, which saves time, saves money, and helps keep customer rates down. On customer rates, in Ralph Izzo's presentation, he had a slide which talked about the fact that rates are down 30% and 40% from 2008 or 2009. This slide brings it a little bit more forward. Just to explain what's on here, the 2 bars on the far left. The far left bar is January of 2016, and the bar next to it is May of 2019. This is about a three-and-a-half year period.
This is the typical electric and gas combined customer bill. It was $176 three and a half years ago. It's $180 today. It's basically, in real terms, flat. That was all while we were doing Energy Strong I, GSMP 1. It reflects the rate case that we settled last November, and it reflects the ZECs that we got. With all of that happening, we're still controlling costs and in real terms, keeping rates flat during that period. The right-hand side of the bar chart describes what's going to happen over the next five years. What's depicted there is our full GSMP 2 program, where we're having rate roll-ins as we go. It assumes we get the full amount of Energy Strong II and the full amount of clean energy.
If you look at what happens, if that happens, particularly with those other two programs, we're still relative in real terms, keeping rates flat. That basically is our strategy on the cost, is to control our costs, to keep rates flat in real terms while we're able to make these investments that provide benefits to the state, to the company, to our customers. On top of all that, on the very bottom is that point, and it's not to be lost. This doesn't factor in any of the benefits from EE, which lowers the customer's bill even more. Just to wrap it up for PSE&G, net income growing from 2017 to 2018. As I mentioned, 2019 is the first full year of rate relief that's depicted in that slide. The guidance that we provided for 2019 is in good shape, and we're on track for that.
Moving on to Long Island just quickly. As you know, Long Island, we're in our sixth year. We've been managing the system out there, 1.1 million customers for five years. We're in our sixth year now. It's focused on all the same things, customer satisfaction, reliability, cost control. It's a performance-based contract. If we do a good job, we get paid, and we get paid incentives. If we do a bad job, we don't get paid. If we do a really terrible job, they can throw us out. It's all performance-based. So far, it's been doing real well. We got a fantastic team out there. They're meeting all their expectations. They're realizing the incentives. The focus on metrics. This slide basically shows safety and customer satisfaction on the top and basically improvements that have been made there.
On the bottom, there's real strong reliability on Long Island, and those results on the bottom reflect continuing top quartile reliability performance. Just a little bit more on the customer sat, because there was a very strong focus on customer satisfaction when we first took over out there. That bar chart on the top, that's called the J.D. Power 100 plus membership club. That's J.D. Power results from 2013 to 2018, and every company in the U.S. that has achieved more than 100-point gain over that five-year period, and we're the highest one. It was up 161. Now, in fairness, we were starting from a little bit of a lower point, but the fact is the team's done a great job, and they've improved that number, and it's still on its way up.
You can see on the bottom how that kind of panned out in terms of both residential and business satisfaction. With Long Island, there's some other benefits that we're seeing out there. We're basically wherever we can, we're leveraging best practices. We're leveraging technology. That really exciting technology we're putting in the customer area with Salesforce, we're leveraging across both of our jurisdictions. We use the opportunities to rotate talent and develop talent across our jurisdictions. It's a service model that seems to be working well. If and when any opportunities arose in the future, it's something that we could learn from and pull from. Just to wrap it up is just, I think everything I just covered summarized on the overall value proposition.
It's about a great team, about investment opportunities that are aligned with policy, operational excellence, customer rates, and good returns for the company and for our investors, for our customers. I'd be happy at this point to take any questions.
If you have any questions, just raise your hand. We'll bring the mic over. No? Okay. Oh, Joan. Okay, there we go.
Hi. Good morning.
Good morning.
As you guys roll out the energy efficiency and some of the other programs, how much of that incorporates in how you guys sort of protect yourselves from any cyber risks or any of that sort? Because as you automate, you are leaving yourselves to be more vulnerable or creating more entry points. As you guys, whether it's AMI or
Yeah
systems, how does that get incorporated into your program?
Yeah. We have a tremendous amount of focus on cyber and cyber risk. We actually internally have a senior executive cyber council. Our program around cyber has a number of elements to it, which will be applied to energy efficiency, AMI, and as well as all of our other programs. Number 1 starts with what we call network segmentation, separating your IT systems, corporate systems from your industrial control systems, which for us is SCADA and EMS, and doing that with air gaps and very strong firewalls. Secondly is a whole lot of information about procedures around access control, making sure we know who's getting in. Data protection, which involves encryption. A new function that I would say has been developing and becoming more sophisticated over time, which is a function called vulnerability management and analysis.
It's a group of people that are very focused on a daily basis examining your vulnerabilities and reacting to those and addressing those on a daily basis, whether that's patching or otherwise. There's physical security, where that makes sense, if we're talking about, for example, some of our substations. I won't get into how much we invest in cyber, but I can tell you it's a very structured program around these four or five areas. We make significant investments in it, and we're constantly evolving and keeping up with the latest on cyber.
Anyone else?
Hi.
Good morning.
Dylan Morrill, UBS. The work on AMI, you were talking about the Rockland Moratorium-
Yes
The submissions. How does that relate to the timeline for the Clean Energy Future program and the energy master plan?
Yeah. I think, as you know, two years ago or so, the New Jersey BPU put a moratorium in place. They authorized Rockland Electric to do a pilot program. It's about $17 million, 70,000 meters, so relatively small. They charged Rockland with doing this program. After it was completed, filing for recovery and a determination of prudence and the benefits. The good news on that is Rockland accelerated that schedule by about a year. They're done, they've made that filing, and the BPU is reviewing it. I think the most important part of that is that the BPU had said they didn't want to pursue AMI with any other utility until the Rockland piece was done. It's now done. They're reviewing it.
I think the impact on our AMI proposal is that they're in the process of determining whether or not they really think AMI makes sense. Combine that with the fact that coming out of the storms, they also asked for submissions. I think to answer your question directly, it's an indication that they're very focused on making a decision that moves them away from where they were, which was a moratorium, and we need to understand this better. They're now looking at the results. I'm cautiously optimistic that they will determine, because I'm aware of Rockland's results. They were very positive. All the benefits you would expect from AMI, they are getting, and they've detailed that in their report. I'm cautiously optimistic that'll get them to turn the corner.
I think on that aspect of our clean energy, that's really how that's going to be moving ahead.
Thank you.
Anyone else? Okay, we'll take a 10-minute break, and then we'll resume with Ralph LaRossa. Hi. Hello, everyone. We're going to start back again, if you could take your seats.
That's okay.
Okay, I'm going to go. Everyone, if we can take our seats, we're going to start back up again. Thank you. Yeah.
All right. Carlotta gave me the high sign. Good morning. I'm Ralph LaRossa, President and Chief Operating Officer of PSEG Power. I wanted to make sure, if you haven't noticed, we have a different city on each slide for our introductions. I was given Camden. I wasn't sure why until I realized that it was a Philadelphia Eagles fan who made this up, and I'm a Giant fan. They decided to give me the southern part of the state. I'm going to try to leave you with three things today. One, we've really worked hard over the last two years to complete our capital program, and as a result, have finished up on our efforts to really move into a cleaner, more efficient asset base, and I'll walk you through that a little bit.
I don't think we've actually got enough credit for that, so give you a little details there. A little more on our focus on the zero emissions generation, and specifically a little more detail, a follow-up on what Tammy gave you on the ZEC process. Finally, the fact that at the end of the day, when we're all completed, we just really have improved cash flows for the business as we move forward. Those are the three big takeaways I hope you have. First, from an asset base standpoint, if you look at where we are in the state and where we were not in the state, but in the region, and where we were last year. Really, the two plants that came online, just to remind you, were our Keys Energy Center and our Sewaren plant in New Jersey.
We added about 70 MW of solar in our Power Ventures group. That's really the changes that have taken place. We're nearing completion, as I'll talk to a little bit more in our Bridgeport Harbor Five facility. This is a timeline of what's been accomplished in the power business since really 2012. Again, this is where I think if you step back and look at us against some of our peers, maybe we haven't gotten the credit. Ralph mentioned some people making large announcements about O&M reductions. Well, this is a place where I think, if you look back, we could have made a large announcement about reducing our carbon footprint and becoming more efficient with our power plants. We didn't make that large announcement. We've just progressed along a path here.
Back in 2012, we started to reduce some of our poor performing peaking units, brought on some more efficient peaking units. We started to retire some of our coal assets, brought on additional solar assets, finished up with some real nice combined cycle plants that we have in place now. The timeline is not this move from our standpoint to a more efficient generation fleet didn't start last week. It's been going on since 2012. Two specific areas from 2018 that we did complete since our last time that we were together was the Sewaren 7 plant and the Keys Energy Center down in Maryland. Both are achieving about their capacity factors that we had planned on. The Sewaren plant moved into commercial operation in June of 2018, and the Keys Center in July of 2018.
I juxtapose those with some pictures on the left-hand side, which is our two last coal plants in New Jersey, both our Hudson and Mercer plants. Not just to show you the fact that we've moved out from a generation standpoint, but also to point out the fact that we actually sold those pieces of land over the last 8-12 months. We're repurposing the land, putting it back. It's gone to a developer who's going to probably put some industrial development on those sites. We're repurposing, putting them back into the economy of New Jersey, and something that we're proud of as we continue to progress here. The latest plant and the final plant that we have from our combined cycle fleet as we've been upgrading is our Bridgeport Harbor Five plant.
As I was mentioning to a few people earlier during the break, if there is nothing I have learned over the last 20 months, I know that when steam is coming out of a stack, it is a good thing. This is a very recent picture of our Bridgeport Harbor plant, just taken last week, and it does show the fact that we have started to run the unit. We are not commercial at this point, but we are in our testing phase of the unit. Good progress made there. We expect it to be on before the summertime peak comes into place. I also wanted to point out on this slide the fact that we have completed, during the construction phase, the upgrades that were needed to the GE blades.
I know that there was a conversation in the industry for some time about the need to replace, on these specific units, the blades from GE. We did that here at Bridgeport Harbor Five, and we also noted on the prior slide that it has been completed on our Sewaren 7 plant. Both of those units have gotten through those upgrades that were required. The result of these upgrades that we have gone through is shown on this chart in really four different ways. First, from an emission standpoint, we have clearly cleaned up the fleet and continue to do so. The next big step will be the retirement in 2021 of the Bridgeport Harbor Three facility, the last coal plant that we fully own. That is in the marketplace up in New England until that time frame. At the same time, we have driven down the O&M per megawatt hour.
It is a combination of two things, becoming more efficient but also generating more megawatt hours. You saw on the prior slide the difference between those coal units and the gas units that have come in New Jersey in its place. Obviously the improvements in the heat rate. Again, all these plants in the 6,400-6,600 range, and they are all operating at those levels. Obviously, the plants themselves becoming newer plants and driving down the age and helping us to reduce our O&M activity. All positive from an operating standpoint when we look at the upgrades that have taken place. I want to transition away from the fossil fleet and talk a little bit about what I will call the zero emissions fleet, carbon-free fleet. A lot of people have asked me, what has X accomplished and how did we get through it?
While it seems like a very long time, for us, it was really accomplished in a pretty quick timeframe in about 18 months. First of all, internally, I cannot thank Ralph enough and our legal team and the finance team and everybody who was out front arguing the cases for us, making the cases for us, and advocating on our behalves. Communication team, governmental affairs team, we all pulled together and got ourselves through that internally. I do not think any of that would have mattered much, but for the fact that we continue to operate those plants very well. Pete Sena and his team, Ralph mentioned them earlier, are doing a great job for us down at the plants.
In fact, it was mentioned on the last quarterly call, we had breaker to breaker runs at Salem One and at our Hope Creek facility for the first time in their history. Those accomplishments shouldn't go unnoted. Great work by the team down there. Finally, we got to where we were from a ZEC standpoint. Again, all the legal reasons that Tammy walked through, because of some great leadership in the State House, and specifically, Senate President Steve Sweeney, the Assembly speaker, and others getting behind this and really agreeing that this made sense from a policy standpoint for the State of New Jersey. A combination of all three of those factors got us to where we were. I know what matters most to you is why will it stay? Why do we think the ZECs will stay in place in New Jersey?
Tammy alluded to this slide, but I'd ask you to take a second and read through the data. This is the impact on New Jersey from a generation standpoint after Oyster Creek closed in October of 2018. If you really look at what happened to the plants, it's almost a one for one on a terawatt hour basis in the replacement of power from the nuclear facilities, zero emission generation to gas-fired generation in the State of New Jersey. This is not our data. This is EIA data, so it's all noted at the bottom. It's a straightforward way to explain to policymakers that the ZEC opportunity that was presented to them made sense from a policy standpoint. If I have confidence about why down the road this will continue, it's this one singular slide.
The plants make sense aligned with the policy of the State of New Jersey. In addition to our nuclear facilities, we have still, as I mentioned earlier, continued to look at and focus on opportunities to grow our solar business. Last year, we had a few plants that came online, specifically down in North Carolina. We expect a few more down in North Carolina again this year. It's an area that we're comfortable working in and provides us with good opportunities from a PPA standpoint. I did want to mention on the left-hand side of the country in California, we only have a little less than 30 MW of plants in PG territory. Our exposure there is really limited in the PG&E area. Not some of the conversations that we've been having or that you've had with others. Very limited exposure in California.
Finally, from a clean generation standpoint, talk a little bit about offshore wind and some questions that we've gotten on this front. First of all, how did we get here and how did we get involved with Ørsted? About 10 years ago, we started to dabble in the opportunities that the State of New Jersey had as they actually put out RFPs for folks to look at offshore wind. We put a buoy out in the water and started to collect some data. That effort kind of went by the wayside during the Christie administration. We still had opportunities, though, for leases at that time, and through several different transactions, wound up with an opportunity for an offshore lease partnership with a company called Deepwater.
Deepwater was acquired by Ørsted, during that acquisition process, we had conversations with them about how we might have opportunities to work together in the future. That's how we got to where we are today on the offshore wind standpoint. The process laid out here is the process laid out for the state of New Jersey. As we look at our opportunities for Ørsted going forward and our opportunities to invest, I want to be clear about two very specific things. It is clearly an opportunity. There is no commitment that we've made at this point. Second thing is that we have no intention to take in risk on the actual construction of the facilities, the generation facilities offshore. Those are two big things that we know from a standpoint where we are, and we want to make sure that you took away today.
We know what we know. We think we can help on the transmission side because we've done work like this in the past. We've crossed Newark Bay very recently with some transmission projects, so we know how to work in the marine environment. We obviously know how to work onshore based upon the amount of work that we've done over the last 10 years as Dave outlined. We have no intention of being involved from a risk standpoint with the actual generation installations offshore. We'll continue to look at the opportunities when the state of New Jersey makes its decision about who might be awarded these projects. Two things that we have committed to do with Ørsted is very simply, one, to work with them from an energy management standpoint.
Our ER&T group, led by Shai Malik and others, potentially could be the ones to sell the energy into the marketplace. We've committed to have a conversation with them about that. We've also made a commitment to give them an opportunity to have some access to land around our nuclear facilities. The reason for that is very simple. It gives the project a competitive advantage with quick access to deep water into the Delaware Bay. That's the two commitments that we've made. Everything else that we have, as we say right at the top, is an option on this going forward. No matter what happens, we think we're going to learn quite a bit about the offshore wind business as we go through these next six months. Transferring a little bit from the assets, moving into the financials.
This just is a way to portray a little bit about our gross margin top line and the different pieces and components that make that up. Obviously, the capacity and energy piece, a little bit that we get from the power ventures group that I mentioned earlier in PPAs on the solar side. Then finally, in the stack bar, you see the impact of the ZECs. The takeaway from this should be the amount of this gross margin that we really have "hedged" or at risk at this point that remains.
We've done a really nice job, I think, as a group over the years, not just in the last one or two, but over the years in really moving this bar and making it less and less of a volatile business and more and more hedged as we've gone forward. I'll break down each one of these pieces a little bit for you. If I can move the slide, there we go. First, the largest piece on the capacity, starting at the bottom of that stack bar, the PJM capacity prices. This is obviously our largest. As we have mentioned over time, we expected the trough year to be in that 2020 timeframe. It's exactly what we see in the slide there.
That from a calendar-weighted average price standpoint, we start to see those prices increase in the 2021, 2022 auction and the layering in of the 2021. There's some uncertainty, as you know, about what's going to happen in the market going forward from a capacity standpoint in PJM. We're not projecting anything going forward. I won't repeat everything that Tammy walked through as to what we think might happen with that auction and the timing of it. We'll leave that at that. I will say on the bottom right, though, we're still pretty happy with the fact of where our assets sit and where we are compared to the RTO from an average price standpoint. That competitive advantage about where our assets are remains from a capacity standpoint in the PJM process.
The next piece from a capacity standpoint is taking a look at what's gone on up in New England. Again, you've seen prices come down from a capacity standpoint, I want to point out the good work that was done well in the past about locking in the Bridgeport Harbor Five for 7 years, and the price you can see there that we've got locked in for that megawatt per day price in the capacity revenues there in New England. That'll keep that plant in good financial shape going forward, and again, that doesn't apply to our Bridgeport Harbor Three, but does apply to Bridgeport Harbor Five as we look forward. Moving into the energy side, up from the capacity part of the stack bar.
You can see very similar to what we've showed you in the past about how much we've hedged from a base load standpoint, combined cycle standpoint, and the total there. I did want to point out, though, just to remind everyone at the bottom there, the prices that you see there are at a full requirements contract price. That's not just a specific price for energy. We feather that in for you and show you year-over-year what those prices have been. I'll move away from the revenue side and into the expense side a little bit and talk just for a second about the impact on gas prices and fuel for our combined cycle fleets. The bottom left is the takeaway from this slide. The basis continues to be compressed between Z6 and Leidy.
The competitive advantage that we've been able to enjoy over the years has been challenged to some degree, and certainly isn't where we were coming out of the polar vortexes that we had in 2013 and 2014 winter. Prices have come down from that standpoint. Prices have gone up in the Leidy region, but the basis has come down for us, and that's the impact that you've seen, and Dan's talked about quite a few different times on several of the calls. Makes it a challenge for some of our units that are worse in the heat rate standpoint, we continue to take a look at this and adjust as appropriate. Second thing, consistent with from an expense standpoint that you've heard from others today is our O&M focus and the driving down that we've done.
Pure O&M expenses have stayed relatively flat year-over-year going back to 2014. The O&M dollars per megawatt hour, again, because we've increased that denominator quite a bit, we've been able to drive and continue to expect to drive those prices down out through 2023. Probably the slide that you're most interested in is are we continuing on the capital investment side for the power business, the answer is, well, we're at the Bridgeport Harbor 5. We have no plans for additional investment, especially on the combined cycle side. We'll look for opportunities for power ventures and see where there's projects that make sense from a solar investment standpoint. Those are not in here. We never project those going forward. As they come up, we layer them in, we have no plans to go forward.
As a result of that, you can see what the impact is combined with our O&M spend, the ability for us to improve the cash flow projections all the way out through 2019. Capital program is reduced, O&M stays flat, we continue to expect, based upon those revenues and capacities, that we'll be able to improve that cash flow. Turning to the back end of it here, those are our operating earnings. Again, we've reinforced that coming out of the call, the first quarter call. We have no changes that we expect. There was some conversation during that call about our extended outage at our nuclear facility. All that information is updated on a regular basis on OASIS, if there's any updates that we have there, we'll pass that on through that process. Finally, pull it all together.
I think I just want to mention again, the highly efficient units that we have, the resulting portfolio and how it looks from a carbon standpoint being improved, the resulting cash flows that we have, and in my opinion, one of the best generation fleets that we have in the country. With that, I will take some questions.
If anyone has any questions, please raise your hands. I'll bring the mic over.
Maybe starting with the ZEC payment. In terms of the longer-term view on ZECs beyond the 3 years, how do you see that cycle playing out, and how do you make the case going forward that this should be an ongoing and not kind of phased out over time?
I just got to take you back to that one slide from a carbon-emitting standpoint in generation. As long as the policy of the state of New Jersey wants to value the attributes that those plants bring, I think the opportunity will continue to exist. If the policy of the state changes, I think that could be a challenge, but there's no indication that that's the case. We've been focused on matching the policy of the state for 100 years, as you heard earlier, and it's clear, to me anyway, that at least this administration wants to see as much carbon-free generation as possible.
Got you. Thanks. Then in terms of the basis impact, I know we've talked about this before, but you kind of mentioned that you'll take action as appropriate. What is the kind of range of options that you're looking at?
Well, just on a daily basis, when you take a look at how you're going to bid units and what's going on in the marketplace, you have to take into account what you can get your gas for. That's what we take a look at. I didn't mean anything more than that by it.
Got you. It's not like the higher heat rate units are at risk or something like that?
No, I think what we're trying to do though, is find ways. In the past, you may have heard us look for more megawatts, I think we're just trying to find more efficiency within the unit. Any opportunities that we have for technology improvements there, that's where we'll focus.
Got you. Finally. For capacity auctions, there was the move on the VRR curve. There have been actual weakness, at least from that perspective, in terms of where capacity pricing could come out. Net CONE changes have been made as well. How do you see that, purely from ignoring when the auction is held and all of those mechanics, but purely from a pricing perspective, how do you see that demand supply kind of playing out?
Yeah. We never comment on the capacity market, I won't do that. I won't break that rule. Dan will throw something at me. I think that you can read that information that's out there just as well as we can.
Got you. Thank you.
Hey, Ralph. Michael Lapides at Goldman. Couple of questions for you. One, can you remind us why the amount of capacity that you cleared in RPM declines each year for the next couple of years? I forget what the driver of that was.
I think it's just really our bidding as we're going through that process. I don't remember that there was one specific plant that we took out year-over-year.
Okay.
I think it's just pricing, right? Yeah. You're talking about the last couple of years, or if I go back to 2012?
No. Looking forward for the next couple of years. I'm just looking at your slide 83, where you go from nine gigawatts down to 7.7. It's not a massive move, a little over a gig.
I just think that's our position in the marketplace. In the past, we reduced a lot of the different units that we had, and I talked about the Mercer and Hudson and all those other units, but going forward, it's just our position in the market.
Okay. Can I ask a real high level, kind of taking a step back and thinking about this business. When you look at it relative to kind of where current power prices are, do you see this business growing? Is this a business that will grow its EBITDA over the next couple of years? Do you see it being flattish, kind of like it is 2018 to 2019? Do you see it in decline? I'm just kind of thinking big picture directional, if I were a generalist investor thinking about 25% of your business.
Yeah. Michael, I think the biggest factor that's going to impact us is operational performance, right? The more that we can perform well with the assets we have, the more that we'll be able to improve. There will be opportunities like we just talked about, where we've got breaker to breaker runs, you're going to be able to grow the business on days like that. If you do not perform that way, you're going to have reductions. From a growth, from an investment standpoint, I think we've been pretty clear that we don't see ourselves making any additional investments from a capital standpoint.
I guess in some ways a follow-up to his question, just heat rate-wise, what opportunities do you see over the next couple of years to improve heat rates, and how significant could that be?
Yeah. I think that what we've done over the past three years to improve our overall heat rate of the fleet has been to put these more efficient units in. I can't tell you what GE is going to bring to the table next week or what Siemens will bring to the table next week. I know they've in the past brought in AGP upgrades, which has been more focused on megawatts. When we have opportunities in talking to vendors like that, we'll continue to listen.
We have a follow-up from Praful.
Thanks. I guess I'll follow up. On the offshore wind side, it was helpful to get the color in terms of your discipline around the investment. Just trying to understand, what is the bigger picture around it? As in, is it an opportunistic investment in this, or do you see that as a more platform opportunity to do more in offshore wind going out in the future? Where do you see the offshore wind kind of opportunity longer term?
Yeah. Look, we've been pretty clear. Our opportunities on wind has been focused on the transmission side, right? The ability, whether you call it transmissions to generator lead, it's the wire coming from the generator in. I think that from a State of New Jersey standpoint, they've committed to 1,100 megawatts. Potentially up to 3,500 megawatts. We'll see how that progresses over time and whether or not there's opportunities for additional things that we know how to do well. What we do not know how to do is to install those windmills in the middle of the ocean.
Got you. It could be a bigger opportunity, though, as the transmission side of it builds out further.
It could, and we'll see. You can't even determine what amount of transmission or generator leads may be required until you see the awarding of the contracts and who gets them and how they're being planned to be brought onshore. Each one of those have different requirements and will drive different amounts of opportunity from a dollar standpoint.
Got you. Just a final clarification. When you bid into these transmission projects, what kind of return expectations are they? Similar we should think about from your utility side? Are you looking for high returns? How should we think about that?
I think you should think about anything we do in the generation business being driven by the same discipline that we've showed over the years. I think we've been pretty clear, even if you look at what we've done on the solar side, we haven't gotten way out front just because we want to grow megawatts. We grew it when it made sense. I think any investment that we make in the wind standpoint will be done the same way. We'll do what we know how to do, and we'll do it on projects and from a return standpoint that makes sense for us.
Thank you. Angie Storozynski with Macquarie. I have one question. Back on the fourth quarter call, you guys increased your outputs expectations for your gas plants, even though the gas basis is going against you, and it doesn't seem like power prices have gone up or the spot spreads have expanded. I was just wondering what was the reason for that?
I think I'll turn to Dan if you remember exactly what was said there, but I thought it was something that had to do with the timing of when the plants were coming online for this year. Dan's nodding his head. In addition to that, some of the operating that I mentioned before, these plants have been running a little bit more as they've come on, they've run a little bit more than maybe we had originally planned from a timing standpoint.
Okay. My second question is, I always ask this question, I admit, about free cash flow of the other power business. Is there a rule of thumb, for instance, how much of that free cash flow is used to finance regulated utility operations? I understand that this is probably more for the finance section.
Yeah, I'll let Dan take that later. You could see from that one chart that we have there, what the free cash flow looks like over the next four years. Take out your ruler, you can get an idea.
Okay, thanks.
Hi. Andrew Weisel from Scotia Howard Weil. Just one more quick follow-up on the offshore opportunity. Would you be interested in building transmission for offshore wind outside of New Jersey, or do you really see your footprint staying local?
I think we know what we know. We know New Jersey really well. If we learn how to do more from this standpoint, I think we could look at any opportunity. Picking up and building offshore transmission to, I guess, Ørsted's coming in Taiwan, I don't see us doing that. There may be some opportunities for us. I would say it'd be around our East Coast, real close by, Mid-Atlantic.
Okay. Your MOU is specific to this one project so far?
Yes.
Okay, great.
I just want to be clear in answering your question, it's not just tied to Ørsted, right? If there's opportunity, somebody wants us to help on transmission, we're always open to it.
On solar, I think I heard you say you have no CapEx planned in the budget. You're opportunistic. How big would you be willing to let that business grow? What's the limiting factor? Is it capital investment, earnings mix? How do you think about the sort of a cap?
I think it's really based upon, and I'll give this to Dan at some point if he wants to touch on it on the back end, but it's where it fits our profile. If someone came along and gave us a FERC-regulated rate of return type of investment opportunity, we would take a look at it because we know how to install solar.
I think if you take a look at what we've done from a solar perspective of late, they have not been huge dollars, but the returns need to fit. It's really going to be return-driven.
Any further questions? Then we'll turn it over to Dan.
All right. Yeah. I'll bring up Dan. Finish up and then some questions, I think Ralph will join him at the end.
All right. Good morning, everybody. I'm going to wrap things up here, give you an overall snapshot of the financial picture on the right slide. I think ultimately what you're going to hear about is going to be very consistent with the story you heard today. I think you're going to hear about a company with a lot of balance sheet strength. I think you're going to hear about a company with a lot of investment opportunities. I think those investment opportunities are going to be aligned with what the state's trying to get done, aligned with issues surrounding climate change, and ultimately aligned with the state policies in New Jersey. To start, this slide really tries to summarize a lot of the items that you've heard about today.
I think at the utility, one of the things you've heard about from Dave, you've heard about a diverse rate base involving transmission, FERC-regulated returns, electric and gas infrastructure spend, as well as energy efficiency, and maybe a little bit of solar investments on the utility side as well. That rate base has compounded 13% over the last five years and has a good outlook as we jump off of our $19 billion current base. Dave talked about a rate case settlement that I think has served the state well, and I think has served us well, and I'll go into just a touch more detail about that in a slide or so. Also just a year ago, we were here, and it was right after GSMP 2 was approved.
It's a 5-year program, if you really think about it and all the cast iron gas that we have in the ground, that's going to go on probably for another 20 years to take all that cast iron out. It is a program that I think as we go into each of these situations and we have challenges on both sides of the aisle, I think on that particular program, there's very little opposition that work needs to continue to go on, and certainly is our longest lead time piece of work that we have. At Power, we've talked a lot about the efficiency advancements we've made in the fleet from some of the new units that are coming in. Also the stability at nuclear by virtue of the ZEC awards, and again, aligning with state policy and what the State is trying to get done.
Net-net, that brings you to three-quarters of our overall results coming from the regulated side of the business, a strong balance sheet, and really a sustainable business model if you take a look at some of the climate items we talked about earlier. From there, if you think about the opportunities for growth that we have, we've talked a lot about the 7%-9% rate base growth that we have over the next 5 years, and Energy Strong II, and energy efficiency pending in front of the BPU. Big programs, big opportunities there. Behind that, most visible is the three other programs that Dave talked about related to electric vehicles, energy storage, and AMI. Those all remain. Bridgeport Harbor going in service, as Ralph talked about. You saw steam, not commercial yet, but very soon.
A 7-year lock on the capacity price gives that plant a great head start as we go forward. Maybe as importantly, brings an end to the growth construction costs and frees up a lot of cash flow for the business. I will talk a little bit about how and where that ends up getting used in the sources and uses slide I'll show in a little while. What it does mean is that 90% of our capital gets pointed at the regulated business. From 75% of the business being regulated, we also have 90% of that capital going towards that side of the business, which will add to the stability as we grow the business. All being funded over the 5 years without any additional equity, a commitment to the dividend growth.
I think in aggregate, not a ton of news coming out of this day, I certainly think a very good coherent story that the company has laid out for you today. The growth that we were talking about clearly is grounded in the utility investment program, doing all the right things for the State of New Jersey, from a resilience standpoint, from an efficiency standpoint, and from an environmental profile. Basically, the growth is going to come on that regulated side and Ralph showed a 10-year picture, bringing us to about three-quarters of our total profitability coming from the regulated business. That will drive the earnings. If you move over to the right-hand side, you can see in 2019, our non-GAAP operating earnings up 4% to $3.12 at the midpoint of our guidance from the $3.12 in 2018.
Ultimately, those cash flows that we're going to get from both sides of the business, again, sources and uses will give you a very good picture as to where those cash flows are coming from. With strength on both sides of the business, we'll be able to drive the dividend currently at an indicative annual rate of $1.88 and continued growth anticipated there. If we stop real quick and take a look at 2018 and 2019, we give a little bit of indication as to how we have moved from 2018 into 2019. First at the utility. Clearly, increases that you will see in earnings from the investment programs that we've been talking about today. In addition, that distribution rate case, David Daly talked about and Tamara Linde talked about, a 54% equity slice. We went in with a 51.2% equity slice. We see an increase there across all PSE&G.
Also a tax flow back, which I think worked extremely well for customers in the state. We had not been in a rate case since we filed one last in 2009 and came out of that in 2010. Basically, rates came out the other side flat. That had a lot to do with the tax flow backs, the excess taxes, deferred taxes, that we had on the balance sheet, and our ability to pass those deferred taxes back to customers, enabling that bill to stay flat. Reducing those deferred taxes, given that deferred taxes are a reduction from rate base, actually does grow the rate base of the company over the five years. Overall, an increase in base rates, a decrease by virtue of those tax flow backs, very effective in keeping rates flat, but being able to continue to grow the business.
At Power, if we take a look at where we are, the operating earnings range reaffirmed at $395 million-$460 million for 2019. Some puts and takes that you see at Power. We've talked about recontracting on the energy side being a headwind, as well as capacity prices. Ralph LaRossa laid out year by year what those RPM results were every year, and you did see that one trough year that starts beginning in June of this year. On a month-by-month basis, more so than an annual basis, since RPM is done on an energy year basis. You will see a decline in the capacity revenues, and that'll be a drag year-over-year as we step through time.
Tamara Linde talked about our beginning to accrue those ZEC payments in April upon our selection by the BPU of receiving ZECs. That will be a help this year, as will the increased generation volumes at Power. One other item that's not always picked up in models is the fact that during construction, we take the interest expense for the funds we're deploying into capital and capitalize that interest expense. When that construction comes to an end, the ability to capitalize that interest comes to an end. There's a drag that we'll see with the end of construction from the standpoint of P&L on the interest expense and the ability to capitalize. All in all, a 4% increase as we go from 2018 to 2019 at the midpoint, and some color on the components between the companies involved.
On slide 97, we move on just to a little bit of a more detailed look at the overall $11 billion-$16 billion capital program at the utility. Dave spoke to this. The gray that he spoke of on the transmission investments, really all about improving reliability and hardening system resiliency, as well as some life cycle and 69 kV projects. Dave did a good job explaining those. 69 kV, in fact, if you take a look at what that's doing, that's taking 26 kV circuits, stepping them up to 69 kV. When that does happen, we move from distribution rating to transmission rating. That moves it out of New Jersey's jurisdiction into FERC jurisdiction where we have contemporaneous 11.68% ROEs. That's all approved by the BPU as that makes that move as it changes jurisdictions.
Just right of that, on the distribution side, really split into two pieces, we've called it distribution maintenance and distribution growth here on the slide. Really, the distribution maintenance is spend to the extent of our existing depreciation. Formulaically, just think about that as we're depreciating down, we're spending capital back up, and we're restoring that rate base to where it was as we came out of the rate case. Distribution growth, you see $3.1 billion as we step through the five-year period. A lot of that is the GSMP program that we talked about. You recall $1.9 billion over five years. The rest of that is new business and other work that's going on within the distribution side.
Lastly, the two clauses that Dave talked about, Ralph rightly pointed out, that while we do have $6 billion in total programs in front of the BPU, this is a five-year look. Those are still pending, so some of that money actually falls off the five-year plan and would move into 2024 if you take a look at it from a full program standpoint. All in all, this basically makes up 90% of Enterprise's total capital program with good clause recovery as we've talked about during the day. If we step back as well and we take a look at 2019, and we take a look at where we believe rate base will end in 2019, right now we have $20.3 billion-$24.4 billion in total rate base at the utility forecasted for the end of 2019.
If I look at that same amount and I go back a couple of years at each of these events, the last two years, that would've been a number closer to $19.1 billion if I looked at it from a 2015 standpoint. Would've been $19.6 billion if I looked at it from a 2017 standpoint. As we build our plans, as we build our capital programs, and you may recall when you look at Dave's program year by year, the front years were higher than the back years. We have failed to bring that to fruition every year because we've been able to find investments to fill the back end of that. That's a good failure on our part.
If you take a look at what we see here from a rate base perspective, the continued growth, not only growth in the number, but growth beyond what we have anticipated, shows that ultimately we've been able to deliver on what we've said from a rate base growth perspective and beyond. The way we fund that rate base growth can be seen really from this 5-year look at sources and uses. The left side gives a snapshot of PSE&G standalone, and the right side gives you a snapshot of Enterprise on a standalone basis. That PSE&G capital program we've been talking about shows on the left-hand side in that green area, the right component labeled PSE&G cash from investing.
Ultimately, that depicts the dollars that we're deploying at the utility to be able to grow the rate base and do all the things that we've been talking about all day. Left of that in the blue is PSE&G's cash from operations. We talk a fair bit about what we spend at the utility, and we don't always talk about how much comes back to us. Through those recovery mechanisms, we have a pretty strong positive feedback loop to bring cash back into the business, and that's depicted by that light blue section on the left-hand side. Ultimately, everything is financed based upon that cap structure that we talked about, 54% equity slice, 46% debt. As we grow the business, that debt component grows as well, and that's what you see on the bottom of the left-hand side under PSE&G net debt.
That's issuances net of redemptions that we'll have over time. Ultimately, you see a dividend to the parent. Once again, I'll harken back to what Dave talked about before, higher capital on the upfront part of the plan, lower later on. Those dividends to the parent will tend to come in a little bit later within the 5-year period. Perhaps as we push out that capital line, you'll be able to see less of that dividend from the parent coming from the utility if there is more capital deployed within the 5-year plan. Move over to the right-hand side and take a look at what Enterprise looks like. A lot of those same components survive intact. You look at the cash from investing, cash from ops, and the net debt of PSE&G. What does come in is Power's free cash flow.
That number has grown as we have shown this year over year for the exact reason Ralph talked about. That capital program coming to an end, the combined cycles going in service, and less of that cash flow going into Power itself, and more of it being available both for the utility as well as for the enterprise dividend. To the question that was asked before, money is fungible, but you can see how much cash flow from Power's coming in. You can take a look at the shareholder dividend, a piece coming from the utility, and ultimately funding, I would argue, by both Power's free cash flow as well as PSE&G's cash from ops over the 5-year period. That cash from our sources and uses ultimately flows into our credit stats foundation, basically how we take a look at our overall debt capacity.
Just as a reminder, our debt capacity is essentially looked at by taking a look at our minimum threshold for our credit ratings and looking at what our overall FFO to debt is against that minimum threshold. That excess that we have within that credit stat really is what derives our ultimate excess debt capacity. When we start on the left, we go backwards a little bit. We take a look at 2015, and you see what I would call an outsized or inflated amount of debt capacity at that time. If you rewind the tape and you think about where we were in 2015, one of the things that was going on at that point in time was bonus depreciation.
For such a capital-intensive industry, and you think about how much cash is coming in through that accelerated depreciation, really what you're getting is an acceleration of the cash flow that you would otherwise have gotten by depreciating all of your capital. If you're getting it then, you're not getting it later. Basically, it was just a front load of cash, non-incremental cash. That helped to pump up basically everybody's credit stats at that time. By definition, would actually hurt credit stats as you go through time because that same cash flow that you would have expected to get in those out years was no longer available to you. It was already in your pocket. There's a couple of billion dollars that's embedded within that 2015 amount back at that time related to bonus depreciation.
As we have stepped through time, we've utilized a fair bit of that capacity, some literally by virtue of the stats coming down because of the tax deltas. Also by virtue on the far right, if you take a look at the blue, by PSEG Power investing in its own growth through the combined cycle construction program. Outsized from that, you see the utility capital spend and supported by both sides of the business and also the shareholder dividend absorbing cash flow as well. As we have stepped through time and you take a look at 2018, a little over $2 billion in remaining excess debt capacity. Nowhere near what we had years ago, but again, I would call that years ago inflated.
I think good uses of our debt capacity as we've looked over the last three years, and as we step forward, I would argue we will continue to utilize that debt capacity in a very favorable way. In the middle of the page, you see how that debt capacity is going to change over time. It'll bridge you from a 2018 snapshot into an average of the next three years. Clearly, PSE&G's own cash from ops and PSEG Power's meaningful cash flow are adders to be able to grow that debt capacity, but they will be absorbed by PSE&G's capital spending. Those are your main moving parts if you just want to follow the numbers as you step through time from the standpoint of cash coming in and cash going out. There's a final bullet on the bottom here, which I think is also important.
We've talked about growing up to an amount of 75% of our earnings coming from PSE&G. We've talked about deploying 90% of our capital into PSE&G. As we have stepped through time, and as we continue to step through time, you will see a stronger, more regulated business mix as we move through time. What that is likely to do is take a look at what that minimum threshold is for our ratings. That business mix could end up lowering that minimum threshold. A lower minimum threshold drives incremental debt capacity as well. None of that is reflected within what we show here. That's one other item that I think could continue to move as we go forward and would move in a positive fashion.
If I think about the deployment of capital, ultimately on an enterprise standpoint, using it in the way that we have used it, I think has also been extremely aligned with the climate change issues that we've talked about earlier today. On this page reflects from investments made about $5 billion. There's solar investments both at the utility and at Power that amount to about $1.7 billion. Swapping out coal units that Ralph talked about and replacing them with state-of-the-art combined cycle units. Also ensuring the resiliency of the grid through Energy Strong and anticipating some energy efficiency investments on top of the ones we've already made.
As we look forward and we think about climate change, a more resilient grid is going to be extremely important to withstand the storms that I think we're likely to see more and more and have seen more and more as time has gone on. The suite of investment proposals that we have starts with the Clean Energy Future in trying to adjust what goes on from a climate standpoint, but also deals with Energy Strong II about strengthening the grid. It certainly is aligned with what's going on in New Jersey from a policy standpoint and a legislative standpoint. Everything that you see on this page, very aligned with climate change. I would argue this is not a new phenomenon for us as well.
We identified a quote from Ralph that goes all the way back to 2007. You can read it yourself. It implies the exact focus that we have had in our business to try to move in that direction. I think Ralph showed that slide earlier and showed the declines that we have seen from ourselves, how we compare across the country. There's more work to be done. We think that aligns extremely well with the proposals that we have in front of the state. From an O&M perspective, Dave talked about his O&M. Ralph talked about his O&M. If you take a look at everything that's here, it really is what we do on a day-to-day basis.
I think on Ralph's slide, the phrase said, "Our O&M control is always on." That points out to what Ralph talked about earlier, that we're not coming up with programs from time to time, stepping back and taking our foot off the accelerator. We are always focused on cost control from vendor arrangements, from refining the organization, thinking about some of our long-term commitments, identifying best practices. I think increasingly looking towards technology as well to help us drive where we need to be from an efficiency standpoint. The discipline that we have in running the business is the thing that will enable us to show charts like this as we come here year after year after year. Great work there by a whole host of people throughout the organization.
Net, what this gets us to from an operating earnings perspective is growth that you've seen over the past few years, as well as a 4% growth as we go from 2018 into 2019. Really, this is, to me, all about delivering on our commitments. Whether that's getting people back after Sandy, whether that's deploying Energy Strong, frankly, faster and cheaper than we went in and asked for, whether the state having confidence for us to go and do all the work that we need to do on the gas pipes and having the confidence for the proposals that we have in front of them now. It's all about delivering on commitments and deploying the financial strength that we have ultimately for the benefits of customers, to derive growth in earnings as well as growth in the dividend.
What we do on a day-to-day basis really enables us to have the confidence to say that we have an opportunity for consistent and sustainable growth in the dividend. What you see here, really, I go back to that same business mix comment that I talked about earlier. Think about the magnitude of our earnings that's coming from PSE&G. What that means from the standpoint of our overall dividend, you've got a stronger base from which to be able to pay the dividend and look for growth on a go-forward basis. That wraps up the remarks from a financial standpoint. I think, in sum, really the story is delivering on promises, enhancing ultimately the portfolio on both sides, and providing returns to investors and benefits to customers.
I think what you've heard today is a consistent story with what's been in the past and a continuation of that as we step forward. With that, I think Ralph will come up, and we'll take some questions.
Stay together.
Hello. There you go. Just kind of two higher-level questions. I guess one just starting for Ralph, and it kind of goes into what Dan was saying as far as the mix of earnings and how they'll continue to change. Just strategically, just as the years have gone by, you've done very steady eddy, and you've done a great job in transforming the company, given the fact that you have a big power portfolio as well. What are you thinking, if anything, strategically? I mean, you have the ZEC now. You have stability at this point on the power side. Things have changed as far as investors' view of power over the last couple of years. As the earnings mix continue to change, just strategically, what are you thinking? I have a follow-up.
Sure. What we've been telling people, Andy, is that we have to stop considering ourselves to be a generator and purveyor of electrons and gas. We have to think of ourselves as an infrastructure company. A quiz that I give whenever I speak to investors or policy groups, I'm going to give to this group here, and it's less about your knowledge, and it's more of a quiz of your honesty. The quiz is one question. How many of you woke up this morning and said, "I can't wait to use a kilowatt hour?" All right. That's typically the answer I get. Now, you may have woken up and said, "I can't wait to watch a ball game," or, "I can't wait to read a book." Or maybe you woke up and said, "I can't see the stairs.
Let me flip on the light switch so I don't break my neck." Electricity and natural gas are a means to an end, and we have to think of ourselves as the company that provides the infrastructure to allow you to achieve that end in a way that is least cost, environmentally benign, and more reliable than ever before. That has really three to four components to it. Number one, to help you live your life today while using less energy. In doing so, help you lower your bill. Number two, efficiency won't take us to the point where you're using zero, right? There's always going to be, even an LED bulb uses some electricity. Higher SEER ratings on HVAC systems use some electricity and gas. That supply has to have a mind towards climate change.
It has to be cleaner than ever before, we took the most important step in New Jersey of achieving that just recently by preserving the existing nuclear fleet, in the future, that's going to be further investments in renewable energy. As we enhance the cleanliness of the supply and as we reduce what you're using today, that creates an opportunity to further electrify the economy. The first step in electrifying the economy is really transportation, because that's surpassing in many places, certainly in New Jersey, electric generation as the number 1 source of carbon emissions. Then number 4 is as we further enhance the use of electricity throughout the economy, if you think people were grumpy during Sandy when they couldn't charge their phone after two or three days, wait till you see the reaction when they can't drive their vehicle after two or three days.
Resiliency becomes increasingly important. I think in every one of those four steps, in energy efficiency, in cleaner supply, in further electrification of the economy, in greater resiliency, there are investment opportunities for us.
Okay. Beyond all that, the bottom line is PSEG kind of stays as PSEG is as far as the structure of it.
Yeah, I think that's true, we get a greater share of the customer wallet because the customer is spending money on thermostats, light bulbs, vehicles today, we, at PSEG, are not participating in that.
Kind of what Dan was talking about, just again, on a high level. As the earnings kind of mix continues to grow towards more regulated, as the cash flows continue to improve and the balance sheet continues to improve, for the shareholder, what may we see? May we see a higher growth or kind of a growth rate that you'll actually talk about beyond one year out? You're talking about 4% this year, but as things become more consistent, maybe we do get a growth rate. Also, you kind of made reference to the dividend, and as the payout grows, can maybe we talk about dividend policy in conjunction with what you were talking about. Also last part is free cash flow. What may be done with that cash beyond, is it investments? Whatever it may be.
I'll start at the beginning. I think what you're seeing from a free cash flow standpoint is the ability to deploy it back into the business in all the ways that we talked about today. Maybe just to touch for a second on the balance sheet. The balance sheet will continue to get stronger as cash flows come in and will continue to be utilized as investments are made. It's going to be an interplay between those two. We have a pretty wide range ultimately in what we're seeing from the standpoint of total investment proposals that are in front of the BPU. The more we are able to deploy into the business, the more we'll utilize the balance sheet. It will strengthen as it comes back in.
Net net, that will be a utilization more so than a growth in the balance sheet.
Andy, I want to try to demystify the future earnings potential of the company without giving you earnings guidance that we're unable to do. You've heard us talk about 75% of the business is regulated utility, 90-plus % of the CapEx is going to be regulated utility. It's safe to assume that barring some major disruption in commodity prices, that 75% is going to be a bigger number. Now, the earnings of the utility will deviate from that 75% to the extent that we have load growth, which has been zero, and to the extent that we have O&M growth, which has been zero. You have 7%-9% growth plus or minus zero. You could do that arithmetic, and Dave did some of that for you, right? He showed you that chart.
It can be some small number epsilon deviation from that. We've got this other business that's 25% and shrinking, and you know what 65% of the gross margin is. You do have to back out some of the fixed charges associated with that because there are some green fees in there. Not golf. Renewable portfolio standard type stuff. You know the capacity markets, you know how we've hedged our energy markets. There's this 35%, if you allow me to be generous to us, because there are some unknowns in that 65%. There's 35% of 25 of the business, 25% of the business that you don't know about. And it's not because we don't want to tell you, it's because we don't know about it. It's supposed to be 72 degrees next week in New Jersey. That's ridiculous. It's June.
It shouldn't be 72 degrees in New Jersey, but that's going to affect power prices, right? Hopefully it'll be hot and sticky in July. I think this notion that folks want to see more earnings guidance in the out years, we give you as much as we know, and we promise to continue doing that. The dividend is going to be a function of various parameters, which is what are the capital needs of the business? Are there attractive, on a risk-adjusted basis, investment opportunities that allow us to grow the business? We like the fact that we don't have to issue new equity to grow the business, and therefore, retaining some of that earnings and retaining some of that cash flow to fund the business is helpful.
The fact that the utility is now, I think, 130% of the dividend gives us greater confidence in the sustainability of that dividend growth. I know what you're fishing for. We can't promise that we're going to match the utility growth and the dividend growth or anything of that sort. It's a set of factors. What are our competitors doing? Competitors for shareholder equity. What are other utilities growing their dividend rate at? Where are interest rates? I think the 10-year bill is now down to 2.2%. We're yielding, unfortunately, as a result of today, about close to 4%. It's a myriad of factors that we consider in deciding the dividend policy. Greg?
That's a good segue to my question. You've got the $2 billion-$2.5 billion of balance sheet capacity, and theoretically, if that all goes into the utility, you can leverage that. If you're 100% successful in convincing the state of the efficacy of the spend that you've proposed, when does that balance sheet capacity get expanded, and you become an equity issuer? Or is it so far out as to not be a reasonable question?
Yeah. It is not within that timeframe. If we get 100% of everything we ask for, which we don't, we would still be able to fund that without equity.
That's through this forecast period?
Yeah. That's right.
Thank you.
Can I ask a question? Okay.
Angie?
Yeah. We've been hearing from other companies, especially the coastal ones, that on the wish list of things that they would want on the distribution side is a storm cost tracker. Given the storms that we had last night here, just remind us how New Jersey is dealing with your storm expenses and how those have been impacting your O&M trends on the distribution side.
Well, if you remember, the last rate case had a $220-something million rate increase offset by return of some deferred taxes and a repair allowance. In that rate increase was our ability to pay down the deferred storm expenses over a five-year period from that mistake. We don't have a storm tracker per se, but each storm, on a case-by-case basis, we will speak to the regulatory staff about how much, if any, should be deferred for future rate recovery. It is deferred. That's right. Correct.
Hey, guys. Just as the offshore wind starts to develop and you're looking at incremental wires opportunities, how do you think the discussions around cost allocation will start to evolve in that process? I.e., should we be thinking about New Jersey bearing the cost of offshore wind wires or PJM? What sort of rate pressure do you expect if it's borne purely on New Jersey?
Yeah. The way the state has proposed this first solicitation is through something called an OREC, an Offshore Renewable Energy Credit. I think that there's going to have to be some recognition on the part of the state as to what the impact of that could be on customer bills. The good news is everything we've seen in terms of offshore wind solicitations has yielded fairly robust price declines. I know it's public, but I may not get the number exactly right. Some of the early solicitations off of Rhode Island and New York were $200 a megawatt hour in north, and you've seen that come down in Maryland to like $160. I believe Massachusetts recently was like a $70, $75 per megawatt hour number. It remains to be seen what happens in New Jersey.
To the extent that SRECs are trading at $220-$250 a megawatt hour, that is going to suggest that whatever we see in the OREC is going to be quite a bit cheaper than rooftop solar. That's not a surprise to anyone, right? Rooftop solar is the single most expensive form of renewable energy that has been invented by mankind, and we continue to pursue that path. The big difference, however, though, is that when you're spending a lot per rooftop solar megawatt hour, but you're not producing many megawatt hours, that product is still a sizable number in New Jersey for the past three years. That's been $600 million-$700 million a year, which is a big number, obviously, and we're not blinking that away. That took almost two decades to get to that point.
If we do 1,100 megawatts of offshore wind, and let's just use a number like $100 a megawatt hour, you're going to see an incremental $250 million-$300 million in above-market expense being asked to be paid for by the customer. That'll be a big impact real quick. Rapid decarbonization is something that matters, and it's important. There are other benefits besides just carbon associated with renewables, obviously, NOx, SO2, ozone, things of that nature. I do think that as we move forward on all of these initiatives, the two most important things we can do, both from a customer point of view and a carbon point of view, one we've done, keeping the nuclear plants online, and two we haven't done yet, and that's energy efficiency.
Cost allocation will be spread among New Jersey customers, because that is a New Jersey program to develop offshore wind. I guess that last sentence was the answer to your question. The first five minutes was something I wanted to say. John. There you go.
Ralph, can I just
Whoop. I'm sorry. Praful, let's give Jonathan a chance here, and we'll come back to you, okay?
Ralph, I just wanted to come back to the strategic question because in your answer, I wasn't sure I really kind of quite got what's the strategic benefit of maintaining that 35% of 25% that kind of takes that ability for the overall company to grow with any certainty away. Once you've got the ZECs on
Yeah
nuclear plants, why retain the fossil?
Hopefully what you heard me say was that 25%, if we have our way, which is based upon filings in front of the BPU, is going to become a smaller number. What hopefully you saw Dan describe was something that is helpful to be able to answer Greg's question of not issuing new equity because the capital program at Power is such that we are going to be a free cash flow positive there for the foreseeable future. Candidly, Jonathan, after what we've just been through with nuclear, we have, I believe, a sociopolitical obligation to retain those nuclear units, right? People genuinely trust the things we said and the way in which we operate those plants. We probably have more flexibility around the fossil plants, but they're our biggest free cash flow generator right now.
You have a growing regulated component, a shrinking unregulated component that's a nice free cash flow generator, and 55% of its output we have kind of a sociopolitical obligation to retain for the foreseeable future, just given the amount of trust that's been put in us.
I guess bringing-
Praful.
Yeah. Bringing some of that together, right? The competitive advantage that you guys have from a balance sheet perspective, given the bonus depreciation roll-off, given a lot more utilities probably do need to issue equity to strengthen balance sheet to keep the growth going into the future. You clearly have that competitive advantage. I guess the question is, how do you use it, apart from obviously not issuing equity, which is a big strength? Are there other ways that you can monetize that competitive strength of what your platform currently offers?
For example, strategically, M&A-wise, is there anything or any other broad themes that you think this gives you, which you can utilize?
Yes. We've always said we'd love to replicate what we've done at PSE&G in becoming. Remember the two stories of PSE&G have been, one, replacing an aging infrastructure, and two, adhering to public policies direction, which we think, notwithstanding the fact that it's taken 12 years, why do we have to show that was 2007? Was that a good thing?
Yeah.
To replicate that model in other places, the problem is those other places are just very expensive, and we're not going to do that. We've tripled, if not quadrupled, the size of PSE&G without having to pay a premium for control, extortion to sometimes regulatory bodies that have to say yes to those acquisitions and various other things. Yeah, if we could replicate that model elsewhere and for a reasonable price, then we'd be open to do that, but we haven't seen that opportunity.
Fair enough. Thank you, guys.
The other thing to add, Praful, is it kind of goes to Andy's question before about kind of in the question was implied you continue to invest, and you would strengthen your balance sheet. That investment is going to be utilizing that balance sheet strength, not adding to it, even with the best of regulatory recoveries. We do have great recovery mechanisms, but every $1 we deploy, we don't get that $1 back right away. It is using balance sheet, and that is, as I referenced earlier, the best use that we have of that investment capacity, and we have a lot of things in front of us.
Thank you, guys.
Ralph, can you talk a little bit about the FERC? We've obviously seen some changes at the FERC over the last year, unfortunately. Can you talk a little bit about some of the key dockets, not just the RPM, the capacity market one, but the transmission? The ROE look docket hasn't come up at all in a lot of utility discussions, but it's being looked at across all of energy infrastructure, transmission pipes, et cetera. Can you just talk about kind of your outlook and how you do your planning around where to invest capital, given these are still outstanding items ahead of the federal government?
Yeah. I think Tammy hits that best. Whatever FERC does, FERC has demonstrated rational thinking, we'll adjust to. Fast start was a good outcome. It was months late, but we know about some of the issues that in terms of FERC leadership and the health issues surrounding the prior chairman, unfortunately. I won't talk about RPM since you suggested I not. I don't think we're going to see much in terms of fuel resiliency and concerns about baseload generation. DOE has taken that mantle up a couple of times, FERC at least once has responded by saying, "I'm not going in that direction." The ROE look has been out there for many years now, in fact, I think we have demonstrated the tremendous benefits associated with our transmission investments in terms of decongesting east-west power flows.
If I can remind you, it wasn't that long ago that the basis differential was positive $20 to the PSE&G zone, now it's negative $1, negative $2. A lot of that was due to the transfer capability investments that we've made. I can't speak for the chairman. I really don't know more than what you've read and I've read recently in terms of his public comments, that they are focused right now on PJM and RPM. They have a growing interest in cybersecurity, and I think we take it one appointment at a time. Until we see some change in the membership, my guess is we're not going to see many significant orders coming out of FERC.
There does seem to be a little bit of a different point of view on major policy issues that's kind of leading them to a bit of a paralysis right now.
Ralph, one follow-up. Your neighbors to the north, both Consolidated Edison and National Grid, have basically publicly come out and said, "No more natural gas connections.
Yeah.
That seems largely kind of a pipeline issue of getting new pipeline capacity, whether via new builds, expansions, compression, or some other mechanism. Do you see a similar issue impacting New Jersey at all? What's your viewpoint on whether some of the proposed pipelines, whether it's PennEast or others, actually make their way into New Jersey over the coming years?
we pass with our gas distribution business, I think 98% or 99% of our customers already, and maybe 100, and we don't have anything in the way of oil to gas conversions or any kind of additional capacity constraints that exist in those other jurisdictions that you've mentioned. Our issue is more the issue that Dave pointed out. We had a pipeline go out in April of 2017, and I'm not casting stones. It was an interstate pipeline run by a very well-run company and a well blew, and it can happen to anyone. Had that not happened in April, had that happened in June or July, we would have been making decisions about whether to illuminate homes or heat homes. We were in literally daily conversations with our BPU regulators wondering if that pipeline would be back in time for the winter heating season.
Fortunately, it did come back in time. What Dave talked about is we are adequately supplied by gas pipelines absent operational disruptions. Rather than rely on additional pipelines to meet the needs of a growing gas market, and while our electric load has been flat, our gas load has been growing a couple of percent per year, I think 3% or so for quite some time now. We would rather be able to have the flexibility to move gas across our territory, because we have confidence that it could continue to be fed by pipelines that are not experiencing operational challenges. That's an active source of conversation in these confidential settlement discussions on Energy Strong II. We don't have the issues that some of our colleagues have in terms of supply.
We do have issues in terms of, should that current supply be disrupted, can we supply the whole territory in a way that it's accustomed to being supplied? The answer to that is no. I can understand where if you have a territory that doesn't have adequate pipeline capacity coming in, you might have other issues. We don't have those issues. Angie?
Yeah. electro transmission CapEx is such a big portion of your growth plan for the next five years, and it has been over the last couple of years. Two questions. One, how sustainable that level of spending is. Is there a gauge of how old your systems are that would give us some sort of a reassurance that the five years out, there's still plenty of transmission CapEx to come? Number 2 is when I think about transmission CapEx for offshore wind, is there like a rule of thumb how expensive this type of underwater transmission line is so that we can gauge potential upside to that CapEx?
On the transmission build, you're right, it is coming down quite a bit compared to some of the bigger projects. I would ask you to just think of two things. Number one, we're in the process right now doing a project where the average tower age is 90 years old. It's not like we're replacing the 50-year-old stuff just yet. The age of the infrastructure is quite a challenge for us. Number two, remember, we still are in a competitive wholesale power market, and PJM's RTEP, Regional Transmission Expansion Plan, is its first and last line of defense for the reliability of the bulk power system. PJM, and we, no longer decide what power plants get retired and what power plants get built or where they get built.
There's constantly an effort to look at that and respond to decisions by private equity, by merchant generators to retire or add supply in different parts of the system that affect investment in the system. I don't know the answer to your question about is there a rule of thumb. It really does depend upon where the offshore lease is, where the generator lead connects. It is not the biggest part of the investment, that much I could tell you. I'd rather not throw a number out there, but it's certainly far less than half of what the investment costs will be.
Far less.
Far less.
Far less.
Dan is muttering far less.
Does anyone else have any questions?
Question on the sustainability of CapEx at the utility. The Energy Strong II and GSMP 2 are pretty big programs, obviously. Would I be correct in assuming the limiting factor of prioritizing is affordability? If so, suppose there were to be a version three or four or five down the road, for how many years do you think that level of spending would last to get all the systems modernized the way you'd want them to be?
You're correct. It's affordability. Think about GSMP 2. That spend rate, that's a $1.9 billion program. It's 5 years, so that's about a $400 million program. I think that takes us another 20-23 years to replace what is currently a 100-year-old system. The aging infrastructure, at the risk of sounding like a broken record, we're not talking about relatively old stuff. We're talking about-- It's not wood pipes the way there are in some parts of the country, but it's just a half a notch better than that. What we've tried to do is lay out a program that because of the combination of clause recovery, which allows you to adjust rates every 6 months, and a funding level that seeks to match CPI, will allow us to basically keep pace in real terms with flat rates.
Now, the reality is people don't think in real dollars, they think in terms of what they're writing on their checkbook, and that will be inching up. But we think it's far better to let it inch up 1%-2% per year than to wait 5 years and go in for a 2% compound annual growth rate over 5 years and ask for a 12% rate increase. Even though you could say to people, "Hey, we haven't changed rates in 5 years," that memory, that recognition doesn't always serve you to the extent that perhaps it should in a reasoned world.
Yes, it is affordability, keeping rates flat in real terms while changing a century-old infrastructure, and at the same time then helping to reduce bills, not rates, but bills, for those customer segments that policymakers decide are most important from a bill production point of view, which in the past has been our energy efficiency program targeted at hospitals, low-income customers, and folks of that nature.
Any other questions?
Greg over here, Carla.
Oh.
If PJM goes ahead and holds the auction in August, do you expect FERC to invalidate the results? If so, what is the impact on your business? Is it a material impact?
Our expectations, which again, Greg, it's based on the same information you have, is that it would be unlikely that FERC would announce in advance that they are or are not going to invalidate the auction, just because that preserves flexibility for them. However, in the past, FERC has not often invalidated results. I think what we would expect to see is FERC preserving their option to invalidate, but probably not invalidating. I don't mean to suggest at all that we know how to predict what FERC will do any better than anyone else in the room.
I think just on impact. If they have an auction, FERC invalidates it the next day, there's really no impact. The following day, there's really no impact. For us, until we roll through into the next BGS auction. From a capacity standpoint, nothing will happen for three years. Keep in mind, the BGS auction does look forward three years. That's the first time you would see any impact, is that the ultimate BGS bids would be presumptive of the known RPM prices, which if they're changed after they're known, could be an impact. There's many months in that timeframe, and you would think if anything would happen, it would happen before that auction.
Thank you.
There too, Dan, if I'm not mistaken, that would just be one-third of the BGS auction capacity.
Right.
If there's no more questions, I think we're going to conclude, Ralph.
Thank you for joining us today, and the story remains intact. I know there was some comedic relief when I mentioned that this would be an opportunity for you to catch up on your sleep at the last quarterly call. Hopefully, that wasn't the case, and it was encouraging to you as it is encouraging to us to say that this very solid story remains on track, and we look forward to meeting with you at future events. Thanks for being here.