Dominion Energy, Inc. (NYSE:D) Q1 2020 Earnings Conference Call May 5, 2020 10:00 AM ET
Steven Ridge - Vice President, Investor Relations
Tom Farrell - Chairman, President and Chief Executive Officer
Jim Chapman - Executive Vice President, Chief Financial Officer and Treasurer
Diane Leopold - Executive Vice President and Co-Chief Operating Officer
Bob Blue - Executive Vice President and Co-Chief Operating Officer
Conference Call Participants
Shar Pourreza - Guggenheim Partners
Steve Fleishman - Wolfe Research
Michael Weinstein - Credit Suisse
Durgesh Chopra - Evercore ISI
Jeremy Tonet - JP Morgan
James Thalacker - BMO Capital Markets
Good morning, and welcome to the Dominion Energy First Quarter Earnings Conference Call. At this time, each of your lines is in a listen-only mode. At the conclusion of today’s presentation, we will open the floor for questions. Instructions will be given to the procedure to follow if you'd like to ask a question.
I would now like to turn the call over to Steven Ridge, Vice President, Investor Relations.
Good morning and thank you for joining us. 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, Q 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 will 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 the earnings conference call materials, including the earnings release kit.
Joining today's call are Tom Farrell, Chairman, President and Chief Executive Officer; Jim Chapman, Executive Vice President, Chief Financial Officer and Treasurer; as well as other members of the executive management team.
I'll now turn the call over to Tom.
Thanks Steven and good morning. I would like to start by expressing our gratitude for the healthcare and other front-line professionals who are engaged in a heroic effort to assist those who have been most acutely impacted by the COVID-19 pandemic.
We salute their efforts with deep appreciation and express our sympathy to all those who have lost loved ones to the disease. I also want to thank our own field personnel who are performing a vital public service by literally keeping the lights on and critical energy flowing. These front-line employees are supported by thousands and thousands of others who provide equally important service to our customers.
As everyone who follows Dominion knows the safety of our employees is paramount. As the pandemic began to emerge, we acted quickly to ensure that our employees were equipped to handle the impact of the virus. We've utilized our frequently drilled crisis response plans now continually supplemented by the most up-to-date health service and government recommendations.
Our efforts include implementing appropriate social distancing policies and activating our remote connection infrastructure, which has enabled more than half of our workforce to operate remotely. We have followed best practices in the distribution and use of PPE. And we are extending health and paid time off benefits as well as establishing a financial assistance program for employees that provides grants up to $2,000 to employees in need.
We've also donated $1 million to the American Red Cross and local nonprofits to assist directly with coronavirus relief. This is in addition to the millions of dollars we provide each year to customer assistance programs and charitable causes throughout our communities. This is the core value of One Dominion Energy in practice.
While even a single case of COVID-19 is a serious concern we have been fortunate that across more than 19,000 employees in 20 states of operation, we have had very few tests positive. The majority of which are either asymptomatic or mildly symptomatic and most of whom have already returned to work. We are keeping those employees in our thoughts and we'll continue to be focused on the health and wellbeing of our entire workforce while not losing sight of our essential duty to provide reliable and affordable energy.
Our thoughts are also with our customers. We are mindful of the hardships many are enduring. That is why, for example, we voluntarily suspended non-payment service disconnections and waived late fees across all our utility service territories. We will also offer our customers tools designed to assist them overcome the financial challenges they may be facing.
As our state and regional economies gradually begin to reopen, we're taking preventative steps to ensure that our workplaces are safe and that our customers receive the best possible customer service.
I'll now turn the call over to Jim to review our quarterly results as well as our thoughts on COVID-related impacts.
Thank you, Tom. I'll first turn to Slide 4 to report that our quarterly operating earnings per share, when adjusted for normal weather met or exceeded the midpoint of our guidance range for the 17th consecutive quarter. Our first quarter of 2020 operating earnings were $1.09 per share, which included $0.09 hurt from significantly worse than normal weather. This was the third warmest first quarter in Virginia on record.
Weather-normalized result of $1.18 per share exceeded the guidance range midpoint. Recall that weather in the first quarter of last year was a $0.06 hurt, but during the following three quarters we more than overcame that and finished the year with a total weather help of $0.02. Even without adjusting for weather, this was the 17th consecutive quarter of results within our guidance range.
GAAP earnings for the quarter were negative $0.34 per share. This result is driven in part by non-cash charge related to the planned early retirement of certain coal and oil-fired generating units in Virginia, consistent with the requirements of the recently enacted Virginia Clean Economy Act. The retirement of these units has been contemplated in previous versions of our integrated resource plan and was formerly announced in late March.
We also had a non-cash impact attributable to unrealized losses on our nuclear decommissioning trust funds. And as a reminder, we report such unrealized gains and losses on these funds as non-operating. A summary of adjustments between operating and reported results is included in Schedule 2 of the earnings release kit.
On Slide 5, we are initiating second quarter 2020 operating earnings guidance with a range of $0.75 to $0.85 per share. We're also affirming our annual guidance range of $4.25 to $4.60 per share. As usual, these ranges assume normal weather, variations from which could cause results to be toward the top or the bottom of these ranges. The second quarter and full year guidance ranges also reflect our preliminary expectations for the impacts of COVID on our financial results.
Before I walk through each of our operating segments let me address potential questions around our expectations for the shape and pace of the economic recovery. And affirming our annual guidance today, we have assumed that the economy begins to ramp up through late summer, though as you will see momentarily, demand in Virginia thus far is positive relative to recent years despite the pandemic.
Of course, variations in the duration and the severity of the economic recovery may ultimately impact our financial results more or less than our current forecast. The future is difficult to predict, which is why we are reiterating the demand-related earnings sensitivities for our two electric utilities.
We hope this is useful for our analysts and investors to sensitize their models to reflect their own perspectives on the shape of the economic recovery. In any case just as we have since early March, we plan to provide periodic public updates on the various aspects of the crisis impact on our business, including updates on load as we make our way through the economic reopening process, which will occur gradually, which began yesterday in South Carolina and is expected to begin in Virginia in 10 days.
Now I'll address our businesses, starting with our largest segment Dominion Energy Virginia. On Slide 6, we present updated load related data. This graph represents daily weather-normalized load in the PJM DOM Zone as compared to a two-year historic weather-normalized average.
As you can see, the impact of COVID on zonal demand has not changed materially since our prior disclosures and Virginia load is continuing to prove extremely resilient. We attribute this to four factors, illustrated on Slide 7, first, residential usage, which typically accounts for around 45% of segment revenue. Last month, we saw year-over-year weather-normal residential load increased by about 3%. As you can see, residential customers contribute more to revenue per unit of usage than our larger volume classes.
Second, the proliferation of data centers in our service territory. Despite a statewide stay at home order, April weather-normalized commercial load decreased by only 3%, as a result of COVID, mostly due to the stabilizing effect of data center demand growth. Third, limited industrial exposure, while we saw industrial demand decrease by around 3% in April only 6% of DEV’s revenue is attributable to industrial usage. And finally, government, military and other demand which accounts for 16% of revenue and which was up almost 4% year-over-year last month.
Let me also point out a few aspects of our regulatory framework, which are important to consider as they relate to the financial impact of the COVID crisis. Around 40% of DEV’s rate base is in rider form that allows for an annual true-up for changes in sales volumes. In addition, fuel pass-through related revenue is also adjusted annually to account for among other factors over or under recovery due to usage.
While not observable in the load data we have shared, these two mitigants taken together account for half of DEV’s operating revenue and represent effective decoupling from changes in load. We continue to monitor the situation closely. Based on observable data, we are not at present forecasting major COVID-driven revenue impacts associated with reduced load at Dominion Energy Virginia during the remainder of 2020. Of course, the situation is dynamic and so we are reiterating for your reference, a previously published rules of thumb for load variations by class. Accounting for nearly 45% of our operating earnings, DEV represents our largest state regulated utility exposure to COVID-related demand fluctuations by far.
Let me now turn to Slide 8 to walk through the same data for Dominion Energy South Carolina's electric operations. From the time the executive order took effect on March 31, we've seen a noticeable decline in weather-normal demand as compared to the two-year historic average. Specifically, April's electric demand was off almost 10% on a relative basis.
While we expect increases in residential demand, our South Carolina operations when compared to Virginia do not benefit from the same data center load stability and as demonstrated on Slide 9 are more exposed to industrial load. 10 of DESC’s top 30 industrial manufacturing customers have temporarily idled at least some production. However, all the two of those 10 have communicated plans to restart production in the coming weeks.
In Virginia, there are some structural mitigants to the load impact. Like in Virginia, there are some structural mitigants to the load impact on revenue in South Carolina. First, around 25% of DESC’s total rate base is in rider form with monthly true-ups. Almost another 10% of rate base is attributable to South Carolina gas distribution operations that operate under regulation that shows up annually.
Finally, fuel pass-through related revenue for both electric and gas operations are adjusted annually to account for among other factors over or under recovery due to usage. While not observable in the load data we've shared, these three mitigants taken together account for nearly 50% of DESC’s operating revenues and represents effective decoupling from changes in load.
Further, the impact of COVID on our South Carolina financial performance stands to be relatively less impactful financially, given Dominion Energy South Carolina's overall earnings contribution is approximately 10% of Dominion’s forecasted operating earnings. The future is difficult to predict, but we currently expect that load trends will gradually rebound through the late summer.
However, the situation is dynamic and therefore we are also reiterating our rules of thumb for variations in load class – in load by class for DESC’s electric operations. Please note that these sensitivities assume a full year 1% change in load. April alone represents only a small percentage of annualized load, given first, it's typically the lowest sales level of any month. And of course, it's only one of 12 months of the year.
I'll also note here that we voluntarily requested a 60-day delay to our upcoming South Carolina electric base rate proceeding. For the merger agreement, this was originally expected to commence later this quarter and conclude with new rates effective January 2021. We feel strongly that this is the prudent approach to take.
Let me turn to Slide 10, now to address our remaining segments, which I'll be able to cover more quickly. First, Gas Distribution, which accounts for around 15% of operating earnings, over 80% of segment operating margin is protected through decoupling or fixed charges including riders and gas pass-through mechanisms. These constructive rate structures significantly reduced the impact we expect to see from COVID-related demand fluctuations. I should also point out that we are entering a multi-month period of off-peak and shoulder demand seasons for gas distribution.
Next Gas Transmission & Storage, which accounts for nearly a quarter of operating earnings. A few points here, first, the typical contract structure is long-term and take-or-pay with reservation or capacity charges which are largely independent of utilization. Average remaining contract life is six to seven years for existing pipelines in storage and much longer for Cove Point liquefaction and ACP.
Second, this is a demand pull dominated segment. As we shared at Investor Day, approximately 80% of the revenue is attributable to segment assets are derived from demand-driven counterparties such as utilities. Third, counterparty credit quality is high, given the regulated utility SKU of the customer base. Where shippers did not meet our stringent internal credit standards, we typically require higher than industry average protections including collateral in the form of cash or letter of credit that often covers multiple years of exposure.
And finally, Cove Point liquefaction contracts are take-or-pay and allow the shippers to deliver cargoes anywhere in the world, not prohibited by U.S. policy. So customers are obligated to pay regardless of usage, I would note that through today customers continue to nominate volumes that are at the plants design capacity. And finally, contracted generation operates primarily under long-term PPA or hedge arrangements, which are unlikely to be materially impacted by the effects of COVID.
Taking a step back now, we are also watching payment arrears data carefully across all of our segments. To-date, we've seen modest increases which are consistent with our expectations. That said, we will work carefully with our customers over the coming months to provide options and tools to maintain service and assist them in returning accounts to current.
We do not expect bad debt expense in excess of budgeted amounts to be a material driver for the year, though not directly comparable. During the financial crisis, we thought annual bad debt expense at DEV for instance increased by around just $20 million. At our electric business, like most of our peers, bad debt is addressed during periodic base rate case proceedings. At nearly all of our gas utilities, we have full or partial ability to recover bad debt expense under real-time rate mechanisms such as dedicated trackers or fuel pass-through adjustment clauses.
While the impact of COVID on our financial results during the first quarter was muted, we are not assuming that that will continue indefinitely. That is why we are redoubling our efforts to identify opportunities to reduce costs generally across our businesses as we look to be prepared to achieve our affirmed annual guidance range. While I'm not in a position today to quantify a total amount, a few straightforward examples would include reductions in business travel, office supply and operational fuel expenses, as well as the impact of implementing a hiring freeze. We will continue to monitor these and other O&M reduction options.
Turning now to liquidity. As shown in Slide 11, as volatility and capital markets increased significantly in March, we moved quickly and opportunistically to enhance our liquidity position out of an abundance of caution. Over a period of around 15 days, we added nearly $5 billion of available or funded debt capital.
On Slide 12, we updated our annual financing plan for our year-to-date issuance. I'll note for the avoidance of doubt that as of today there is no change to our long-term debt financing amounts, our external equity need of $300 million under our DRIP program or our CapEx guidance for the year. We have and we'll continue to look at the potential to defer small amounts of capital investment where safety and reliability will not be compromised but any such deferral would be relatively small and short lived. We have not observed any major disruptions to any of our key supply chains.
And finally, a few comments regarding our pension on Slide 13. We entered the year with a 92% funded status up meaningfully from the previous year. While it's way too early to tell where we will land at year-end 2020 when we remeasure assets and liabilities, a few factors to consider. First, discount rates which are based on long-term all-in corporate bond yields are around the same level as observed at the end of last year despite lower treasury rates. And second, at the end of January this year, we decided to hedge the equity exposure in our plan assets using the futures market.
As public equities fell in March, we took advantage to monetize most of our hedge position at 25% and 30% in the money levels. We are beginning to reinvest those cash proceeds back into equity exposure. As a result through April, plan assets are close to flat for the year, which compares favorably to the significant declines that may be expected for typical pension portfolios.
I'll reiterate, there's a long way to go before the next expected remeasurement date of December 31 but regardless of where we ended up for the year on funded status, we do not expect to need any pension plan contributions this year or next.
Turning now to Slide 14 and in summary, we reported our 17th consecutive quarter of weather-normal results at or above the midpoint of guidance. And our 17th consecutive quarter results within our guidance range. We feel that our businesses are well positioned with regard to COVID-related demand impacts but we are monitoring the situation carefully. We affirmed our annual operating EPS range of $4.25 to $4.60 per share. And we're also affirming our post-2020 guidance of five plus percent annual operating EPS growth as well as our dividend per share growth of 2.5% per annum subject as is customary to board approval.
I'll now turn the call back over to Tom.
Thanks Jim. Amidst the turmoil of the global pandemic, our employees have been singularly focused on maintaining reliable and safe operations for the individuals and families, businesses, industries, and government agencies that we are fortunate to count as customers. We are in the public service business and our work directly impacts the lives of our customers and communities.
Let me share three specific examples that occurred over just the last six weeks on opposite sides of the country and shown on Slide 15. On the morning of March 18th the Salt Lake City Valley experienced largest earthquake to occur in that region in 30 years. The 5.7 magnitude event generated nearly 1,800 service calls and 1,400 gas distribution work orders, which were both over 20 times normal. Our crews went to work immediately to address any potential safety issues to ensure reliable service to homes and businesses in the middle of the winter season.
As a testament to the quality of our infrastructure and as a result of the significant investments in integrity and pipeline replacement programs authorized by our regulators, we have found zero material gas leaks across our system, as a result of the earthquake. Less than four weeks later on April, 13, 21 tornadoes touched down in South Carolina, four of which were classified as EF3 strength with winds up to 165 miles per hour, and one of which was classified as an E4 tornado with winds up to 200 miles per hour. It was the most prolific day of tornado activity in South Carolina in the last 35 years.
Within 24 hours, our crews had restored 96% of the 117,000 of our customers that lost service during the storm. During the next two days, our people worked very long hours in devastated areas to finish restoring service, and along the way, helping those communities find a measure of normalcy. In the aftermath of the storm, the South Carolina office of regulatory staff issued a press release commending the dedication and effort of the State's electrical personnel, men and women who worked tirelessly to ensure power systems were restored, even in the midst of a global pandemic.
That same day, 300 miles northeast, heavy rains and winds gusting to 70 miles per hour across Virginia and North Carolina, interrupted service to nearly 200,000 of our customers, within 24 hours 95% of customers have been restored by our crews with the final 5% reconnected over the following 12 hours. I'm proud, but not surprised at the way in which our Dominion Energy team members have responded on behalf of our customers throughout this trying time.
Turning to Safety, which is our first core value. Our first quarter safety results ranked us number one, among our southeastern peer group and puts us on track for another year of record performance. Through the end of March, our OSHA recordable rate is approximately one half that of the first quarter of last year. Also two weeks ago, seven of our gas infrastructure operating companies received awards from the AGA for superior safety performance.
The remainder of my prepared remarks, I will address the results of the Virginia General Assembly session and the status of the Atlantic coast pipeline. Virginia legislative session formally concluded last month, on April 11, Governor Northam signed into law the Virginia Clean Economy Act or BCA, which compliments the existing Grid Transformation and Security Act adopted in 2018. That law established a comprehensive framework for utility regulation and investment in Virginia.
As shown on Slide 16, the VCEA sets our company on a path of achieving the most significant legislatively mandated clean energy investment program in the United States. As a result, Virginia is poised to become a nationwide leader in zero carbon deployment over the next three decades. This mandate will create 1,000 of jobs, support localities, bolster the Virginia economy, attract businesses and families, improve the environment and serve as an example for other states seeking to achieve similarly ambitious sustainable energy goals.
The plan also supports our enterprise-wide net zero methane and carbon emissions targets by 2050. The VCEA calls for and finds in the public interest the development of renewable generation and energy resources, storage resources as follows; 5,200 megawatts of offshore heat wind, 100% of which may be utility owned, 16,100 megawatts of solar or onshore wind, 65% of which may be utility owned, in 2,700 megawatts of energy storage, 65% of which maybe utility owned. These targets are to be met over the next 15 years with additional goals by 2045.
In addition to establishing a public interest determination for these programs, the law outlines specific regulatory approval criteria and affirms rider eligibility for each of those programs. I'll discuss them in turn. Regarding our previously announced 2,600 megawatt Coastal Virginia Offshore Wind project, the commission is required to presume costs are reasonable and prudent if the project meets three key tests as shown on Slide 17. First, competitive procurement and solicitation standards for components are met. We have met the standard on our Virginia projects for many years. We have always sought to drive down costs while also balancing performance and reliability to optimize value for our customers.
Second, the projected levelized cost of energy or LCOE is reasonable relative to a specific EIA benchmark. Our early estimates for project LCOE are of $80 to $90 per megawatt hour compared very favorably to this benchmark. This range does not include the benefit of any available federal tax incentives which are working to preserve for the benefit of customers. And third, the projects construction commences prior to 2024 or has a plan to enter service by 2028. Our project satisfies both milestones.
We're pleased with the progress today on both our pilot and full-scale deployments. Despite the pandemic, the primary pilot project components have arrived from Europe as shown on the cover slide. And we expect installation to begin this quarter with commercial in-service by year end. We have also initiated the sub-sea survey work that will support the submission of our full scale offshore, construction and operation plan to bomb by the end of the year. We have joined in this work with the Virginia fishing industry.
We continue to work with equipment manufacturers and service providers to encourage making Virginia the hub for the U.S. offshore wind industry. And we are leading a consortium of industry experts and participants in the development of a fully Jones Act compliant installation vessel, that will be equipped to handle all current turbine technologies as well as the next generation turbine sizes of 12 megawatts and larger. These mega turbines result in fewer foundations and reduce construction and maintenance costs, thereby lowering the levelized cost of energy.
The vessel which will be funded by consortium participants, including Dominion Energy, will enter service in 2023 and operate continuously for several years under contracts with multiple major U.S. offshore wind developers. Based on our current estimates for fully installed costs, which we expect will reduce over time. Offshore wind as directed by the VCEA represents between $8 billion and $17 billion of capital investment over the next 15 years. This range is consistent at the low end with our previously announced cost estimate for our 2,600 megawatt project.
The high end represents any incremental opportunity associated with the law’s direction to put an additional 2,600 megawatts into service by 2035. Accordingly, we are updating our five year growth capital estimate for this program by one year. The new outlook now totals $3.5 billion and reflects the ramp up on our full scale deployment in 2024. Our previously plan included only $1.1 billion. We planned to make an initial rider filing in 2022.
Next, Solar and onshore wind is shown on Slide 18. Given Virginia's relatively onshore wind resource, we expect that the vast majority of the laws mandate in this area will be met through a very significant expansion of the state's solar capacity. As I mentioned previously, the law calls for over 16,000 megawatts by 2036, 10,000 of which can be utility owned.
In other words, Dominion will install on average nearly 700 megawatts of solar every year for each of the next 15 years. Today, we have achieved more than 70% of our previous commitment of at least 3,000 megabytes by 2022. In the first quarter, we got our third solar rider application approved by the Virginia commission. Meeting the ambitious targets set by the VCEA we’ll require a redoubling of effort in this area and we have already begun to significantly increase our activity. In granting approval for solar and onshore wind, as well as energy storage, the law directs the commission to give due consideration to quote the promotion of new renewable generation and associated economic development, projected fuel savings and the RPS standards of the law.
Assuming 65% utility ownership is provided in the law, solar generation represents approximately $19 billion of capital investment over the next 15 years. Our role for five year growth capital forecast now totals $5.5 billion as we seek to accelerate investments to meet the laws milestones. Our prior estimate was $3.7 billion.
Next, energy storage, which includes our existing efforts to develop a pumped storage facility in southwestern Virginia. The commission recently approved four battery technology pilot projects totaling around $30 million and about 16 megawatts. In order to achieve the 2,700 megawatt target established by the law, we will be focused on a very aggressive effort in years to come. Assuming 65% utility ownership is provided in the law, energy storage represents approximately $7 billion of capital investment over the next 15 years. Our existing five year growth capital plan, which were arising only modestly as we roll forward by one year already included around $1 billion related to pumped storage.
On Slide 20, we show the impact of updating our five year growth capital estimates for just these three programs, which shows a $4 billion and over 70% increase. We're not updating existing five year CapEx figures for other programs or segments today, but we do not expect any material changes from our most recent guidance. We will look for an opportunity in the future to provide a comprehensive update across all segments. Looking longer-term on Slide 21, these three legislative priorities of wind, solar and energy storage taken together represent based on current cost estimates, somewhere between $34 billion and $43 billion of growth capital over the next 15 years, subject to regulatory approval.
This is additive to the existing rider eligible investments we will make this decade or electric transmission, nuclear relicensing, strategic undergrounding, grid modernization and renewable enabling quickstart generation. Together these projects represent nearly $16 billion of growth capital, also subject to regulatory approval. To give these figures some context, Dominion Energy Virginia’s 2019 year-end rate base was around $24 billion.
Turning to Slide 22, As reported in our recent integrated resource plan, we expect typical residential customer bills from 2019 through 2030 including authorized pass-throughs related to Virginia joining the regional greenhouse gas initiative to keep pace with average historic inflation. We expect fuel savings from increased dispatch of renewable generation to be a key customer benefit. Of course, we always work to maintain competitive and affordable rates and we have a track record of success as demonstrated by our current rates which are below the state, regional and national averages.
I would also note that our current typical customer bill is almost 40% lower than the average of Reggie participating states. We expect that our future rates will stay lower by a very wide margin compared to those states. Further, the VCEA expands on existing programs that are designed through direct funds to assist lower income customers. The proliferation of renewable but intermittent resources across our system will also require the continuation of our extensive investment in transmission infrastructure, as solar generation sites emerge throughout the state. It will also require an increasingly modern grid, which is why the recent commission decision to reject certain, although certainly not all aspects of our most recent grid transformation filing was disappointing for our company, and particularly for our customers.
We will continue to see comprehensive deployment of smart meters and other enhancements across our system, which will greatly improve the way we interact with customers, as well as our ability to manage our increasingly two way energy delivery system. VCEA and associated legislation will dramatically change our generation fuel mix over the years to come. What will not change is our obligation to customers to provide 24/7 energy with the least possible disruption. That is a message that has been clearly reinforced during the COVID pandemic.
Technological, operational, and economic constraints around the multi-day baseload dischargeability of existing battery technology, combined with the fact that sometimes in Virginia at least the wind does not blow and the Sun does not shine for extended durations, meaning days, not hours, ensures that natural gas-fired generation will continue to play a critical low emission role in our system for years and years to come. That's why our policymakers wisely included language in the VCEA in multiple places that provides express consent to consider system reliability and energy security holistically, before ruling out any low emitting fuel, such as natural gas. This aligns with our unwavering commitment to be net zero by 2050.
What is clear, however, is that less efficient and higher emitting sources of electric generation such as coal and oil will phase out of our system. To that end, we have taken steps since early 2019, including during this first quarter to retire more than 3,300 megawatts of mostly coal and oil fired power stations. Given recent changes in law, the commission is no longer mandated by statute to approve period expense treatment for these retirements. Period expensing is the best choice for customers and dictated by many years of existing commission precedent.
During the triennial review under the framework established by the GTSA, if the commission determines that we have excess earnings, either because they determined to overrule existing precedent and amortize plant retirement charges over a longer period of time or because our financial performance otherwise warrants such determination, we will offset those excess earnings using dollar-for-dollar customer credit reinvestment offsets or CCROs, including our $300 million offshore wind pilot project investment. Only if we are unable to fully offset excess earnings with CCROs, would the commission be authorized to order a one-time customer refund and reduce rates by no more than $50 million through the following triennial review, which will conclude in late 2024.
Now to the Atlantic Coast Pipeline and Supply Header. On Slide 23, we summarize the status of select project permits. First, the Appalachian Trail crossing. On February 24, the Supreme court heard oral arguments on the case. We expect the court to rule on ACP’s favor in the coming weeks. Such a ruling would restore the authorization of the project to proceed along the existing route. Despite the pandemic, the court continues to meet telephonically and release orders on cases heard earlier in the term.
Next, the biological opinion. Progress continues, despite COVID as we provide information that is responsive to request from both FERC and the Fish and Wildlife Service. We expect the authorization to be reissued by the end of this quarter, that period would mark nearly a 12 – a full 12 months since the court invalidated the prior version in July, 2019. Demonstrating the rigor with which the permitting agencies are approaching resolution of the concerns identified by the court.
In the case of the air permit for Buckingham Compressor Station, we've already begun to submit additional data and analysis to the Virginia department of environmental quality, which we believe provides ample justification for the original air board decision to approve the strictest minor source air permit in the nation and addresses all the concerns voiced by the court. We expect the permit to be re-issued by year end. Finally, with regard to the nationwide permit 12, which is issued for the project by the United States Army Corps of Engineers, we had expected the permits to be re-issued shortly after the issuance of the biological opinion, as the core in recent months has taken steps that address the four circuits concerns.
The recent decision related to the Keystone pipeline by the district court in Montana has potential implications for nearly all critical infrastructure investment and associated employment across the country. This includes the provision of drinking water, electricity and fuel, internet, radio, television, telephone and other communications and stands to impact service to the public governments, defense installations, hospitals, schools and other businesses and industry. Since the nationwide permit 12 program was renewed in March of 2017, it has been used more than 38,000 times and the core estimates that it has over 5,000 additional notifications awaiting action.
The department of justice has sought and been granted expedited consideration for their motion for partial state pending appeal with all replies due by this Friday. We expect a focused effort across the industry, commerce and labor groups, as well as the department of justice to clarify and resolve the issue in a timely manner. With regard to ACP, we believe it is too early to tell what if any impact this ruling will have on the existing and timing and cost of the projects which are otherwise affirming today.
So many issue has revolved in a timely manner, we can maintain the existing schedule and cost estimates so long as we can take advantage of the November, 2020 through March, 2021 tree felling season. We will continue to monitor and provide communication to investors as appropriate. Based on these expectations, we remain confident in the successful completion of the project and note that there are no changes to the financial contribution estimates for 2020 and beyond that Jim provided on our fourth quarter earnings call.
Customers need this infrastructure now more than ever to ensure the reliability of energy supply. Accordingly, we have recently finalized negotiations with major customers that provide a fair rate of return for the project owners and appropriately balanced project costs among the parties. Further, we remain confident in Virginia regulatory approval, the prudency of capacity contracts as part of Dominion Energy’s fuel filing cases as the project nears operation. Legislation that passed during the recent Virginia General Assembly session established a fuel case review criteria that recognize the importance of energy reliability and largely mirrors the standard for prudency already employed by the commission.
With that, I will summarize today's call as follows, our safety performance is on track to set a new company record for the lowest OSHA recordable rate. We achieved whether normalized operating earnings that exceeded the midpoint of our guidance range for the 17th consecutive quarter. We affirmed our 2020 earnings guidance. We confirmed our EPS growth expectations apply plus percent post 2020. We're excited about the opportunities under recently enacted legislation in Virginia to increase the sustainability of our generation fleet, which will also be supportive of our corporate-wide net zero carbon and methane emissions by 2050 commitment. And we are making significant progress across all of our capital investment programs to the benefit of our customers.
We will now be happy to answer your questions.
Thank you. And at this time, we will open the floor for questions. [Operator Instructions] And our first question comes from Shar Pourreza with Guggenheim Partners. Please go ahead.
Hey, good afternoon guys.
So good details on your CapEx projections with solar onshore wind, offshore wind post the passage of the legislation. And obviously you guys increased your capital budget for clean energy investments through your planning period. Is there anything you could point to structurally that could hinder you pulling additional spend forward as your total investment opportunity set is materially higher, i.e., bill headroom permitting. Obviously, offshore wind may have some hindrances, but how do we sort of think about further onshore or solar spend being pulled forward? So trying to get a little bit of a sense on any potential upside to the near-term plan and your current plus 5% growth trajectory, which is proving somewhat manageable?
Hey, Shar, good morning. It's Jim. Thanks for that. Yes, so what we've done here is we have not obviously done a Full Monty roll forward of all of our capital spending and addressed more holistically our long-term growth rate, et cetera. All we've done today is we've addressed an update, a roll forward for a new five year period just for three programs just within one segment. So we of course do the more holistic view less frequently, we did it in 2016, we did it in 2019, so that's not for today. So we'll find a time in the future where we will do a full walkthrough and be able to provide a little more color on other moving parts other than just these three updates on the specific spending programs within DEV.
Good, got it. So I’m like – so I guess the takeaway, and correct me if I'm wrong, if the plan is becoming much more sustainable, much more – you'll be able to fine tune that 5%-plus growth rate in time.
Yes. Keeping in mind, when we set the 5% plus growth rate, when we announced that last March, we had in our minds that this kind of spending program is going to continue or maybe increase in Virginia and elsewhere. But that's right. We'll come back and address something more holistically when we're not kind of in the midst of a global pandemic. We didn't think this is the right time.
Got it. Agreed there, by the way. So just a real quick last question on ACP. You kind of stated timely resolution to the Nationwide 12 Permit, right? Is there any more color you can provide on this? I mean, when would you start to reevaluate the timing of the resolution was pushed to a later part of the year. And then, Tom, can you just maybe elaborate a little bit more on your latest contract negotiations with customers. What's been sort of the debate? Is it – or what's been sort of the push pull? Or is it more of a focus on COVID, and that's been a bit of a slowdown. So just maybe a little bit more elaboration on the negotiations, and I'll jump back in the queue. Thanks.
Thanks, Shar. I’ll talk – I’ll answer the first part of your first question. Diane will answer your second question. So the key dates for us is, as we said, is the tree cutting season, which runs through the end of – through March of next year. We need 10 weeks or so of tree cutting period, 10, 12 weeks to complete what we need to – you need to keep in mind, we already have 250 miles of trees cut on this 600 mile pipeline, and not every single mile has trees on it. Actually 100s of miles do not. So that's the real key for us is getting into that tree cutting season. So we'll see what happens.
A lot of people were quite surprised by the judge's decision. And there's a lot of – I think you should expect to see a lot of a mickey briefs being filed pointing out – I mean, what he talked about was all forms of utility infrastructure, not just an oil pipeline in Montana, it was every single utility infrastructure program in the country. So it seems like maybe a strong action by the judge, maybe not completely justified by the case put forward. So we'll have to just have to see how that goes. Of course, you can go to the 9th circuit after that, things – but we'll judge that as it goes along. On the second part of your question, I'll turn it over to Diane Leopold.
Okay. Good morning, and I believe your question was related to the customer negotiations. And if I'm not answering, let me know. But the customer negotiations are complete. They have been finalized throughout the quarter. So the rate and all the other terms and conditions have been complete to ensure that there is a fair rate of return for the project, and it balances customer needs and customer costs.
Got it. Any change in the return assumptions that's material to disclose?
Excellent. Thanks guys. Congrats, it’s a very resilient plan. Congrats.
Thank you. Moving on to our next question. This comes from Steve Fleishman with Wolfe Research. Please go ahead, sir.
Thanks, good morning and hope all of you are doing well. Jim, I’m looking forward to the Full Monty roll forward.
Thank you, Steve.
But just maybe to fill that picture in a little bit. The – any color on kind of financing need changes with a higher capital plan? Maybe that would come with the roll forward, but how should we think about that?
Yes. I think that’s fair. That will come with the roll forward, but we're outlining here spending plans that are large, but over a 15 year time period. So when it comes to financing, we're going to continue our process of giving that one year and sometimes multiple years in advance. There's no change in the near term. Certainly no change this year, but we'll revisit what the financing mix will be kind of across the board as we do a more holistic update.
I would note, though, for the avoidance of doubt that for these programs, we've talked about under the VCEA, all the financing will be at DEV, so a VEPCO legal entity. So we're not considering project financings or other things like that. It will be a mix of regular way of financing at VEPCO. But more to come when we provide more holistic updates.
Okay. And then, maybe kind of a, bit of a specific, but also a high-level question for Tom. So just the whole picture of Virginia with this plan, obviously seems to be very very green, clean, sustainable focused program. So maybe you could just give a little color on kind of the whole – what the state is trying to do with this? And kind of the view of you in the context of the state? And then specifically, this part of the plan, the new plan on the Jones Act vessel, just any color on how that would work and fit into – maybe fit into kind of this whole Virginia plan?
Sure, Steve. So the – just to refresh everybody on the state of Virginia politics, for the first time, and I think it's 30 years in this session of the general assembly, we had elections last year. We're always off [here] [ph] for our state legislature, both in the Senate and the house of delegates. And for the first time, it's in either 20 or 30 years, I don’t remember which – how many decades. You had democratic party in charge of both houses plus the executive branch. And there was a lot of interest among the new members of the House and Senate to advance a number of policies on many fronts, not just in energy. There was all sorts of legislation around gun rights, for example, and a variety of other things, minimum wage, et cetera.
And there had been an effort – we had worked for years with a number of groups to – on solar in particular, and how to make sure that, that came into Virginia in an efficient, cost-effective way. And we worked with a wide variety of the policymakers to ensure that these goals are achievable and still affordable for our customers. And you can see from our IRP that was filed last week, that we expect, even with this spending plan, our plan B under the IRP is the most likely plan, at least we think it is, the most likely plan. Others will weigh in, of course. We'll run at a little bit – right around traditional inflated rates of inflation.
And we've joined RGGI and our rates, well, when you now compare our rates to the RGGI sates, we're 40% lower than the average RGGI state, we're half of the highest RGGI state. And so there's a lot of room in there for us to stay extremely competitive. So Steve, I think overall, from a big picture view. It was part of an overall effort across many different parts of policymaking to have a more progressive outlook as those policymakers would call it, a more progressive outlook on a variety of factors. Your second question had to do with vessel, which I'll turn it over to Bob Blue.
Hey, good morning, Steve. I would put the vessel in the context, not just of Virginia, which Tom did a nice job of describing, but in the entire East Coast. If you look from New England all the way down to Virginia, there are a host of offshore wind projects in various stages of development. All of those projects are looking for a Jones Act solution for installation, ours among them.
So we're excited to be a leader in a consortium of potential infrastructure investors, other participants in the industry on a vessel that will allow the installation of larger turbines compliant with the Jones Act. So we think that project fits very nicely into the context of what we're seeing in terms of offshore wind development off the East Coast.
And just would that be in Virginia?
Sorry. Sorry about that. Just when it comes to the profile of that vessel, just to clarify, that will be fully contracted long-term profile. And we don't have a number for our planned percentage ownership. We will be an owner through our contracted generation segment. But we expect infrastructure style returns from that. Business profile and therefore, expect interest from infrastructure investors and other industry participants to co-fund that project. Thank you.
Interesting. Okay, great. Thank you.
Thank you. Our next question comes from Michael Weinstein with Credit Suisse. Please go ahead, sir.
Good morning. Sorry about that. The Jones Act vessel, is that going to be part – is the cost of that, the investment, is that part of the cost of the offshore wind going forward? Is that included in the CapEx profile for that?
No. Michael, good question. It's not. The amount, which is to be determined, will be invested. Our stake will be invested through our contracted generation segment, not in DEV and not part of the capital spend we outlined for offshore wind.
Right. And what is the timing of – it looks like about another 2.6 gigawatts of offshore wind that you're planning on over the next 15 years, what's the timing of the second 2.6 gigawatts, is that clearly after the first 2.6?
Yes. Absolutely, still to be determined where that might be. If you look at our IRP, we show that coming in 2034. But it will be after our initial project, which Tom described, that we would expect to be in service into 2026.
And I apologize if you mentioned this before, but also the timing of investments in storage, battery storage. Is that – how has that pays out going forward? Are you waiting for any specific technological improvements before you begin to put significant capital into that?
Yes. It's Bob again. No, I wouldn't say we're waiting for specific technological improvements. As you know, we have a mandate in the statute by 2035, we would expect to pay storage out during that period. It will take us a few years before we start layering it in. But again, if you look at the IRP, this is obviously generic storage. We don't have specific projects scoped out at this point, but we start layering it in around 2026 is when you would see that start to go into service based on the models we're describing here.
And one last question about data centers. Data center load is up. Is that – that's on current data centers actually running at – they're just running at higher capacities. I guess it's probably from work at home that you're – sort of your…
Yes. Again, it's Bob. The answer to that is yes. So they're ramping. There's a ramp rate with data centers. We would usually see them start to hit a peak later in the year, but they're peaking earlier this year. I don't know. You could surmise, it's related to what's going on with the pandemic and more broadly, but we just know it's happening.
Are you aware of any plans to expand and build more data centers as a result, like maybe more than would have been built prior to the crisis?
Yes. We've had strong data center growth in our service territory for some time and expected strong data center growth for some time to come. And we have seen no slowdown in that at all. Would expect very strong data center growth going forward.
All right, thank you very much.
Thank you. And our next question is from Durgesh Chopra with Evercore ISI. Please go ahead.
Hey, good morning, guys. Thanks for taking my questions.
Sorry if I missed this, but just Virginia, obviously looking pretty strong here at South Carolina, what are you assuming in the 2020 guide as decline trends for the rest of the year?
I didn't hear the last part of the question.
Yes. Durgesh, we couldn't hear quite the last part of your question.
What was the assumption of what for 2020?
The South Carolina demand decline trends in your 2020 guidance.
Got it. Durgesh, sorry. We were having some technical difficulties. I got you. So what are our assumptions there? So yes, a couple of things. We're obviously, in Virginia, not a material impact yet, but we are seeing now these steps get underway, economic reopening in Virginia and South Carolina. South Carolina, kind of announced yesterday, so modest steps underway. But we are not expecting like an immediate snapback.
That's not the assumption that backs our guidance. We're expecting that, that will slowly recover through late summer. So when it comes to our guidance, we've obviously reaffirmed the annual guidance and long-term. But there are a couple of gives and takes there. So one is weather, not to your question, but we had $0.09 of weather hurt. So the rest of the year, like last year, we expect to make up some of the ground we lost in the first quarter home weather.
Virginia, as you mentioned, no impact, and we'd expect the same and then in South Carolina, we expect that the loads bottomed out, and then we're going to – again, going to see that gradual recovery through late summer.
Got it. Thank you so much. And just a quick follow-up on financing costs. So just can you quantify for us or just versus plan? What – you've done a ton of financing here. So what's the impact versus on financing costs versus the plan you had in place at the beginning of the year?
Yes, Durgesh, good question because our financing plan, while intact on a full year basis, is a little bit modified because we accelerated a number of our financings into that March time period I talked about in my prepared remarks. So this financing cost for the year is something we're watching pretty closely. And I don't have a specific number for you, but a little bit of color. Obviously, we raised $5 billion earlier than we otherwise would have some of that short-term debt. But some of that just replaces what already would have been in our plan commercial paper.
And as one example, one of those short-term financings, one year financings that come to mind that we did in that period was at LIBOR plus 50 with no fees. So kind of not too far off where CP would have been anyway. So not a big driver. And now as you look forward from here, the markets have recovered in dramatic fashion, as you know, the fixed income market.
And the issuance rates from here on out for the next three quarters the way it looks right now is they're even lower all-in than they were in January. So we had a little bit of pressure from doing things earlier within our plan than we would have expected otherwise. But now we expect probably to make some of that up as rates have – all-in rates have decreased.
Got it, thanks so much, guys. And the detailed disclosure by segment on COVID is super helpful. Congratulations on a solid print and appreciate all the disclosure.
Thank you, Durgesh.
Thank you. And our next question comes from Jeremy Tonet with JP Morgan. Please go ahead.
Hi, good morning.
Just want to follow-up on ACP. A bit more here on ACP. Thanks for all the color that you provided so far. Just want to clarify, I guess, do you need Nationwide 12 Permit for FERC approval to restart construction here? And are there any other potential hurdles for FERC here that you see?
This is Diane Leopold. So obviously, we need to have our major permits in place for the majority of linear construction but again, as Tom said before, the key thing that we're really watching with respect to our forecast is a productive tree felling season between November and March. So while there is in the Nationwide 12, you do not need to have that for hand felling of trees. It is not a regulated activity under the Army Corps Nationwide 12 Permit. So subject to FERC approval, we may be able to begin hand felling trees through the season. We would look to have that for full ramping up of linear construction.
Got it. Understood. Thanks for that. And then just sticking with ACP here, what factors could impact project cost and timing between now and the tree felling window? Or just do you have a line of sight at current estimates as long as permits are in place prior to November?
Yes. The range of forecast that we have given that has not changed since the last quarter, has a wide range of scenarios that is not materially impacted again so long as we have a productive tree felling season this winter.
Got it, great. I’ll leave it there. Thanks for taking my questions.
Thank you. And our final question comes from James Thalacker with BMO Capital Markets. Please go ahead, sir.
Thank you for the time. Can you guys hear me?
Yes, good morning.
Yes, good morning.
Just maybe just to pivot a little bit to the other regulated businesses. I know that you guys had delayed the rate filing for Dominion Energy in South Carolina. But I was as you kind of pushed that off into the fall and kind of given what's been going on, I guess, with demand trends, do you guys see an opportunity maybe to propose something a little bit more formulaic down there or maybe try and see if you could do a rate plan that includes decoupling as part of that proposal?
I don't – we're still, of course, in the process of developing the plan. But right now, the schedule would call for us to file notice on July 15 and file the case actually in August. We expect that to happen at this point, barring some other developments. But we're still developing that rate case, and we'll see how it comes together and when we file the notice.
Great, thanks for the time, guys.
Thank you. And this does conclude this morning's conference call. You may disconnect your lines, and enjoy your day.