Dominion Proposal A Total Refresh, SCC Staff Says

The integrated resource plan (IRP) for Dominion Energy Virginia, pending at the State Corporation Commission, involves building or rebuilding enough generation to replace most of its existing capacity.

That is one conclusion reached by the SCC staff’s own analysis of Dominion’s filed plans. A bottom line $5.6 billion estimate of the 15-year customer cost of this building spree, along with upgrades to the transmission grid, produced a banner headline story in the Richmond Times-Dispatch.

Go to the SCC website and you find the staff written testimony divided into eight documents, with a total of 422 pages, and there are additional exhibits not available to view because the company has demanded the information remain confidential. An integrated resource plan by its nature covers the entire company operation, and this review is the first since 2018 legislation changed many of the rules and produced General Assembly blessing of grid and renewable energy investments.

A summary of the overall testimony is provided by Gregory Abbott, associate deputy director of the public utility division. It was Abbott who noted that the 15 gigawatts (GW) of generation in the plan approaches the maximum demands of 16.3 GW in 2017, although summer peaks for Dominion customers have reached 18 GW. “In other words, the Company’s build plan is nearly equal to its existing coincident peak load,” Abbott testified.

SCC testimony hides the projected cost of extending the life of Dominion’s nuclear plants, at company’s request.

Part of that is not new generation but a license extension for the existing nuclear plants accounting for 3.3 GW.  The cost of upgrading those plants to achieve that extended lifespan is substantial however and needs to be weighed against alternatives.  The actual cost is hidden by redaction.

To make room for the new, about a dozen existing plants will be retired years before the end of their useful lives, stranding about $450 million of depreciated costs on the company’s books.  Most of them burn coal, oil or wood to generate electricity, although two burn natural gas. Customers get the bill coming and going, paying for both sets of facilities – new and old.

Dominion plants proposed for early retirement, and their expected retirement dates.

The staff testimony usually starts the debate on these cases, and other case participants will now add more to the record, all of it answered eventually by Dominion staff and its own outside experts. The two judges of the Commission (no movement on filling the third seat at the Assembly) will hold a public hearing starting September 24.

The IRP itself is just that, a plan, and only takes form as the various grid or transmission projects later come to the Commission for review. The SCC in the past has said approval of the IRP does not guarantee approval of the elements. But this IRP, more than any previous one, is going to the heart of key issues facing Virginia.

First, as noted by the newspaper article, the SCC staff is rejecting Dominion’s own internal projections for electricity demand growth. It points to data from the regional transmission organization PJM that indicates a lesser demand going forward, and if you don’t have as much demand, you don’t need all these new generation sources. If you build them and don’t need them, the cost per customer goes up.

Abbott states that PJM requires Dominion to have a generation reserve margin above its normal demand of 16%, but in recent years it has been as high as 38%.  The staff analysis projects 5 GW less demand than Dominion does by 2033.  The staff suggests the SCC use an alternate projection for all its decisions going forward.

Second, the SCC is challenging a key assumption that solar power has a 26% capacity factor in Virginia, meaning it produces power 26% of the time (versus a nuclear plant that might run 90% of the time.) Abbott and the staff note that Dominion’s existing solar panels have shown capacity under 20%, and down in (slightly sunnier) North Carolina the record is only a bit better. That capacity factor is also crucial to any cost-benefit analysis.

The still-falling cost of solar installation leads the staff to recommend a slower build plan for that resource. “Based on the Company’s 2013 IRP data and 2018 IRP data, the costs of solar have decreased substantially from 2013 to 2018. By delaying deployment of 5,000 MW of solar from 2013 to 2018, a total estimated cost savings of $10.6 billion was realized from just a five-year delay.  The percentage cost decrease exceeded the value of any investment tax credit that would have been realized,” he testified.

Third, the staff doubts that Dominion can achieve the legislative mandate of $870 million in energy efficiency program to drive down demand, especially since large industrial customers are able to opt out. Between 2009 and 2018 the SCC authorized $368 million in such programs, but Dominion spent only $199 million, “likely because of lower than projected customer participation,” Abbott wrote.

The staff also challenges Dominion’s estimates of the cost of compliance with the Regional Greenhouse Gas Initiative (RGGI) on the basis of the earlier issues, the high projected load growth and the optimistic capacity factor for solar.

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10 responses to “Dominion Proposal A Total Refresh, SCC Staff Says

  1. Mr. Haney continues to offer compelling stuff!

    I’m okay with closing mercury-spewing coal plants… but I suspect Dominion would still choose to use them over buying PJM power if they could do so. So those plants are probably effectively obsolete and uneconomic.

    But if Dominion can essentially buy PJM power now rather than run the coal plants – why does Dominion want to build more gas plants rather than continue to buy from PJM / already-built gas plants?

    I suspect some answers are in the redaction…

    I, like Tom, would like to see a financially-healthy Dominion Power.. but in a manner that serves Virginians as well as their investors… and it’s starting to look like Dominion prefers to remain a generator of electricity rather than buying it from PJM…

    I’d like to see the Govt commission a 3rd party analysis of electricity needs in Virginia now – and into the future – and to use that analysis in judging what Dominion’s role should be in that context.

    I just see Dominion’s IRP as more a document that is what Dominion wants to do – for Dominion – than I see it as a credible vision for Virginia’s electricity needs.

  2. Some observations:

    1. “If you build them and don’t need them, the cost per customer goes up.” DE is proposing to build these new generators at ratepayer expense to compete in a wholesale marketplace (PJM). Normally (if anything is normal about DE’s ratemaking) whatever is built with ratepayer funds ends up operating for the ratepayer’s account — that is, at ratepayer cost, or profit if there is any. That gives DE’s ratepayers a direct stake in the wholesale market competitiveness of the new generation. If it can compete and make a profit, fine; and in fact a smaller number of ratepayers will each get a larger share. If DE can’t, then DE’s ratepayers will own a bunch of lemons.

    Even by its own projections, DE proposes a small capacity shortfall which it probably plans to make up from the PJM marketplace. You must understand that DE could go out and buy every bit of its capacity and energy needs in the PJM marketplace for its ratepayers at the current market price for each. Or if DE is so sure of what it’s doing it could make this a “merchant” generation investment at shareholder expense and risk, with 100% of the profits going to shareholders. Either way, that would mean no (i.e., zero) up front capital cost for the ratepayers to finance or amortize. Of course it is possible that Dominion will make a decent profit off selling the output of this new generation (as well as the refurbished nuclear generation) in the PJM marketplace, which profit should flow entirely to ratepayers (if they paid for the equipment making the profits). But ratepayers bear the risk that DE has not forecast the competitiveness of its new generation correctly, or that gas prices will rise again long before these new gas-fired plants are ready to be retired. They, the ratepayers, will bear the entire risk and cost of obsolescence due to changing conditions on the Grid.

    2. “The SCC staff is rejecting Dominion’s own internal projections for electricity demand growth [based on] data from the regional transmission organization PJM that indicates a lesser demand going forward . . . [and] the SCC is challenging a key assumption that solar power has a 26% capacity factor in Virginia [as] Dominion’s existing solar panels have shown capacity under 20%.” See above — the ratepayers bear the entire risk that DE has forecast neither its load growth nor the competitiveness of its proposed new generation correctly, and these hefty overestimates are a very bad sign.

    3. “The still-falling cost of solar installations leads the staff to recommend a slower build plan for that resource.” Yes, DE should build less solar at DE ratepayer expense. If the question were, should DE build less solar at DE stockholder expense, I would feel very differently about the answer. These days, in the PJM region, heavy investment in utility-scale solar generation is risky, but not nearly as risky as heavy investment in more gas-fired cycling generation. Solar may even prove more profitable, and relatively speaking the capital investment cost is lower. But this should not be up to the SCC to decide. DE has proposed, here, what it thinks will be best for DE shareholders, but entirely at its ratepayers’ risk. If DE really thinks that what’s best for its ratepayers is not simply to rely on purchases from the PJM wholesale market but to outcompete everyone else in the PJM region for sales into that market, at ratepayer cost and risk if they fail, then I have a bridge over the East River they might be interested in buying!

    4. “A license extension for the existing nuclear plants account[s] for 3.3 GW [of the proposed ratepayer-funded generation].” Exelon, the single biggest eastern-U.S. owner of nuclear generation, is closing down nuclear units. So are most other nuclear owners. This is not because we don’t need them any longer, but because the world price of nuclear fuel (driven up by Chinese and other new competitors) means these units can no longer operate cheaper than the least expensive alternatives (solar and cheap natural gas). So why should DE’s ratepayers take on the risk of that new investment in nuclear power? If DE wants to go ahead with shareholder money, at shareholder cost and risk, and sell the power to PJM for profit (setting aside a fund to relieve ratepayers of any lingering responsibility for decommissioning the plant), then have at it, DE! But you know they won’t do that. The cost-benefit calculation isn’t even close to a benefit.

    Building all this new generation at ratepayer expense is for DE shareholders, courtesy of the suckers in the GA who either don’t know any better or must consider themselves paid to turn a blind eye to what is going on. Looking back in a few years, I believe this will become the source of enormous economic cost, if not embarrassment, for Virginia.

  3. I’m a serious skeptic of DE building plants to make a profit – and even a bigger skeptic that such profit if it did happen – would go to ratepayers in the form of lower rates..

    Some critics might suggest that what DE is doing is using it’s monopoly status to fund it’s entrepreneurial efforts and if they fail – the ratepayers pick up the tab and if they succeed their investors get the profits…

    I don’t blame DE for pursuing this.. it’s the nature of capitalism and a characteristic of entrepreneurial skill.

    The problem is that we KNEW THAT and that’s why we set up the SCC to look out for the interests of ratepayers.. and we got folks in the GA who are either asleep at the switch or their sympathies are with DE not ratepayers; these are some of the same folks who hammer Govt for “taxes”.

  4. A fair, just and reasonable rate of return must consider financial and business risk. The former is determined by considering the utility’s capital structure. The latter must consider many factors, including the risk that the utility will not recover all of its investment in plant. A power company that finds its coal-burning power plants obsolete may or may not be able to include the costs of amortizing the undepreciated investment. If there is a risk the shareowners must eat all or part of the undepreciated investment, it’s business risk is higher and it should be allowed a higher rate of return.

    However, if a PUC is going to allow for amortization, the utility’s business risk is less and its rate of return should be lowered.

  5. I for one find it very hard to come up with any real numbers to compare … I am happy to see that the SCC is challenging Dominion’s total kwhr projected use. Several of us have called for that for several years.
    I am sorry to see that any real move toward distributed generation does not even come up …
    and that although Dominion has 7,442 MWs (6900-coal) of operating oil and coal units, at the end of 15 years some will still be operating. I totaled that long list of proposed plant closures and it appears to be just over 5,000MWs. Looks like 15 years from now we will still be operating 2,000MWs of coal in addition to our gas-fired units! GO FOSSILS!

  6. Yes, DE management may indeed be fossils. At least they are exploring utility-scale solar enthusiastically now; and maybe offshore wind. I’d love to see more distributed generation too, but solar DG is already fully permitted (if not encouraged) by DE’s tariffs, and one of their stated purposes for improving their distribution grid is to facilitate two way flow to accommodate the expanded DG they anticipate. And DG (including in DE’s own service territory) is huge down in NC, where there has been a big State tax credit to push it. I just don’t see DE as the obstacle. What’s lacking is any State of Virginia promotion in the form of tax credits, and/or legislation overriding the many obstacles to DG that homeowners and small businesses face in local zoning and building codes.

    What bothers me is the construction of any new DE generation for ratebasing. The future of the grid, the future of natural gas prices, is just too uncertain to be sticking ratepayers with the risk of depreciation on those new units for the next 50 years. As TMT says, full amortization is not guaranteed; but at least DE has a much stronger case to make for adhering to the “regulatory bargain” to offset stranded investment down the road if it was built for ratebasing. What they don’t have is a good case for ratebasing new generation at all while operating in the middle of the most competitive wholesale electric market in North America. These should be built, if at all, as merchant plants, with DE accepting the business risk. The fact that DE won’t do that says to me, they recognize that despite passing up the profits, passing this risk of obsolescence onto ratepayers is likely to prove beneficial to shareholders before long, perhaps sooner than later.

    I sympathize about the possible slow demise of DE’s coal fleet; but as Yorktown illustrates, arbitrary deadlines can be costly. Mt. Storm does have some locational advantages that should keep it operating longer than most. But even relatively efficient rust belt coal units are getting retired these days if they are in PJM — they just can’t compete. Eg., First Energy’s recently announced retirement of >4GW of coal, its last remaining coal units.

    • Acbar … Thanks for your knowledgeable and sensible comments. I think the throw on possibility of more than 2 windmills must have come when they saw the price for Vineyard Wind. My Grandmother’s label was “pennywise and pound foolish”. Not a show of vision there. AND there is a bad story to be told about the fracked gas market.

      The numbers and the sun itself are different in CA but the state has had both commercial and residential PACE loans. I think the availability of low cost money that doesn’t eat up a property’s assessment, and follows the sale of the property like a conservation easement, has been instrumental in the large PV build. The program was blocked here by screwed up law that looked good but couldn’t work. Now that Arlington has done the state’s work, maybe PACE will get adopted in more jurisdictions, although it is commercial only. That is a way for your merchants to get involved.

      I think too there is a good political trade off out there … More demand will be created by EVs so let Dominion rate base public, and building only, charging stations in exchange for starting a distributed upgraded grid with micro-grids and storage in the Hampton Roads area. Every building in the state does not need smart meters tomorrow. The redo can move from congested area to congested area with a real upgraded grid. North Carolina is ahead on that too. Schools and hospitals are being set up as emergency stations along the grid that can isolate in hurricane weather.

      This lack of vision will cost them in the long run, I believe

      • Perhaps lack of vision; perhaps also a clear vision of how to make it someone else’s problem. I just posted under the Micron discussion but it’s also relevant here: There are a number of uncertainties that Dominion seems intent on shifting from shareholders to ratepayers: “How long will the Marcellus Shale continue to supply cheap natural gas from fracking? How long will it take for distributed customer-owned, on-site solar generation and cheap battery storage for time-shifting to become the norm? What will be the Grid impact of a fully electric-powered transportation fleet, or a vigorous carbon tax? To these uncertainties add: How long will Virginia voters put up with the GA’s willful suspension of cost-based utility ratemaking?” The list goes on.

        I don’t know enough about the PACE loan program except that there was a dust-up a while back about interfering with FHA mortgages which should have been anticipated. PACE sounds like the right direction to go in to avoid the legal problems arising when DG equipment vendors sell electricity from their own PV arrays to the hosting customers at a contract rate, triggering incumbent-utility exclusive-retail-territory objections, something TomH and I have discussed here. I hope the Arlington small-business implementation is a good and successful one and offers a way to work around such problems.

  7. Acbar … Like your list …
    PACE can be more than small business loans. Some of the CT loans are quite large and the issue is that with a common set of parameters the loan can be securitized. CT has done that with at least 1 batch. I am on the trail of the changes that were made in the law last year and what Arlington has managed to get written up. They did the loan parameters and found the banks etc. Roanoke is starting a PACE program too. Michael Milkin invented the program with good input at his Institute.

    Re what Dominion understands .. just ran across this … from Charleston WVA paper. “For years, coal was the base of everything we did,” Orndorff, DE’s WVA state policy director, said in a panel discussion on energy’s future in the state. “It still is, and it still has a role, but we need to talk about wind. We need to talk about solar, because the Procter & Gambles of the world want that.”

    West Virginia “needs to make a quantum leap” when it comes to inexpensive and renewable electricity options, and I believe that the gas decision that looked good in 2014 will cost the company, and us, mightily in the not too distant future.

  8. Pingback: Dominion Objects to Testimony on Pipeline Cost - Bacon's Rebellion

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