Bob Blue
President, Chief Executive Officer & Chairman at Dominion Energy
Thank you, David, and good morning, everyone. We had another solid quarter and are well positioned to meet our expectations for the year. We're steadily executing on the largest decarbonization investment opportunity in the country, as outlined on our fourth quarter call in February. The successful execution of this plan is already benefiting our customers, communities, the environment and our investors.
I'll begin with safety on Slide 4. Through June, our OSHA recordable rate was 0.52, which remains low relative to our historical levels and substantially below industry averages. We take pride in our relentless focus on safety, and it is the first of our company's core values. Now, I'll turn to updates around the execution of our growth plan.
First, at Dominion Energy Virginia, our regulated offshore wind project development continues to be on schedule and on budget. On Friday, we received approval from the Virginia SEC for our rider and the CPCN for onshore transmission. The commission concluded that the project is in the public interest and that our request for cost recovery associated with the project met all requirements as called for in the VCEA. We're continuing to review the specifics of the order, but we are extremely disappointed in the commission's requirement of a performance guarantee. While there are scant details, the order states the customer shall be held harmless for any shortfall in energy production below an annual net capacity factor of 42%, as measured on a three-year rolling average.
You may recall that 42% is also our projected 30-year lifetime average net capacity factor, meaning, of course, that roughly half the time, it would be above that level and half below. Effectively, such guarantee would require DEV to financially guarantee the weather, among other factors beyond its control, for the life of the project. While no party opposed approval of the project, there were concerns raised regarding affordability and the financial risk to customers given a project of this magnitude. However, the commission's performance guarantee created unprecedented layer of financial one-way risk to DEV and is inconsistent with the utility risk profile expected by our investors.
There are obviously factors that can affect the output of any generation facility, notwithstanding the reasonable and prudent actions of the operator, including natural disasters, acts of war or terrorism, changes in law or policy, regional transmission constraints or a host of other uncontrollable circumstances. We believe the commission already settled this issue when it declined to adopt a performance guarantee for our Clean Energy 1 solar projects in 2021 after such a provision was proposed by SEC staff.
In that case, the commission ordered that involuntary performance guarantees, already unprecedented and regulated utility generation, are not required for projects specifically contemplated within the framework of the VCEA and needed by law to meet the objectives and requirements therein. By applying the commission's own logic, the same outcome should be made here. And all of this is occurring at a time when fuel costs have increased dramatically, leaving renewable energy as one of the few ways to alleviate inflationary pressures on electricity prices.
As shown on Slide 5, offshore wind is expected to save Virginia customers billions of dollars in fuel costs. It will also enable economic development opportunities through Hampton Roads and the Commonwealth. This project is a key component to a diverse energy generation strategy to meet the Commonwealth's clean energy goals while simultaneously meeting the need for an affordable and reliable grid. For example, it is expected to provide customers over $5 billion in benefits on a net present value as compared to being dependent upon purchasing energy and capacity from the PJM market.
In summary, we continue to believe this is an important and beneficial project for our customers. It also has significant stakeholder support. Nevertheless, the performance guarantee as outlined in the commission's order is untenable. We plan to actively engage with stakeholders on the unintended consequences of that provision and are reviewing all public policy options, including reconsideration or an appeal. So more to come here. We'll update you along the way.
Turning to other notable clean energy investment updates on Slide 7. Last month, the Virginia SEC approved the settlement agreement for the nuclear subsequent license renewal rider filing. Nuclear life extension represents nearly $4 billion in capital investment through 2035. These Virginia units have performed exceptionally well for years, providing over 30% of our customers' energy needs and providing that energy at a low cost and with zero carbon emissions. Successful nuclear life extension is a win for our customers and the environment.
On solar, our next clean energy filing will take place in the third quarter. We expect the filing to include about a dozen solar and energy storage projects. The filing will represent at least $1.5 billion of utility-owned and rider eligible investment, further derisking our growth capital plan provided earlier this year. Let me touch on the solar supply chain. As we've discussed on prior calls, there continue to be challenges. Supply is still tight and prices for certain components are still up. However, our plans remain largely derisked.
As it relates to the Department of Commerce's anti-circumvention review, I would remind everyone of the detailed remarks I shared on last quarter's call. We remain focused on the customer impact and advocate for energy policy that provides for an affordable clean energy transition. Development since our last call only reinforce our confidence in our near-term and long-term development expectations.
This past quarter, we received commission approval to suspend our rider RGGI as Virginia works towards its exit from that program. We also received approval that RGGI compliance costs incurred through July 31 and not yet recovered, totaling approximately $180 million, be alternatively recovered through base rates currently in effect. These approvals provide a meaningful benefit to customer bills.
Finally, last month we reached a settlement agreement with the SEC staff on the fuel factor component in DEV's rates. The settlement includes our voluntary mitigation alternative to spread the recovery of the under-recovered fuel balance over a three-year period to reduce the effect on customer bills. If approved, this settlement, together with other recent rate revisions, represents an increase to the typical residential customers' monthly bill by approximately 7%.
Turning to Slide 8. We're dedicated to the delivery of safe and reliable energy to our customers, which is also affordable. Based on data from the U.S. Census Bureau, the share of our customers' wallet attributable to DEV's customer bill has declined over the years, a testament to the fact that DEV's rates have remained relatively stable despite an overall increase in household income during that time. Also, as regards to the starting point for relative rates, we're proud to have rates today that remain below the national and various regional averages.
Based on EIA data, our rates, even after taking into account our most recent fuel filing, are 8% lower than the national average. Looking ahead, we expect to continue to offer a compelling value proposition to our customers, with the addition of zero fuel resources to support sales growth in our service area.
As reflected on Slide 10, the share of our typical customer rate attributable to fuel is expected to decline, reducing our customers' exposure to future fuel cost fluctuations. By 2035, fuel is expected to be less than 10% of the total customer bill as compared to 25% of the total today. Our customers and our policymakers have made it abundantly clear. They want cleaner energy in a way that supports economic growth within our service area, and we're working to deliver those results.
Let me now address data centers, which have provided strong sales growth in our service area to date, a trend we certainly expect to continue. Recently, we've been laser-focused on the potential for transmission constraints in a small pocket of Eastern Loudoun County, Virginia that could impact the pace of new connections for data center customers, which are shown on Slide 7. Let me share a few thoughts on; one, what has created this issue; two, what's being done to resolve it; and three, the impact to our long-term financial plan.
First, what has created this issue? The data center industry has grown substantially in Northern Virginia in recent years. In aggregate, we've connected nearly 70 data centers with over 2,600 megawatts of capacity since 2019. This is roughly equivalent to over 650,000 residential homes. Data center volumes today represent about 20% of total sales in Virginia. Last year, this growth began to accelerate in orders of magnitude, driven by: one, the number of data centers requesting to be connected on to our system; two, the size of each facility; and three, the acceleration of each facility's ramp schedule to reach full capacity.
For some context, a single data center typically has demand of 30 megawatts or greater. However, we're now receiving individual requests for demand of 60 megawatts or greater. After extensive discussions and exchanges of data with our team throughout 2021, PJM incorporated this step change in growth into its 2022 load forecast, as shown on Slide 12. In 2027 alone, it shows an increase in data center load of 2,600 megawatts, which represents a 12% increase as compared to the forecast just last year. To put that in perspective, that is equal to the entire installed capacity of our planned offshore wind project. This is an important step as the official PJM DOM zone load forecast is what governs all transmission planning and demonstration of need at both FERC and the Virginia State Corporation Commission.
After reviewing existing load and contract commitments and validating the power flow models, we've identified the need to accelerate our previous plans for new transmission and substation infrastructure in this area of Eastern Loudoun County, bringing it forward by several years. To be clear, we're not at the limits of our facilities today, but we need to act now to alleviate transmission constraints in the future while serving our customers growth in this region.
As delivering safe and reliable energy to our customers is our core mission, one that includes maintaining transparency, we're actively engaged with our customers and other stakeholders to communicate about this potential issue. This resulted in a pause on new data center connections while we work on solutions to alleviate the constraints as quickly as possible. For the avoidance of any doubt, transmission capacity is not constrained outside of this data center alley in Eastern Loudoun County, nor our data center customers in other parts of our service territory impacted by this issue.
Second, what are we doing to resolve the issue? We are actively working on a variety of potential solutions to serve as much of this increased demand as possible, while we work to accelerate transmission solutions to ensure a safe and reliable grid. This includes reviewing the current capacity constraint analysis, including performing additional in-depth analysis substation by substation; engaging further with customers and other stakeholders on projects to pace new connections and ramp-up schedules; and reviewing a variety of technical alternatives to address areas of concentrated load.
Based on the work and outreach done to date, it is clear that we will be able to resume new connections in the near term. But how much and how quickly is still being determined. The longer-term solution will absolutely require additional transmission infrastructure to be built. Among the needed additional infrastructure are two new 500 kV transmission lines into Eastern Loudoun County.
We're working expeditiously with PJM, the SEC, local officials and other stakeholders to fast-track these along with several other critical projects in order to alleviate the constraints. In fact, we have already submitted plans for the first new 500 kV transmission line with an in-service target date of 2026 to PJM last week. And we plan to file for approval with the FCC in the coming weeks. We're committed to pursuing solutions that support our customers and the continued growth of the region.
Finally, what's the impact to our financial plan? It's still early, and we'll have to work through this issue. But at a high level, we see this issue as being neutral to our financial plan based on the following. For 2022, in the near term, we expect no impact to sales growth as we have sufficient transmission capacity to meet our customers' load growth as recently connected data centers are continuing to ramp up their demand from existing facilities.
A little more color for that perspective. Data centers tend to have longer ramp-up and load following their connection to the electric grid. Historically, that period is about three to four years, although we see that period shortening over time. For the latter few years of our five-year plan, we expect slightly lower sales growth due to the transmission capacity constraints until new infrastructure can be placed into service.
However, we expect to overcome any potential headwinds by the acceleration of needed new build transition projects from later in the long-term plan to earlier, which increases capital in rider form in our five-year growth capital program. We plan to reflect such updates in our next roll forward to our long-term capital plan in early 2023. As a reminder, all related transmission capital spend is in rider form at FERC formula rates.
We will continue to provide updates as things develop. We remain focused on our core responsibility of safely providing reliable energy to our customers. And it's worth noting that in Virginia last week, we reached a record summer peak demand and our colleagues kept the electric grid operating flawlessly under demanding load conditions. We expect that exceptional performance to continue.
Turning to other business updates on Slide 13. At Dominion Energy South Carolina, new electric and gas customer accounts increased nearly 3% in the second quarter as compared to last year, driven by continued strong underlying population growth as South Carolina's population continues to increase at one of the fastest rates in the nation. In addition, we've reduced the average annual customer outage met or SAIDI, by over 20% during the first half of the year relative to the same period last year. I note that we've been in the top quartile among all utilities in the Southeast 8 out of the past 10 years. Investments made in prior periods are critical to system reliability and the continuation of this trend for the benefit of our customers.
In that regard, let me provide an update on our Integrated Resource Plan. Last month, the South Carolina Public Service Commission unanimously approved our 2021 IRP update. As a reminder, our preferred plan is indicative of the potential for accelerated decarbonization and assumes our three remaining coal units are retired by the end of the decade, which would result in a nearly 60% reduction in DESC's CO2 emissions. Recently, we filed a retirement study to evaluate the generation transmission resources needed to replace those units. These findings, among other updates, will be part of our 2022 IRP update expected to be filed next month. We look forward to engaging with all stakeholders on this planning process.
At Gas Distribution, our utilities operate in some of the fastest-growing areas of the country, with annual customer growth rates over 2% in two of our largest markets. We continue to see strong support for timely recovery on prudently incurred investment that provide safe, reliable, affordable and increasingly sustainable service. In May, we filed our statutorily scheduled rate case at Dominion Energy Utah. We're currently in the discovery phase and responding to data requests. We asked for an ROE of 10.3% and a revenue requirement increase of $70 million, which represents around a 6% increase to a typical customer bill. We expect new rates to be effective in January of next year.
Last month, first gas occurred in our natural gas storage project in Utah, Magna LNG, which will be used to meet system reliability for customers' gas supply in the Salt Lake City area. We remain on schedule to place this facility in service later this year.
On RNG, we remain one of the largest agriculture-based RNG developers in the country. We've recently commenced operations at our fourth RNG project and expect two additional projects to come online this year, for a total of six projects producing negative carbon renewable natural gas. In addition to these six projects, we have a portfolio of projects in various stages of development, continuing progress toward our aspirational goal of investing up to $2 billion by 2035.
Before I hand it over to Jim, I'll recap an important addition to our Board of Directors. Last month, our Board elected Kristin Lovejoy to serve as a Director effective August 1. Kris brings CEO and entrepreneur experience, a global business perspective, a passion for diversity as a catalyst for business excellence, and deep experience in the intersection of business, technology and cybersecurity. Kris' skills and experience in management, governance and technology will enhance our continuing efforts to deliver on our core mission. We look forward to her leadership on behalf of the company and our 7 million customers.
And with that, I'll turn the call over to Jim.
