Welcome to the Dominion Energy fourth quarter 2020 earnings conference call. At this time each of your line is in a listen-only mode. At the conclusion of today's presentation we'll open the floor for questions. Instructions will be given for the procedure to follow, if you would like to ask a question. I would now like to turn the call over to Steven Ridge, Vice President, Investor Relations. Good morning. 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, Steven, 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 five. All share the philosophy that a common-sense approach to energy policy and regulation 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 by 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 six. 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. 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. 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 seven. 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 that residential rates at our two electric utilities compare favorably to state, national, and where applicable, RGGI state averages. Looking forward, we expect our customer rates 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 eight. 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 result of that case will not impact customers until late this year. Second, we built on our longstanding 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 nine. 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 and 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. 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 that accompanies investments. Our employees who develop the best practices of the transition to a low carbon future. 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 dispatch 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 impacts 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 and 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. Good morning. Our fourth quarter 2020 operating earnings, as shown on slide 14, were $0.81 per share, which included a $0.01 hurt 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 hurt 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. A summary of such adjustments between operating and reported results is, as usual, included in schedule two 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 5th gas transmission storage sale announcement on the chart, as this obviously has had an impact on our original annual guidance, which was, of course, set prior to that transaction. 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 guidance on 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-$4.00 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 $1.00 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 2021 base through 2025. Slide 18 provides a breakdown of the five-year growth CapEx 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. 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 are filed and trued up at least annually in single-issue proceedings. 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 allows for 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 varies a little by state, but prominent examples for us include offshore wind, solar, energy storage, nuclear relicensing, electric transmission, strategic undergrounding, grid transformation, rural broadband, and gas distribution infrastructure integrity and modernization spending. On that theme, 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. Slide 20, we refresh our outlook for sources and uses of cash. On average, between 2021 and 2023, 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 dividend, 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, as shown on slide 21, these are multi-year 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 2021 through 2024 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 ratings category. 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 company. Before I summarize my remarks, let me spend just a minute on O&M. As demonstrated by our 2020 results, we're focusing on driving O&M through improved processes, innovative use of technology, and other best practice cost initiatives to keep normalized O&M flat through the forecast period. This reflects the successful continuation of our flat normalized O&M efforts we discussed in more detail at our last Investor Day. With that, I'll summarize. We reported fourth quarter and full-year 2020 operating EPS, which were above the midpoints of our guidance, extending our track record to five years of meeting or exceeding the quarterly midpoint on a weather-normal basis. We initiated 2021 full-year operating EPS guidance that represents a 10% annual increase, midpoint to midpoint. We affirmed 6.5% operating EPS growth from 2021 through 2025. We introduced a $32 billion five-year growth CapEx plan that drives an approximately 9% rate base growth. We expect highly disproportionate rider investment spending across our segments. Our balance sheet and credit profile remain in very good health. With that, I'll turn it over to Bob. 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, 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 fossil-fired units by 2046, subject to reliability and energy security considerations. The largest single investment project to come out of the passage of the VCEA is Dominion Energy's initial 2.6 GW offshore wind deployment, as described on slide 26. I'm not going to go through every line item on this slide. We'll 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'll also propel Virginia closer to achieving its goal to become a major hub for the burgeoning offshore wind value chains 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 MW 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 on the left-hand side of this slide. The lease's position 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 GW of offshore wind by 2036. Our near-term focus is on successfully executing on our initial deployment, we look forward to finding ways to support the state's additional offshore wind capacity goals. The VCEA provides that the costs of any offshore wind project will be borne by our customers only in proportion to our ownership of the project. 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 MW, have been approved, and the most recent filing is pending approval. We expect to make additional filings annually as we work toward the over 10 GW 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 MW 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 eight-megawatt facility in Georgia in 2013 has today become a portfolio of over 2.2 GW, 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 the 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. The VCEA prudently calls for the development of nearly 3 GW 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 MW of pilot projects across three different sites and three different use case scenarios, as shown on the right side of slide 30. 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 and 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 units, 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 the South Carolina Commission 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 diminished 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 RGGI. 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. 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. The triennial review process will commence next month and conclude late this year. This triennial review will cover four years of performance from 2017 to 2020 and compares our earned return to our allowed return of 9.9%, inclusive of a 70 basis point collar. Third, as Jim pointed out, the review applies only to the Virginia base portion of our rate base. Rider investments are outside the scope of the proceeding. 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. 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 MW 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've 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. Obviously, we have quite a ways 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. 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 available 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. 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. 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, or SAIDI, 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 H, is indicative of the potential for accelerated decarbonization at only slightly higher customer cost as compared to the prior base plan. Plan H would retire 1,300 MW of coal-fired generation in 2028 and add 300 MW of storage and 700 MW 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 in jurisdictions where regulation prioritizes safety and reliability. Decoupling mechanisms promote the implementation of increased efficiency measures, which help to reduce customer bills. Infrastructure modernization and integrity trackers allow us to make critical investments in 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. That isn't enough. We're now looking at Scope 3 emissions in cutting-edge ways. We formalized our support for federal methane regulation, 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. Finally, we're developing plans, which 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 footprints. 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 that just surpassed $100 million of funding from over 30 industry members. I'll conclude my remarks by addressing several important topics we took in 2020 that enhanced our industry-leading ESG profile. In February, we announced a 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. In November, we announced our formal support 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. 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're 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. If you would like to ask a question please press the star key followed by the one on your telephone keypad. If at any time you would like to remove yourself from the question queue please press star two. Again to ask a question please press star one now. Our first question comes from Steve Fleishman with Wolfe Research. Hi. Thanks. Good morning. Just a first question on your growth rate now goes out to 2025, which would encompass, I guess, the 2024 triennial outcome in it. Can you talk a little bit about how you're kind of including that in your assumptions? What are you assuming for that? Thanks, Steve. Appreciate the question. As I mentioned earlier, we're only 43 days into a three-year period that's going to be reviewed, and we don't even file the case for more than three years. Not surprisingly, lots of details to come. I do think it's important, though, when we look at developing a long-term growth rate, we look at a variety of planning scenarios. We don't assume a single outcome for the 2024 triennial or any other major planning assumption that far out in our plan. I will say one theme that is certainly assumed in all of our forecasted outcomes, 2024 or any other year, is that Virginia regulation continues to be constructive, just the way it's worked over the years, which has provided our customers with solid reliability rates more than 10% below the national average and a greener and greener generation portfolio. I think it's also important to remember, as Jim and I talked about earlier, that the portion of our earnings that come from base rates in Virginia as we go through time, and riders and other mechanisms outside Virginia grow in importance. Our growth between now and the 2024 triennial, after the 2024 triennial, is driven by rider investments that are outside the 2024 triennial or any other triennial proceeding. Okay, is the punchline then that you kind of feel like you've got ability to deal with a variety of outcomes for that or in the scheme of things or and that's kind of encompassed in there in some sense? This is what we do. This is what we've done over the years, is we work with regulators, policymakers on constructive outcomes for customers and the health of the utility. We fully expect that we'll be able to continue that going forward. Okay. 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 seem lower than they had been from your other recent disclosures. Could you just explain maybe some of the changes there? I guess maybe Jim? Okay, Steve, morning. Yeah, let me take that, and I'm not sure if everyone has the full deck in front of them, but for future reference, it is set out on page 60 in the appendix. 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. What we did do is we refined the calculation of the elements of total rate base. We had 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. The refinement relates to about $4 billion of rate base that previously we had categorized as Virginia Base and other, and the $4 billion is really the other. We've now reallocated that to other categories. What's in that 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 in our new slide. Others track more some of the riders, whether it's a transmission rider or legacy H6 riders. We've reallocated to be more precise. Virginia Base is not Virginia Base and other, it's just Virginia Base, and it brings down that number to about $9 billion. I think that's helpful to folks as they do math on sensitivities to have that more refined division of the various buckets of our total Virginia rate base. Okay. Yeah. Thank you very much. Thanks, Steve. Thank you. Our next question comes from Dan Ford with UBS. Hi, good morning. Thanks very much for the time today. Hey, Dan. Thanks for joining. Hey. Thank you. This question is for you, Bob. 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? Yeah, sure. I don't think I can remember a fourth quarter call we've done where we didn't get a question on the Virginia General Assembly. I guess that's a function of the timing of our fourth quarter call and the session. I'm glad you asked because we would have been disappointed if we didn't get one this year. It's been now, I guess, more than 15 years since I worked in the governor's office in Virginia, there are a few things about the legislative process that I think are probably still true. The first one, the legislature doesn't follow a script. That you make a mistake, or you make predictions with certainty about the outcome of legislation at your peril. I think that is still true. The second is that bills to become law have to clear a number of hurdles. It's not just one house or the other, it's both houses, and it's committees of both houses. An example of that from this year's session would be the one bill introduced in the Senate that related to our regulatory model was defeated in committee on a pretty strong bipartisan vote. The last thing that is still true about the legislature in Virginia is it moves quickly. I don't think we're going to have to wait a long time. This year, the timing has been a little bit different, as you mentioned. The session went its constitutionally mandated 30 days, and then the governor called a special session, but the process is still moving pretty quickly. I think those bills that you're referring to will be resolved relatively soon because that's the way the Virginia General Assembly moves. We'll keep an eye on them. I think it's important to remember that they've got hurdles they would still have to clear before they could become law. Okay, thanks very much. I guess one also for Jim. 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? Yeah, thanks, Dan. Let me do that. As I mentioned, over 70%, almost 3/4 of our capital spending in this five-year plan is in rider format in Virginia and elsewhere. What that means is we invest that capital, there's no regulatory lag. There is a proportional increase in operating cash flow from that investment. That's quite an assistance in our plan for the sources and uses of cash, given the lack of regulatory lag and the proportional advancement of our rider spend and our rider rate base growth, and also our operating cash flow. We think it's quite a nifty feature of this structure. Great. Hey, thanks very much, guys. Thanks, Dan. Thank you. Our next question comes from Shar Pourreza with Guggenheim Partners. Hey, good morning, guys. Morning, Shar. Morning. Just a quick housekeeping, and then I have a quick follow-up. Just maybe starting with the 2021 guidance. Obviously, you've highlighted an expectation for 10% or better growth off that 2020 base. The bottom end sort of implies about 6% year-over-year growth. There's a lot of visibility with the plan, so just trying to get a sense on any scenarios outside of weather that could put you at that lower end. 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? Yeah, a lot of parts of that question as normal, Shar. Let me just address that last part. South Carolina had no impact on that guidance range, none. Let me walk through the elements of our guidance. We have our long-term EPS growth guidance of 6.5%, which is intended to be more precise than our peers as opposed to a 200 basis point range. What we do every year as we go along that 6.5% long-term growth rate, we choose a midpoint for our annual guidance. Around that midpoint, we have a range. Every quarter we mention that that range is intended primarily to capture different weather outcomes. Now, going back a few years, that range was pretty wide. Within the last five years, it was $0.50, then it was $0.45, this year it was $0.30. The primary reason for that range this year included is to accommodate various weather outcomes. The midpoint of the range is 385, and we're very confident in making that number and in continuing our track record of meeting or exceeding on a weather normal basis like we talked about for the last five years. There's a range, there's a midpoint. That midpoint, again, as I said in my prepared remarks, is consistent with the very narrow range of potential midpoints that we guided in July. No relevance to the South Carolina process. Got it. Thank you for that, Jim. Just lastly on the ratings, obviously, you're presenting a really healthy cash flow outlook. The business risk profile is obviously improved, 9% utility growth. A lot of it is rider treatment, single-issue rate making, 15% debt levels. An agency obviously also has you on positive outlook. Metrics seem to point you closer to A -. Any sense on how the conversations are going with the rating agencies? Let me say it this way. I think generally across the three rating agencies, there's a recognition of the senior management focus on credit that has been a part of all the transactions and financings we've done in the last years. There's a recognition of the improvement that we've accomplished. We're in a good spot. Okay. I wouldn't speculate on an upgrade. What I would expect, maybe I'm not trying to get ahead of the agencies, but what I'd hope for is increased recognition of the very material improvement in our business risk profile from a credit perspective over all the last years. The dust has barely settled right on our last step of that with the sale of gas transmission storage. I would hope that that element would work its way more into the dialogue and even the thresholds that the various agencies apply to our company. Terrific. All right. That's what I was trying to get at, Jim. I appreciate it. Thank you, guys. Yeah. Thank you, Shar. Thank you. Our next question comes from Julien Dumoulin-Smith with Bank of America. Hey, good morning, team. Thanks for the time and opportunity. 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 into 2025. How do you get yourself so confident around that 6.5% precision that you guys articulate? Obviously, it's purposeful, 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'd be great. Then I have a quick follow-up, if you don't mind. Yeah, I think I'd answer it simply this way, Julien. We were confident in July when we announced the 6.5% growth rate. 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. 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. Turning back to South Carolina quickly, if you can. Obviously, I heard what you said about 2021 here. How do you think about prospects for a settlement timeline there, given some of the variations and ultimately, CapEx? Obviously, we're paying attention to what's going on with Duke and the Carolinas here too. How do you think about CapEx opportunities as well? Yeah. On settlement, we're working through the pause that was ordered by the commission that we agreed to, with monthly reports on that. We're always optimistic about our prospects of settling cases because we think we're very creative in finding ways that we can resolve issues that are beneficial for customers and for the company. Ultimately, it requires all the parties to agree to settle, and I can't tell you what's in the mind of the counterparties. I can just tell you that we're working very hard toward that. We have an endpoint that the commission said, "If you haven't settled, we'll start the case back up again." We'll get there either with a settlement or we'll finish the case. It's a strong case. We were very confident in the case that we filed. We haven't had a base rate case in eight years, and we've invested substantially in the system and improved the system, and we're entitled to a return on those investments. We think it's a very strong case. Hopefully, we can settle it. If we can't, we're very comfortable with our ability to defend the position that we took in that case. As to potential future growth, obviously, we need to get through this rate case and see. That's our focus at the moment, along with making sure that we maintain our commitments that we made in the merger process. The IRP process obviously suggests that going forward, there may be some further investment opportunities, and we'll certainly take advantage of those. Right now, what we're focused on is getting this first rate case resolved in a constructive manner. Got it. Absolutely. Best of luck. Talk to you soon. Thanks. Thank you. Our next question comes from Michael Weinstein with Credit Suisse. Hi, guys. Hey. Morning. Hey, Michael. I'm wondering to what extent has additional tax credit extensions and some of the renewable stimulus planning that we're expecting to see from the Democrats over the next few months built into the plan? Is there potential for upside, especially when I look at the solar portion of it, and maybe even just in terms of customer affordability? Maybe you could afford to do some more work, maybe in undergrounding or grid transformation. Yeah, 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. We'll look at whether there are opportunities. We have a pretty aggressive plan, as you've seen, and the Virginia Clean Economy Act last year passed an aggressive plan. We're moving very quickly. If there are opportunities to advance, we'll take them. The main effect of ITC extension is going to be a benefit to customers on rates. One thing, Michael, I'll add to that. It's Jim, is when it comes to ITCs that we recognize the earnings benefit from outside of a regulatory context, that, just to be clear, is not really a growth industry for us. Most of what we do that relates to ITC is in a regulated format where it benefits our customers, as Bob said. Two years ago at Investor Day, we gave some guidance that ITC recognition in earnings would be somewhere in the up to $0.15 per year range. Where we've been is really below that. In 2018, we were at $0.09, in 2019 we were at $0.11, in 2020 we were at $0.16. We still plan to trend within that run rate up to $0.15 per year guidance. Not a big impact in that area. Mostly on the regulated customer benefit side, as Bob described. Right. Just to be clear, the ITC doesn't reduce the rate base in any of the projects that you're working on a regulated side. Yeah, that's exactly right. My understanding is that strategic undergrounding is driven, there's a limit to the amount you can invest there by law. Is there any talk of perhaps maybe expanding that, considering maybe things might be getting more affordable due to federal tax credits? 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. If it were to be extended, it's unlikely that would happen this year. Okay, great. Thank you very much. Thank you. Our next question comes from Jeremy Tonet with JPMorgan. Hi, good morning. Morning. Morning. You outlined the decarbonization opportunity through 2035. Hey, Jeremy. We can barely hear you. Oh, sorry about that. Is that better? That's much better. Much better. Yeah. Okay, thanks. You outlined the decarbonization opportunity through 2035 today. How do you think about customer growth and other investments for that period? 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 talk a little bit about customer growth. We've had pretty consistent growth in our electric utility over the course of the last decade or so that we would expect to continue. On the Virginia side, for example, 35,000 new customers connected a year or so. On the gas side of our business, as we mentioned in our prepared remarks, very strong new customer growth. I'm not sure I totally followed the second part of the question. I apologize. Just the relative share, I guess, of the green CapEx is, just wanted to see if that's going to continue to be a large portion of what you're doing going forward or are there other chunky investments in the non-clean side we should think about there? The outlook is very much, and I think it's really reflected on the slide that shows that $72 billion opportunity. These are all decarbonization-related or enabling investments. That's going to be the absolute lion's share of our investment going out, and we would expect that to continue even beyond that long-term period. Obviously, 15 years from now is a long time in this business. Right. Great. Thanks. Then how much timing and recovery flexibility do you have with CCRO-eligible CapEx for the second triennial review period? Does your plan currently assume kind of bake in recovery of any of this spend explicitly? Yeah. As I mentioned, we have a variety of assumptions, not one single assumption related to the 2024 triennial. We do have a slide that shows what's eligible, and the total there, and we'll sort of take advantage of that as circumstances warrant. It's too early for us to know how much of it we would expect to use in the 2024 triennial. We just know what we're likely to have available. You can see that on that slide. Got it. Thanks. One last one if I could. Sure. You talked about Virginia legislation and just wanted to see about South Carolina legislation and if securitization came through, how would you deal with that? Yeah. We think securitization makes sense in certain circumstances. Storm recovery, for example, makes a lot of sense. Obviously, we didn't think it made sense with respect to new nuclear. We'll see if it passes. If it passes in a way that would be constructive, that's great. We'll just have to wait and see how it goes. I know that bill has been introduced a number of times in South Carolina in the past and hasn't been enacted. In circumstances like storm recovery, it makes a lot of sense. Great. Thanks so much. Thank you. Our next question comes from Durgesh Chopra with Evercore ISI. Hey, good morning, team. Thanks for taking my question. Good morning. Jim. Good morning. Jim, on slide 20, I'm just curious, the cash flow sources and uses go through 2020 and the plan goes to 2025. Am I reading too much into it, or are there differences in the composition of cash sources and uses in 2024 and 2025 as you ramp up your offshore investment? Yeah. Durgesh, thanks. The reason we went to just a three-year average view here is that over five years, the numbers get pretty big and maybe a little bit more difficult to bridge from where we are now or where we were in 2020. You probably are reading too much into it. We have elsewhere, of course, disclosed our equity financing plan through the end of the period on the next slide. You can see that the financing is going to continue. What will change is the operating cash flow, which will grow on a five-year basis, and the investing cash flow, which will grow slightly as it creeps a little bit back years in the five-year plan. Nothing more interesting than that, I'd say. Understood. I get it. Okay. More sort of granularity and conviction in near years but no significant changes in the makeup of source and uses. Bigger numbers. That's about it. Yep. Okay. All right. Just quickly following up just on slide 10, and maybe, Bob, this is for you or perhaps even Jim, just the largest regulated decarbonization plan. I love it. In terms of when I'm thinking about any legislative support that you need, is it fair to assume that this opportunity of $72 billion, you can accomplish this with the Virginia Clean Economy Act, or do you need further legislative support to kind of act on some of these generative opportunities? No, your assumption is correct. This is based upon the Virginia Clean Economy Act and the Grid Transformation and Security Act in 2018. All of this is already legislatively authorized. Now, we obviously have to seek approval from the commission for projects, and we've demonstrated on solar. As I mentioned in earlier remarks, we've had three solar filings approved by the commission already. We've had our electric transmission spend and those kinds of things approved consistently over the years. We're not looking for additional legislative enactments to carry out this 15-year regulated book. Excellent. Thank you for the update today, and much appreciate the added disclosures. Thanks a lot, guys. Thank you. Thank you. Thank you. Our next question comes from James Thalacker with BMO Capital Markets. Well, good morning, and thanks for the time, guys. Morning. I just wanted to circle back on your comments just on bill affordability as you implement your capital plan. Michael Weinstein actually raised a good question. As we saw the extension of the ITC at 30% at the end of the year, could you potentially talk to how you maybe quantify it or how it's going to impact customer rates and making things more affordable as you implement your capital plan? Yeah, I don't think we've quantified that yet. We filed an integrated resource plan earlier this year or last year, I guess we're in 2021. The 2020 integrated resource plan, we showed a 10-year look, that 2.9% that we talked about. I'm confident we'll be updating that. We certainly have an IRP update later this year in Virginia. I would expect as part of that, we'll run the numbers on the customer rates. We haven't quantified customer rate impacts of that ITC at this point. Okay, great. I would assume that it would give you a little bit more flexibility as we're looking down the road here. That is absolutely true. It is going to have benefits to customers in rates and offers us flexibility as we go forward. Great. I guess just to stay along that line is, and I know we're looking a little bit farther out, but maybe you could touch a little bit about some of the programs or, I don't know if you're ready to quantify it, but how you're thinking about controlling costs to create more headroom to continue to implement your capital plan over the next say, five to seven years. Let me talk about that. It's Jim. ITC is one element which will benefit customers for sure. The other is O&M. Let me give some kind of high-level thoughts on that. We talked at our last Investor Day about flat normalized O&Ms. Normalized is normalizing for new riders that have associated required O&M or things like pension benefits, which discount rates and the like make that number go up and down. We normalize for all that, and then we keep it flat. In 2019, we gave an estimate that by keeping it flat for three years across our entire business, we were going to save, versus a 2% escalator, like $200 million-ish cumulative basis. We did. Now it's still flat, and we're rolling that out for the full five-year period. Now, we did have some savings that actually went down a little bit in 2019, sorry, in 2020 from COVID. Not all that's permanent. Our effort to keep that flat O&M, so negating inflation or wage increases and things like that, it's not easy. It's not through big things like some of our peers have talked about step changes in O&M discovered during COVID. We had some COVID savings for sure, but our approach is a little bit different. It's kind of programmatic. It's pushing cost savings as part of the system, the culture. Finding ways to use technology and work smarter throughout the business. We have examples of that helps us keep that flat O&M. They're tiny in comparison to Dominion. Electronic time sheets and electronic signatures. I mean, I've got a long list. They're all tiny, but they add up. That's the kind of thing, the small efforts throughout the company, every state, every location that allow us to keep that normalized O&M flat. The reason we do that is to make room in the customer bill. Yeah, it helps out on the customer side and potentially also creates room in that bill for the capital spending that also benefits customers. That's kind of our other lever we have, is in managing customer bill is continuing to manage that flat O&M. Got it. Great. Thank you very much for the time. Thank you. Our next question comes from Michael Lapides with Goldman Sachs. Hey, guys. Thank you for taking my question and great slide deck today. Lots of detail. I have two questions. One, can you remind us, as a percent of rate base or dollar millions, what is coal generation and rate base both in Virginia and South Carolina? We set that out on a whole company basis, Michael, on page 32. As a percentage of total investment base, which is rate base plus the fixed assets, the PPE for our smaller contracted assets business, is 7%. 7% of rate base, effectively. Got it. Okay. This just is five-year plan, given obviously the spending on other areas, that goes to 4% by 2025 and down from there. Got it. If I think about it at the Virginia level, and you've done a significant amount of coal retirements in Virginia, if you wanted to retire facilities even earlier than planned, some of the coal facilities there, that would accrue or account as part of the CCRO in the 2021 to 2024 timeframe. Am I thinking that that's also an alternative, not just investing new capital that would necessarily get a cash return, but the write-downs of some of the older coal plants might as well? Yeah, a couple things there, Michael. One is, obviously we don't make decisions on fossil retirements based on the timing related to a regulatory proceeding. We make those decisions based on the sustainability of those plants going forward or if there's a change in the law or those kinds of things. I think that's an important thing to keep in mind. The other is that you are sort of conflating two different topics, I think. One is this customer credit reinvestment offset, which is provided for by statute. Those are projects that are either Grid Transformation projects or renewable projects, where that capital investment can be applied as essentially the customer benefit in an earning sharing mechanism. When you calculate when the triennial review is done and there are available earnings, there is an earning sharing mechanism, and then for the customer portion of that, it could either be a refund or one of these renewable or grid transformation projects. I think what you're thinking of is, if we retire a plant early, there's a write-down, and then that expense would be treated logically as an expense in the period if there are available earnings. That's the best for customers. It's what longstanding practice has been in Virginia. Two sort of slightly different things you're talking about there. Both have some impact on the calculation in the triennial, but we're obviously a long ways away from the second triennial here. Understood. Just coming back to the coal generation question, do you think your coal units in both states, given how much power prices have come down, given how much CapEx costs for renewables and storage have come down, do you think the coal units are currently economic still, the existing operating coal units? Is there a dramatic difference between the ones in Virginia and the ones in South Carolina? Yeah, I don't know that I'd say there's a dramatic difference. We obviously look at the economics of those plants regularly and make a determination whether they are viable in the future and whether they're properly valued. We'll do that, continue to do that on a regular basis. Got it. Thank you, guys. Much appreciated for taking the time. Thank you, Michael. Thank you. Our final question comes from Srinjoy Banerjee with Barclays. Hi. Good morning, guys. Thanks for taking the question. Just on thinking about FFO-to-debt metrics as well as the ratings. Obviously, we've seen a consistent improvement to those metrics, 15% in 2020. If we look at the S&P and Moody's targets for high BB B, I guess S&P requires 15% and Moody's requires 17%. How do you see your FFO-to-debt metrics evolve over the time period? Would you expect to stay around the 15% mark or expect an improvement given the levers that you have? Srinjoy, thanks a lot. Good to hear from you. The way we think about that is it hasn't been easy to achieve the improvement that we show in that one slide to get to the solidly mid-teens level. That's where we expect it to stay. I think maybe you were suggesting, is there an upgrade in the air? Of course, not against that. What we really hope comes to pass at some point is, again, further recognition of the business risk profile improvement. I wouldn't expect material changes in the metrics from where we are, from what we've achieved to where we've landed. I think that's in a good spot, probably where we'll stay. We'd love to have a little bit more headroom to that recognition I mentioned, and we want that headroom not because we want to blow through it, but just because we think it's more the better. That's kind of where we are on credit. Perfect. No, thanks very much, and appreciate the time. Yeah, thank you. Thanks a lot. Thank you. This does conclude this morning's conference call. You may now disconnect your lines and enjoy your day.