Welcome to the Dominion Energy Fourth Quarter 2020 Earnings Conference Call. At this time, all lines are in listen-only mode. At the end of today’s presentation, we will take questions. I would now like to turn the call over to Steven Ridge, Vice President, Investor Relations.

Good morning, and thank you for joining today's call. Earnings materials including today's prepared remarks may contain forward-looking statements and estimates that are subject to various risks and uncertainties. Please refer to our SEC filings, including our most recent annual reports on Form 10-K and our quarterly reports on Form 10-Q for a discussion of factors that may cause results to differ from management's estimates and expectations. This morning, we'll discuss some measures of our company's performance that differ from those recognized by GAAP. Reconciliation of our non-GAAP measures to the most directly comparable GAAP financial measures which we can calculate are contained in the earnings release kit. I encourage you to visit our Investor Relations website to review webcast slides as well as the earnings release kit. Joining today's call are Tom Farrell, Executive Chairman; Bob Blue, President and Chief Executive Officer; Jim Chapman, Executive Vice President and Chief Financial Officer; and other members of the executive management team. I will now turn the call over to Tom.

Thank you, Steve, and good morning, everyone. I want to start by outlining Dominion Energy's compelling shareholder return proposition. We expect to grow our earnings per share by 6.5% per year through at least 2025, supported by our updated $32 billion five-year capital growth plan. We offer an attractive dividend yield of approximately 3.5%, reflecting a target payout ratio of 65% and an expected long-term dividend per share growth rate of 6%. This resulting 10% total shareholder return proposition is combined with an industry-leading ESG profile, characterized by what we believe is the largest regulated decarbonization investment opportunity in the country. We plan to invest tens of billions of dollars over the next several years to the benefit of the environment, our customers, our communities, and our local economies. Our strategy is anchored on a pure-play state-regulated utility operating profile that centers around five premier states, as shown on Slide 5. I'll share the philosophy with a common sense approach to energy policy and regulation that puts a priority on safety, reliability, affordability, and, increasingly, sustainability. These states also strive to create environments that promote sensible economic growth, which, like the rising tide, lifts all boats. For instance, three of these state jurisdictions rank consistently in the top four best states for business as determined by independent analysis carried out by CNBC and Forbes. Our state-regulated utility model offers investors increased predictability and is enhanced by our concentration in these fast-growing, constructive, and business-friendly states. Turning to Slide 6. Dominion is a purpose-driven company and has adopted a comprehensive stakeholder approach. We are driven by the belief that the world's best companies consider the interests not just of investors, but also employees, customers, and communities, and the well-being of the environment. Our actions are grounded in adherence to our five core values, and we embrace transparency and stakeholder engagement as hallmarks of responsible corporate citizenship. The well-being of our over 17,000 employees is critical to our long-term success, and there is no measure more important to our company than the safety performance of our employees. 2020 represented, by a wide margin, the safest year of operations in the history of our company, as depicted on Slide 7. This result did not happen overnight. As you can see, it takes years of dedicated effort to drive sustainable improvement. I congratulate my colleagues on this significant achievement. Turning now to our customers and communities. We believe that it is not enough that we provide energy safely. We must also provide energy that is affordable. We are pleased the residential rates at our two electric utilities compare favorably to state, national, and, where applicable, RGGI state averages. Looking forward, we expect our customers to be very competitive even as we invest heavily to transform our system's carbon footprint. Bob will address this more comprehensively in his remarks. With regard to our community initiatives during 2020, which are described on Slide 8. First, the impact of COVID-19 on our customers during 2020 was obviously significant, which is why we voluntarily took immediate action at the onset of the pandemic to suspend service disconnections. In doing this, we avoided what otherwise would have been disconnection of over 255,000 customer accounts. We also developed extended and flexible payment plans, resulting in over 330,000 enrollments. And we contributed $18 million toward direct energy assistance for our most vulnerable customers. In Virginia, we supported special session legislation, which gave customers a fresh start by forgiving over $125 million of customer arrears. We also agreed to a pause in our South Carolina rate case proceeding, ensuring that the results of that case will not impact customers until late this year. Second, we've built on our long-standing legacy of supporting social equity by committing $25 million to 11 historically Black colleges and universities, funding an additional $10 million for scholarships for underrepresented minority groups, and creating a $5 million social justice fund that supports community efforts to address the impacts of racism. This is in addition to the diversity and inclusion initiatives within our company that Bob will address. As you can tell, we are extremely proud of these accomplishments, and I thank all of my Dominion Energy colleagues who contributed to these successes in what was obviously an extraordinarily challenging year. Turning now to Slide 9. We have rolled forward our five-year capital growth plan to capture the years 2021 through 2025. This has resulted in a $10 billion, or 43% increase to the plan we shared with you in the spring of 2019, as adjusted for the Gas Transmission & Storage sale. We now project $32 billion of growth capital investment on behalf of our customers, over 80% of which reduces or enables emissions reductions. We plan to invest $17 billion in zero-carbon generation and energy storage, including regulated offshore wind, solar, and nuclear relicensing. Another $6 billion in electric grid enhancements, such as electric transmission and grid modernization, which will enable our system to be more resilient to cyber and climate threats and more responsive to increasing intermittent generation. And we plan to invest $3 billion on the modernization of our LDC networks as well as on renewable natural gas development, thereby increasing safety and reliability while driving emissions down. Jim and Bob will provide more color on these industry-leading investment programs in a moment. As meaningful as these near-term plans are, consider on Slide 10 how they compare to the long-term scope and duration of our overall decarbonization opportunity. Our initiatives extend well beyond our five-year plan. We have identified over $70 billion of green investment opportunity between 2020 and 2035, nearly all of which will qualify for regulated cost of service recovery. This is, as far as we can tell, the largest regulated decarbonization investment opportunity in the industry. And the accelerating electrification of the transportation sector promises to drive growing demand for utility-scale, zero and low-carbon generation for many years to come. The company's long-term transformation has multiple beneficiaries: our customers who want more sustainable energy; our local communities, which benefit from the economic growth and tax revenue from the company's investments; our employees who develop the best practices of the transition to a low-carbon future; and the environment, via the emissions reductions we illustrate on Slide 11. Through 2019, inclusive of asset divestitures, we have successfully reduced our enterprise-wide CO2 equivalent emissions by around 55%. This is great progress but we have more to do. By 2035, we expect to improve that reduction to between 70% and 80% versus baseline on our way to net zero by 2050. As shown on the right side of the slide, by 2035, we expect that approximately 95% of our company-owned generation will be either zero or low emitting, a remarkable transformation from our 2005 mix. Before turning it over to Jim, I will summarize the actions and events of 2020 that have positioned Dominion to thrive for years to come. We took care of one another, and in so doing, we achieved an all-time safety record. We took quick action to work with our customers to address the impact of the COVID-19 pandemic. We announced our ambition to be net zero by 2050. The Virginia Clean Economy Act was adopted by the general assembly, which puts the state on a cutting-edge path to decarbonization and positions the state as a hub for the global green economy transition. We advanced our strategic positioning by selling our Gas Transmission & Storage assets to focus on our premier state-regulated utility operations. We simultaneously initiated best-in-class earnings and dividend growth rates. We reported our 20th consecutive quarter of weather-normal results that met or exceeded the midpoint of our quarterly guidance. And we transitioned both our CEO and Lead Director roles. With that, I will turn it over to Jim.

Thank you, Tom, and good morning. Our fourth quarter 2020 operating earnings, as shown on Slide 14, were $0.81 per share, which included a $0.01 hit from worse-than-normal weather in our utility service territories. Both actual and weather-normalized results were above the midpoint of our quarterly guidance range. Full year 2020 operating earnings per share were $3.54, above the midpoint of our guidance range and included a $0.09 hit from weather. Weather-normalized results of $3.63 were at the top of our annual guidance range. Note that our fourth quarter and 2020 GAAP and operating earnings, together with comparative periods, are adjusted to account for discontinued operations, including those associated with the sale of assets to Berkshire Hathaway Energy. And then a summary of such adjustments between operating and reported results is, as usual, included in Schedule 2 of our earnings release kit. As shown on Slide 15, this represents our 20th consecutive quarter, so five years now, of delivering weather-normal results that meet or exceed the midpoint of our quarterly guidance range. We've highlighted here the July 5 Gas Transmission & Storage sale announcement on the chart as this has obviously had an impact on our original annual guidance, which is, of course, prior to that transaction. But regardless, we believe the historic consistency across our quarterly results is worth highlighting and it's a track record we are absolutely focused on extending. Turning now to Slide 16. As usual, we are providing a range for the year, which is designed primarily to account for variations from normal weather. We are initiating 2021 operating EPS guidance of $3.70 to $4 per share. The midpoint of this range is in line with the indicative guidance midpoint range we provided in July. Measured midpoint to midpoint, we expect approximately 10% growth in 2021, also consistent with our July guidance. Looking longer term, we expect operating EPS to grow off the 2021 base at around 6.5% per year through 2025. Finally, we expect first quarter 2021 operating earnings per share to be between $1 and $1.15. Turning to Slide 17. We expect our 2021 full year dividend to be $2.52, reflecting our target payout ratio of approximately 65%. We're also extending the long-range dividend per share growth rate of 6% off that '21 base through 2025. Slide 18 provides a breakdown of the five-year growth capital expenditure roll-forward which Tom introduced. For more details on this, I would point to the very comprehensive appendix materials. We've really put some effort into providing all the more granular detail, which we expect will be useful for understanding and modeling each part of this growth profile. But just a few items I'll highlight here. We are forecasting a total five-year rate base CAGR of around 9%, broken out here by segment and by major driver. I would note that nearly three-quarters of this planned growth CapEx is eligible for rider recovery. That nomenclature varies but capital invested under riders, rate adjustment clauses, or trackers, as they're called in various jurisdictions, allows for more timely recovery of prudently incurred investments and costs. They're filed and trued up at least annually in single issue proceedings, so outside of the more time-consuming and less frequent general base rate proceedings. In some of our jurisdictions, including Virginia, rider recovery mechanisms utilize a forward-looking or projected test period and/or allow for our construction work in progress, all of which minimizes traditional regulatory lag that, in other cases, can prevent utilities from earning at their authorized return levels. Rider-eligible CapEx programs vary a little by state, but prominent examples for us include offshore wind, solar, energy storage, nuclear licensing, electric transmission, strategic undergrounding, grid transformation, rural broadband, and gas distribution, infrastructure, integrity, and modernization spending. On that theme, and turning to Slide 19, we illustrate how base investments and rider investments are expected to trend at Dominion Energy Virginia through the five-year plan. You'll note that the Virginia base investment balance is growing at about 6% annually, driven primarily by new customer connections and maintenance spending. By contrast, the rider investment balance in Virginia, which comprises half of DEV's investment base today, is expected to grow at nearly 20% annually on average. Since the Virginia rider investment programs are reviewed and trued up annually, they are not included in the triennial review process, the first of which, of course, will commence next month. Based on these growth trends, the base investment balance as a percentage of total DEV declines from 37% to 27% by 2025. It also shrinks dramatically as a percentage of overall Dominion Energy. On Slide 20, we refresh our outlook for sources and uses of cash. So on average, between '21 and '23, we expect to generate annual operating cash flow of around $6.6 billion, return around $2.4 billion to our shareholders in the form of dividends and invest nearly $8 billion a year on growth and maintenance CapEx on behalf of our customers. Our financing plan assumes we issue around $400 million of equity annually through our existing DRIP and ATM programs, with the residual financing needs satisfied by net fixed income issuance. Again, and as shown on Slide 21, these are multiyear averages. To be clear, in 2021, we don't expect any issuance under our ATM program. This equity guidance is consistent with our prior guidance for the '21 through '24 period. We view this level of steady equity issuance under existing programs as prudent, EPS accretive and in the context of our very sizable growth capital spending program, appropriate to keep our consolidated credit metrics within the guidelines for our strong credit rating categories. To that point, as shown on Slide 22, our consolidated credit metrics have continued their steady improvement as has our pension plan's funded status. We're all very proud of these results. We continue to target high BBB range credit ratings for our parent company and single A range ratings for our regulated operating companies.

Thanks, Jim, and good morning, everyone. I'll begin on Slide 25, which provides an overview of the Virginia Clean Economy Act. The law mandates a renewable energy portfolio standard that over the next 25 years moves towards a zero carbon future. In order to achieve the RPS milestones, the law calls on the state's utilities to add significant amounts of wind and solar power generation as well as battery storage. It ramps up energy efficiency and demand side management programs, requires the use of Virginia-based renewable energy credits, mandates that Virginia join the regional Greenhouse Gas Initiative, and requires the retirement of substantial coal-fired generation by 2025 and all ossified units by 2046, subject to reliability and energy security considerations. The largest single investment project coming out of the passage of the VCEA is Dominion Energy's initial 2.6-gigawatt offshore wind deployment, as described on Slide 26. I'm not going to go through every line item on this slide but will highlight the following: first, the project, which is the largest of its kind in North America, is very much on track. This project will provide a boost to Virginia's growing green economy by creating hundreds of jobs, hundreds of millions of dollars of economic output, and millions of dollars of tax revenue for the state and localities. It will also propel Virginia closer to achieving its goal to become a major hub for the burgeoning offshore wind value chain up and down the country's East Coast. Second, as was contemplated in the VCEA, we intend this investment to be 100% regulated and eligible for rider recovery. Finally, the VCEA provides very specific requirements on the presumption of prudency for investment in the project as shown here, which we are confident that we will meet. On Slide 27, we list the major project milestones. In December of last year, we submitted our construction and operations plan to BOEM. We're encouraged by the incremental funding appropriated to BOEM late last year, with the specific direction to augment the agency's resources to process offshore wind permits as well as BOEM's recent recommencement of processing the vineyard wind application. As you likely know by now, we are the only owner in the United States to have completed an offshore wind BOEM permitting process successfully. Our 12-megawatt test project, which recently entered service, completed the BOEM permitting process in 2019, and we're applying lessons learned during that process to our present application. The other item I'll highlight is on the left-hand side of this slide. The lease is positioned in shallow water, outside of major maritime shipping lanes, away from any other offshore wind leaseholds and not in a region that supports a significant commercial fishing industry. We expect to receive final permits in mid-2023 and complete project construction around the end of 2026. The VCEA calls for another 2.6 gigawatts of offshore wind by 2036. While our near-term focus is on successfully executing our initial deployment, we look forward to finding ways to support the state's additional offshore wind capacity goals. The VCEA provides that the cost of any offshore wind project will be borne by our customers only in proportion to our ownership of the project. While offshore wind may be our largest single renewable energy project, the aggregate capacity of solar generation called for by the VCEA is over three times larger. In accordance with the law, 65% of the target amount is to be utility-owned. This is not new ground for us or for the commission. To date, we've made four cost of service rider recovery filings for solar projects in Virginia, three representing around 400 megawatts have been approved in the most recent filing is pending approval. We expect to make additional filings annually as we work toward the over 10 gigawatts of regulated solar capacity called for by the law. Current solar technology requires around 10 acres for every megawatt of installed capacity. Rough math suggests, therefore, that the utility-owned target of around 10,000 megawatts will require around 100,000 acres of land. We've been hard at work to secure enough land to support our long-range goal, and I'm pleased to report that in less than a year, we've put 63,000 acres under option. Turning to Slide 29. What started with an 8-megawatt facility in Georgia in 2013 has today become a portfolio of over 2.2 gigawatts, representing over $5 billion of investment. Our early focus was on the development of long-term contracted projects, mostly outside of Virginia, that allowed us to develop the expertise and competency to undertake the substantial regulated solar build-out in Virginia that I just described. Going forward, you can see that our emphasis shifts, and a very significant majority of our solar capacity investment will take place under regulated cost of service recovery mechanisms in Virginia. Growth in long-term contracted solar is limited and driven by large customer requests for bilateral, 100% renewable power supply. As increasing intermittent generation sources proliferate in our system, energy storage will be critical to maintaining reliable service. We observed, with keen interest, a recent example of the negative consequences that occur for customers when rapid changes in intermittent generation are not accommodated with sufficient storage and/or quick-start gas-fired generation. Hence, the VCEA prudently calls for the development of nearly 3 gigawatts of energy storage by 2036, 65% of which is to be utility-owned and rider eligible. Admittedly, we're starting small when it comes to developing technologies in this area, 16 megawatts of pilot projects across three different sites and three different use case scenarios, as shown on the right side of Slide 30. But starting small has its advantages, as we saw in both our offshore wind and solar development strategies. We're rapidly developing expertise that will ensure we're providing the maximum value to customers as we fulfill the targets of the VCEA. In our estimation, the success of greenhouse gas emissions reduction targets requires the ongoing viability of existing nuclear facilities. That's why we filed for 20-year license extensions for our four Virginia regulated units. Today, these facilities account for 30% of Virginia's total electric output, around 90% of Virginia's zero carbon electricity. Based on PJM's carbon intensity rate, the ongoing operation of these plants will effectively avoid CO2 emissions of 16 million tons per year. Key milestones for the relicensing process are shown on Slide 31. We expect to submit for rider cost recovery approval in the second half of this year. Our near-term focus is on the Virginia unit. But under the appropriate circumstances, life extensions over the long term at our other three units may be advisable. Successful nuclear life extension is a win for customers and the environment. The transition to a clean energy future means reduced reliance on coal-fired generation. As Tom showed, in 2005, more than half our company's power production was from coal-fired generation. By 2035, we project that to be closer to 5%, perhaps lower if South Carolina prefers an accelerated decarbonization plan as part of our IRP refiling. From an investment-based perspective, which is a rough approximation of earnings contribution, you can see, on Slide 32, the role coal-fired generation plays in our financial performance, driven by facility retirements and non-coal investment. We're mindful that this shift has the potential to be disruptive to employees and communities and are being purposeful in our efforts to ameliorate any such negative consequences. You'll also note that zero carbon generation grows significantly such that by 2025, over 60% of our investment base will consist of electric wires and zero carbon generation. Turning to Slide 33. Let me address customer rates with a focus on Virginia. First, between 2008 and 2020, our typical residential customer rate increased, on average, by less than 1% per year, which is much lower than average annual inflation over that period of closer to 2%. Second, based on EIA data, our typical customer rate is 13% lower than the national average and 36% lower than other states, that like Virginia have joined. Third, going forward, we see typical residential rates increasing by a compound annual growth rate of around 2.9% through 2030, which is a comprehensive estimate and includes, among other factors, the impact of the decarbonization investment programs we've discussed today. If we move the starting point back to 2008, that rate of increase falls to 2.1%, which is lower than projected inflation for 2021. It's incumbent upon us to deliver energy that is safe, reliable, increasingly sustainable, and affordable. Now on Slide 34, let me address the upcoming triennial review proceeding. Note, we've developed detailed slides in the appendix that we believe will be helpful to you on this topic. First, the triennial review process will commence next month and conclude late this year. Second, this triennial review will cover four years of performance from 2017 through 2020 and compares our earned return to our allowed return of 9.9%, inclusive of a 70 basis point power. Third, and as Jim pointed out, the review applies only to the Virginia-based portion of our rate base. Rider investments are outside the scope of the proceeding. And finally, to the extent the commission concludes that available revenues, inclusive of adjustments for impairments, weather, and other factors, are greater than customer credit reinvestments, it may order a refund as well as a forward-looking revenue reduction of up to $50 million. So let me point out just two factors that we know will be part of the first review process. First, we've invested nearly $300 million in the on-time and on-budget completion of the 12-megawatt offshore wind test project. We've indicated we will not seek a revenue increase from customers associated with this project. Rather, we will apply that investment as needed as a customer credit reinvestment offset. Second, we provided over $125 million of arrears relief in Virginia to assist customers, many of whom have faced financial hardship as a result of COVID. Naturally, we're focused on the triennial review filing next month, but we also get questions from time to time regarding the second triennial review, which is expected to conclude in almost four years. A few observations there, which are shown on Slide 35. First, we're in the very early days, 43 days, I think, of that review period. So obviously, we have quite a way to go before being in a position to file the precise regulatory inputs for that proceeding. What we do know, however, is that the structure of the review will be similar to T1. This includes the ability, for instance, to use customer credit reinvestment offsets, which allow us to invest in projects for the benefit of customers. Second, as Jim described well, the robust growth of our asset base at DEV is concentrated around rider recoverable investments that are outside the scope of triennial earnings reviews. Combined with growth at our other state-regulated operating segments, the proportion of the company's earnings and cash flows which are subject to triennial earnings tests will naturally diminish over the forecast and beyond. Third, the very nature of our business as a state-regulated utility company is working with regulators to deliver beneficial outcomes for both customers and investors. It’s something we've been doing for many years. We expect to continue to apply the experience we've gained to upcoming rate proceedings of all varieties, including the triennial reviews. We firmly believe that there are a number of paths that converge on a single objective: serving customers, employees, communities, the environment, and investors. On top of that, we're incredibly excited about what Dominion Energy is planning to accomplish well beyond the next two triennial reviews. Specifically, over the next 15 years, the investment of upwards of $70 billion of green capital, nearly all of which will grow earnings under regulated rider mechanisms and significantly reduce emissions while maintaining competitive customer rates. We don't believe any other company in the United States offers the duration, visibility, and scope of regulated decarbonization growth that Dominion Energy now offers. Shifting gears a little on Slide 36, we summarize the status of the pending South Carolina general rate case proceeding, which is presently in a six-month pause, which we supported. As part of the pause, the commission ordered the parties to report, on a monthly basis, on their progress toward reaching a settlement. We can't report to you this morning on the status of current negotiations, obviously, but we look forward to continuing to engage with parties to the case in hopes of finding a suitable resolution to bring before the commission for approval. In the meantime, our commitment to customers is unwavering. Over the last approximately 15 years, we've reduced average annual customer outage minutes by 40%. Investments made in prior periods, including the years covered by our recent rate case filing, are critical to system reliability and the continuation of this trend to the benefit of our customers. We're committed to meeting 100% of our merger commitments, establishing trust with our customers and communities, and working toward an increasingly sustainable future for South Carolinians. In that regard, let me provide an update on our integrated resource plan. Briefly, the commission asked us to refile the plan and consider, among other changes, accelerated renewable energy deployment and increased sensitivities to potential carbon pricing. In the table on the right-hand side, you can see how one of the cases we filed with our original IRP called Plan 8, is indicative of the potential for accelerated decarbonization at only slightly higher customer cost as compared to the prior base plan. Plan 8 would retire 1,300 megawatts of coal-fired generation in 2028 and add 300 megawatts of storage and 700 megawatts of new solar, which would result in a nearly 60% reduction in CO2 emissions by 2030 and only cost approximately 3% more than the base plan. We look forward to engaging with all stakeholders on this planning process. On Slide 38, we provide key elements of our gas distribution segment growth and sustainability strategy. Our utilities operate in some of the fastest-growing areas of the country, with annual customer growth rates approaching 3% in two of our three largest markets. These customers simply prefer natural gas service for cooking, heating, and other residential, commercial, and industrial applications. We're also fortunate to operate jurisdictions for regulation that prioritize safety and reliability. Decoupling mechanisms promote the implementation of increased efficiency measures, which help to reduce customer bills. And infrastructure modernization and integrity trackers allow us to make critical investments and upgrades that both reduce emissions and raise the bar on safe and reliable service. When it comes to natural gas distribution, location matters. We know that for natural gas to be relevant in the future, we must continue to focus on increasing the sustainability of our service. We've adopted ambitious Scope 1 emission targets but that isn't enough. We're now looking at Scope 3 emissions in cutting-edge ways. We've formalized our support for federal methane regulation. And we're working towards procurement practices that encourage enhanced disclosures by upstream counterparties on their emissions and methane reduction programs. Further, we're considering a preference for suppliers and shippers who adopt a net zero commitment. For downstream emissions, we plan to increase our annual spend on energy efficiency by 45% over the next five years and provide our customers with access to a carbon calculator and carbon offsets. We're also developing plans that will require collaboration with policymakers and regulators to increase access to RNG for our customers and, ultimately, to initiate mandatory RNG blend levels that would act to offset our customers' carbon footprint. And finally, we're pursuing innovative hydrogen use cases, which we discuss in more detail in the appendix. This includes our participation as a founding member of the Low Carbon Resources Initiative, which just surpassed $100 million of funding from over 30 industry members. I'll conclude my remarks by addressing several important topics we tackled in 2020 that enhanced our industry-leading ESG profile. In February, we announced the goal of net zero carbon and methane emissions by 2050. Over the summer, as the nation began to reexamine important points around race, we built upon our existing legacy of social equity by committing $40 million to social justice and equity causes. In October, we published our latest Sustainability and Corporate Responsibility Report, which conforms with the major best-in-class reporting standards, including the Global Reporting Initiative, the Sustainability Accounting Standards Board, and the UN Sustainable Development Goals framework. Also in October, we established a new commitment to increase our total workforce diversity by 1% each year. During 2020, we got off to a strong start, with half of our company's new hires being diverse. And in November, we announced our report for the Task Force on Climate-related Financial Disclosures, or TCFD, making us one of only six utilities to adopt such support. Looking ahead on Slide 40, we have more to do. In January, as I mentioned, we publicly formalized our support for federal methane regulations. During the second quarter of this year, we'll publish an updated climate report that will reflect TCFD recommended methodologies. And throughout 2021, we'll advance our efforts to address Scope 3 emissions, firstly, in our gas distribution businesses, as I previously described. These and other ESG-oriented efforts have been recognized by leading third-party assessment services, as shown on Slide 41. By each measure, our performance exceeds the sector average. We've been recognized as part of the leadership band by CDP for our climate and water disclosure; as trendsetters for the third consecutive year by the CPA-Zicklin report on political accountability and transparency; and as part of the Just 100 for the second consecutive year by Just Capital for our actions to promote increased equity. I'll conclude the call on Slide 42, which you saw in Tom's remarks as well. We are taking steps today to chart a course that over the next decades will put our company on a remarkable journey to becoming the most sustainable energy company in America. Our future is bright, and we're focused on executing this plan for the benefit of our employees, customers and communities, the environment, and our investors. With that, we're ready to take questions.

Thank you. At this time, we will open the floor for questions. Our first question comes from Steve Fleishman with Wolfe Research.

Hi, thanks. Good morning. My first question is about your growth rate extending to 2025, which will include the 2024 triennial outcome. Can you elaborate on how you are incorporating that into your assumptions? What are your expectations for it?

Yes, thank you for the question. As I mentioned earlier, we're only 43 days into a three-year review period, and we don't file the case for over three years. So, it's expected that many details will emerge over time. It's important that when we consider a long-term growth rate, we evaluate various planning scenarios and do not rely on a single outcome for 2024 or any major assumptions far into the future. One thing we do anticipate in all of our forecasts for 2024 and subsequent years is that Virginia's regulations remain favorable, as they have historically provided our customers with reliability rates that are over 10% below the national average and contributed to a more sustainable generation portfolio. Also, it's crucial to remember, as discussed earlier, that the portion of our earnings from base rates in Virginia will decrease over time while riders and alternative mechanisms outside Virginia will become more significant. Our growth projected from now until the 2024 triennial and beyond is largely driven by rider investments that are independent of the 2024 triennial or any other triennial process.

Okay. So is the conclusion then that you feel confident in your ability to manage a range of outcomes based on your assumptions?

Yes, this is what we do. It’s what we've done over the years is we work with regulators, policymakers on constructive outcomes for customers and the health of the utility. And we fully expect that we'll be able to continue that going forward.

Okay. And then one other question related to that is, I did notice that it does seem like the base component of the rate base in Virginia and the percentages seemed lower than they have been in some of your other recent disclosures. Could you just explain maybe some of the changes there, I guess, maybe, Jim?

Okay, Steve. Good morning. Let me take that, and I'm not sure if everyone has the full deck in program, but for future references, it's set out on Page 60 in the appendix. But you're right, the total rate base in Virginia has not changed other than through the passage of time and the completion of the year. But what we did do is we refined the calculation of the elements of total rate base. We have been showing the schedule since like 2019 when we started this, I guess, our last Investor Day, where we, at that time, the triennial was very far away, we were trying to make it simple. So we lumped some things together. And now we've refined that. And the refinement relates to about $4 billion of rate base that previously we had categorized as Virginia-based and other, and the $4 billion is really the other. And we've now reallocated that to other categories. So what's in the other? Those are contracts where we serve various entities in the state, municipalities, the state of Virginia itself, the federal government, entities like that, where the contracts reflect different economic constructs. Some of them are just sort of negotiated. Those are in the other category and our new slide and others track more some of the riders, whether it's a transmission rider or legacy A6 riders. So we've reallocated, to be more precise. Now Virginia-based is not Virginia-based and other. It's just Virginia-based, and it brings down that number to about $9 billion. So I think that's helpful to folks as they do math and sensitivities to have that more refined division on the various buckets of our total Virginia rate base.

Okay. Thank you very much.

Thanks, Steve.

Hi, good morning. Thanks very much for the time today. So…

Hi, Dan, thanks for joining.

Hey, thank you. So this question is for you, Bob. So the Virginia legislature has several live utility and energy economy-related bills still floating around, and Governor Northam's asked for a special session. Can you put all the noise that this creates for investors into perspective for us?

Yes, I don't recall a fourth quarter call where we didn't receive a question about the Virginia General Assembly. This is likely due to the timing of our fourth quarter call coinciding with the session. We appreciate your inquiry and would have been disappointed if it hadn’t come up this year. It has been over 15 years since I worked in the governor's office in Virginia, but I believe some aspects of the legislative process remain constant. First, the legislature does not operate according to a script; making definitive predictions about legislation outcomes can be risky. Second, for a bill to become law, it must pass through various hurdles, including both Houses and their committees. A relevant example from this year's session is the bill introduced in the Senate regarding our regulatory model, which was defeated in committee on a strong bipartisan vote. Lastly, the Virginia legislature moves swiftly, so we shouldn't expect lengthy delays. This year has seen a slightly different timing due to the constitutionally mandated 30-day session followed by a special session called by the governor, but the process is still proceeding rapidly. I believe the bills you referenced will be addressed relatively soon, as that is characteristic of the Virginia General Assembly. We will monitor the situation, but it's crucial to remember that these bills still face obstacles before they can become law.

Okay. Thanks very much. And I guess one also for Jim. So Jim, thanks for all the detail on the CapEx going forward as well as what's rider-eligible versus not. Can you talk a little bit about the impact that the CapEx mix and the rider-eligible projects will have on cash flow conversion as we go through the next five years?

Thank you, Dan. As I mentioned, over 70% of our capital spending in this five-year plan is in rider format, both in Virginia and in other locations. This means that as we invest that capital, we experience no regulatory lag, resulting in a proportional increase in operating cash flow from that investment. This significantly aids our plan for managing cash sources and uses because of the absence of regulatory delays and the related growth in our rider spending and rider rate base. We believe this is a valuable aspect of the structure.

Great. Hey, thanks very much, guys.

Thanks, Dan.

Just a quick housekeeping and then I have a quick follow-up. Just maybe starting with the '21 guidance. I mean, obviously, you've highlighted an expectation for 10% or better growth off that 2020 base, but the bottom end sort of implies about 6% year-over-year growth. There's a lot of visibility with the plans. So just trying to get a sense on any scenarios outside of weather that could put you at that lower end. And then I know the midpoint of the range is about $0.025 lower versus prior. Is that South Carolina GRC delay-related? Can you manage it? Is there sort of a conservatism built in there?

Yes, there are several parts to that question, so let me address it. South Carolina had no effect on our guidance range. I’ll walk you through the elements of our guidance. Our long-term EPS growth guidance is 6.5%, which is more specific than our peers, who typically provide a range of 200 basis points. Each year, based on this 6.5% long-term growth rate, we select a midpoint for our annual guidance and establish a range around it. This range primarily accounts for different weather outcomes. In the past five years, this range has seen some fluctuations, starting at $0.50, then $0.45, and down to $0.30. This year's range is designed to accommodate various weather scenarios as well. The midpoint of the range is 3.85, and we are very confident about achieving that figure while maintaining our track record of meeting or exceeding expectations on a weather-normal basis, as we have demonstrated over the last five years. We have a range and a midpoint, which is consistent with the narrow range we provided in July.

Terrific. All right. That's what I was trying to get at, Jim.

Perhaps to follow up on some of the last questions. I got a couple real quickly, if you can. I believe you just said a second ago, with respect to the 6.5% and the increased level of precision, I think Steve brought up earlier. Obviously, there's a lot baked into that five-year outlook through '25. How do you get yourself so confident around that 6.5% precision that you guys articulated? I mean, obviously, it's purposeful, as you just said. If you can speak to it a little bit more narrowly about the level of confidence you have in these outcomes to drive that number, that would be great. And then I have a quick follow-up, if you don't mind.

Yes. I mean, I think I'd answer it simply this way, Julien, we were confident in July when we announced the 6.5% growth rate and nothing has changed since then. We're still confident. We've outlined, as you've heard today, some roll-forward of our CapEx. We've got a lot of clarity on rider recoverability of that CapEx, and all of that contributes as we sort of develop our assumptions around our long-term growth rate to maintaining the confidence that we had last summer in that 6.5%.

Got it, fair enough. And then turning back to South Carolina quickly, if you can. Obviously, I heard what you said about '21 here. How do you think about prospects for settlement timeline there, just given some of the generations? Then ultimately, obviously, we're paying attention to what's going on with Duke in the Carolinas here, too. How do you think about CapEx opportunities as well?

We are actively working through the pause mandated by the commission, for which we are providing monthly updates. We remain optimistic about our ability to reach settlements because we believe we can creatively find solutions that benefit both our customers and the company. However, reaching a settlement requires agreement from all parties involved. I can't predict the thoughts of the other parties, but I can assure you we are making significant efforts toward a resolution. The commission has indicated that if no settlement is reached by a certain point, the case will resume. We are confident in either achieving a settlement or successfully concluding the case since we have a robust case. It has been eight years since our last base rate case, during which we have made considerable investments to improve our system, and we feel entitled to earn a return on those investments. We believe the case is strong, and while we hope for a settlement, we are prepared to defend our position if necessary.

Our next question comes from Michael Weinstein with Crédit Suisse.

I'm curious to know how much the additional tax credit extensions and the renewable stimulus planning you're anticipating from the Democrats in the coming months are incorporated into your plan. Is there a possibility for increased benefits, especially in the solar sector, and in terms of customer affordability? Perhaps there could be opportunities for further projects, such as undergrounding or grid transformation?

Yes. That's a great question, Michael. And you're right, for us, in the regulated environment that we're talking about, the extension of the ITCs and various tax credits is customer rate beneficial and doesn't change the investment return but definitely reduces the rate that customers pay. So we'll look at whether there are opportunities. We have a pretty aggressive plan, as you've seen in the Virginia Clean Economy Act last year passed an aggressive plan. So we're moving very quickly. If there are opportunities to advance, we'll take them. But the main effect of ITC extension is going to be a benefit to customers on rate.

One thing I want to add is that regarding ITCs where we recognize earnings benefits outside of a regulatory context, it is important to clarify that this is not a significant growth area for us. Most of our ITC activities are in regulated formats that provide benefits to our customers, as Bob mentioned. Two years ago at Investor Day, we provided guidance that ITC recognition and earnings would be in the range of up to $0.15 per year. Currently, we are running below that target. In 2018, we recorded $0.09; in 2019, it was $0.11; and in 2020, we reached $0.16. However, we still aim to maintain a trend towards that guidance of up to $0.15 per year. Therefore, the impact in this area is modest, primarily benefiting regulated customers, as Bob noted.

All right. And just to be clear, the ITC doesn't reduce the rate base in any of the projects that you're working on, on the regulated side?

Yes, that's exactly right.

My understanding is that the strategic undergrounding has created a limit on the amount you can invest there by law. Is there any discussion about possibly expanding that, especially since things might be becoming more affordable due to the federal tax credits?

Yes. So that's a legislative. That cap is in legislation that you're referring to. It has to do with a percentage of overall rate base. There's no legislation pending in Virginia right now on that issue. So if it were to be extended, it's unlikely that would happen this year.

You've outlined the decarbonization opportunity for 2035.

Jeremy, we can barely hear you.

Sorry about that. Is that better?

Yes.

You outlined the decarbonization opportunity through 2035 today. How do you think about customer growth and other investments for that period? And given the magnitude of your clean spend here, do you expect this to capture an increasing share going forward, absent large changes in customer growth?

I'm sorry. We can discuss customer growth. We have experienced consistent growth in our electric utility over the past decade, and we anticipate this will continue. For example, in Virginia, we add around 35,000 new customers each year. On the gas side of our business, as mentioned earlier, we are seeing very strong new customer growth. However, I'm not sure I completely understood the second part of the question, and I apologize.

I wanted to ask about the proportion of the green capital expenditures. Will this continue to be a significant focus for you moving forward, or should we also consider other major investments in non-clean areas?

Yes, the outlook is very promising, and it is clearly illustrated in the slide showing the $72 billion opportunity. All of this pertains to decarbonization-related or enabling investments, which will constitute the majority of our investments moving forward. We expect this trend to persist even beyond the long-term horizon. Naturally, 15 years is a significant timeframe in our industry.

What started with an 8-megawatt facility in Georgia in 2013 has today become a portfolio of over 2.2 gigawatts, representing over $5 billion of investment. Our early focus was on the development of long-term contracted projects, mostly outside of Virginia, that allowed us to develop the expertise and competency to undertake the substantial regulated solar build-out in Virginia that I just described. Going forward, you can see that our emphasis shifts, and a very significant majority of our solar capacity investment will take place under regulated cost of service recovery mechanisms in Virginia. Growth in long-term contracted solar is limited and driven by large customer requests for bilateral, 100% renewable power supply. As increasing intermittent generation sources proliferate in our system, energy storage will be critical to maintaining reliable service. We observed, with keen interest, a recent example of the negative consequences that occur for customers when rapid changes in intermittent generation are not accommodated with sufficient storage and/or quick-start gas-fired generation. Hence, the VCEA prudently calls for the development of nearly 3 gigawatts of energy storage by 2036, 65% of which is to be utility-owned and rider eligible. Admittedly, we're starting small when it comes to developing technologies in this area, 16 megawatts of pilot projects across three different sites and three different use case scenarios. But starting small has its advantages, as we saw in both our offshore wind and solar development strategies. We're rapidly developing expertise that will ensure we're providing the maximum value to customers as we fulfill the targets of the VCEA. In our estimation, the success of greenhouse gas emissions reduction targets requires the ongoing viability of existing nuclear facilities. That's why we filed for 20-year license extensions for our four Virginia regulated units. Today, these facilities account for 30% of Virginia's total electric output, around 90% of Virginia's zero carbon electricity. Based on PJM's carbon intensity rate, the ongoing operation of these plants will effectively avoid CO2 emissions of 16 million tons per year. Key milestones for the relicensing process are shown on Slide 31. We expect to submit for rider cost recovery approval in the second half of this year. Our near-term focus is on the Virginia unit. But under the appropriate circumstances, life extensions over the long term at our other three units may be advisable. Successful nuclear life extension is a win for customers and the environment. The transition to a clean energy future means reduced reliance on coal-fired generation. As Tom showed, in 2005, more than half our company's power production was from coal-fired generation. By 2035, we project that to be closer to 5%, perhaps lower if South Carolina prefers an accelerated decarbonization plan as part of our IRP refiling. From an investment-based perspective, which is a rough approximation of earnings contribution, you can see the role coal-fired generation plays in our financial performance, driven by facility retirements and non-coal investment. We're mindful that this shift has the potential to be disruptive to employees and communities and are being purposeful in our efforts to ameliorate any such negative consequences. You'll also note that zero carbon generation grows significantly such that by 2025, over 60% of our investment base will consist of electric wires and zero carbon generation. Turning to Slide 33. Let me address customer rates with a focus on Virginia. First, between 2008 and 2020, our typical residential customer rate increased, on average, by less than 1% per year, which is much lower than average annual inflation over that period of closer to 2%. Second, based on EIA data, our typical customer rate is 13% lower than the national average and 36% lower than other states. Third, going forward, we see typical residential rates increasing by a compound annual growth rate of around 2.9% through 2030, which is a comprehensive estimate and includes, among other factors, the impact of the decarbonization investment programs we've discussed today. If we move the starting point back to 2008, that rate of increase falls to 2.1%, which is lower than projected inflation for 2021. It's incumbent upon us to deliver energy that is safe, reliable, increasingly sustainable, and affordable. Now on Slide 34, let me address the upcoming triennial review proceeding. Note, we've developed detailed slides in the appendix that we believe will be helpful to you on this topic. First, the triennial review process will commence next month and conclude late this year. Second, this triennial review will cover four years of performance from 2017 through 2020 and compares our earned return to our allowed return of 9.9%, inclusive of a 70 basis point power. Third, and as Jim pointed out, the review applies only to the Virginia-based portion of our rate base. Rider investments are outside the scope of the proceeding. And finally, to the extent the commission concludes that available revenues, inclusive of adjustments for impairments, weather, and other factors, are greater than customer credit reinvestments, it may order a refund as well as a forward-looking revenue reduction of up to $50 million. So let me point out just two factors that we know will be part of the first review process. First, we've invested nearly $300 million in the on-time and on-budget completion of the 12-megawatt offshore wind test project. We've indicated we will not seek a revenue increase from customers associated with this project. Rather, we will apply that investment as needed as a customer credit reinvestment offset. Second, we provided over $125 million of arrears relief in Virginia to assist customers, many of whom have faced financial hardship as a result of COVID. Naturally, we're focused on the triennial review filing next month, but we also get questions from time to time regarding the second triennial review, which is expected to conclude in almost four years. A few observations there, which are shown on Slide 35. First, we're in the very early days, 43 days, I think, of that review period. So obviously, we have quite a way to go before being in a position to file the precise regulatory inputs for that proceeding. What we do know, however, is that the structure of the review will be similar to T1. This includes the ability, for instance, to use customer credit reinvestment offsets, which allow us to invest in projects for the benefit of customers. Second, as Jim described well, the robust growth of our asset base at DEV is concentrated around rider recoverable investments that are outside the scope of triennial earnings reviews. Combined with growth at our other state-regulated operating segments, the proportion of the company's earnings and cash flows which are subject to triennial earnings tests will naturally diminish over the forecast and beyond. Third, the very nature of our business as a state-regulated utility company is working with regulators to deliver beneficial outcomes for both customers and investors. It's something we've been doing for many years. We expect to continue to apply the experience we've gained to upcoming rate proceedings of all varieties, including the triennial reviews. We firmly believe that there are a number of paths that converge on a single objective: serving customers, employees, communities, the environment, and investors.

On top of that, we're incredibly excited about what Dominion Energy is planning to accomplish well beyond the next two triennial reviews. Specifically, over the next 15 years, the investment of upwards of $70 billion of green capital, nearly all of which will grow earnings under regulated rider mechanisms and significantly reduce emissions while maintaining competitive customer rates. We don't believe any other company in the United States offers the duration, visibility, and scope of regulated decarbonization growth that Dominion Energy now offers. Shifting gears a little on Slide 36, we summarize the status of the pending South Carolina general rate case proceeding, which is presently in a six-month pause, which we supported.

As part of the pause, the commission ordered the parties to report, on a monthly basis, on their progress toward reaching a settlement. We can't report to you this morning on the status of current negotiations, obviously, but we look forward to continuing to engage with parties to the case in hopes of finding a suitable resolution to bring before the commission for approval. In the meantime, our commitment to customers is unwavering. Over the last approximately 15 years, we've reduced average annual customer outage minutes by 40%. Investments made in prior periods, including the years covered by our recent rate case filing, are critical to system reliability and the continuation of this trend to the benefit of our customers. We're committed to meeting 100% of our merger commitments, establishing trust with our customers and communities, and working toward an increasingly sustainable future for South Carolinians. In that regard, let me provide an update on our integrated resource plan. Briefly, the commission asked us to refile the plan and consider, among other changes, accelerated renewable energy deployment and increased sensitivities to potential carbon pricing.

In the table on the right-hand side, you can see how one of the cases we filed with our original IRP called Plan 8, is indicative of the potential for accelerated decarbonization at only slightly higher customer cost as compared to the prior base plan. Plan 8 would retire 1,300 megawatts of coal-fired generation in 2028 and add 300 megawatts of storage and 700 megawatts of new solar, which would result in a nearly 60% reduction in CO2 emissions by 2030 and only cost approximately 3% more than the base plan. We look forward to engaging with all stakeholders on this planning process.

On Slide 38, we provide key elements of our gas distribution segment growth and sustainability strategy. Our utilities operate in some of the fastest-growing areas of the country, with annual customer growth rates approaching 3% in two of our three largest markets. These customers simply prefer natural gas service for cooking, heating, and other residential, commercial, and industrial applications. We're also fortunate to operate jurisdictions for regulation that prioritize safety and reliability. Decoupling mechanisms promote the implementation of increased efficiency measures, which help to reduce customer bills. And infrastructure modernization and integrity trackers allow us to make critical investments and upgrades that both reduce emissions and raise the bar on safe and reliable service.

When it comes to natural gas distribution, location matters. We know that for natural gas to be relevant in the future, we must continue to focus on increasing the sustainability of our service. We've adopted ambitious Scope 1 emission targets but that isn't enough. We're now looking at Scope 3 emissions in cutting-edge ways. We've formalized our support for federal methane regulation. And we're working towards procurement practices that encourage enhanced disclosures by upstream counterparties on their emissions and methane reduction programs. Further, we're considering a preference for suppliers and shippers who adopt a net zero commitment. For downstream emissions, we plan to increase our annual spend on energy efficiency by 45% over the next five years and provide our customers with access to a carbon calculator and carbon offsets. We're also developing plans that will require collaboration with policymakers and regulators to increase access to RNG for our customers and, ultimately, to initiate mandatory RNG blend levels that would act to offset our customers' carbon footprint. And finally, we're pursuing innovative hydrogen use cases, which we discuss in more detail in the appendix. This includes our participation as a founding member of the Low Carbon Resources Initiative, which just surpassed $100 million of funding from over 30 industry members. I'll conclude my remarks by addressing several important topics we tackled in 2020 that enhanced our industry-leading ESG profile. In February, we announced the goal of net zero carbon and methane emissions by 2050. Over the summer, as the nation began to reexamine important points around race, we built upon our existing legacy of social equity by committing $40 million to social justice and equity causes. In October, we published our latest Sustainability and Corporate Responsibility Report, which conforms with the major best-in-class reporting standards, including the Global Reporting Initiative, the Sustainability Accounting Standards Board, and the UN Sustainable Development Goals framework. Also in October, we established a new commitment to increase our total workforce diversity by 1% each year. During 2020, we got off to a strong start, with half of our company's new hires being diverse. And in November, we announced our report for the Task Force on Climate-related Financial Disclosures, or TCFD, making us one of only six utilities to adopt such support. Looking ahead on Slide 40, we have more to do. In January, as I mentioned, we publicly formalized our support for federal methane regulations. During the second quarter of this year, we'll publish an updated climate report that will reflect TCFD recommended methodologies. And throughout 2021, we'll advance our efforts to address Scope 3 emissions, firstly, in our gas distribution businesses, as I previously described. These and other ESG-oriented efforts have been recognized by leading third-party assessment services, as shown on Slide 41. By each measure, our performance exceeds the sector average. We've been recognized as part of the leadership band by CDP for our climate and water disclosure; as trendsetters for the third consecutive year by the CPA-Zicklin report on political accountability and transparency; and as part of the Just 100 for the second consecutive year by Just Capital for our actions to promote increased equity. I'll conclude the call on Slide 42, which you saw in Tom's remarks as well. We are taking steps today to chart a course that over the next decades will put our company on a remarkable journey to becoming the most sustainable energy company in America. Our future is bright, and we're focused on executing this plan for the benefit of our employees, customers and communities, the environment, and our investors. With that, we're ready to take questions.

Thank you, sir. At this time, we will open the floor for questions.