SCC Rejects Most of Dominion Grid Proposal

The State Corporation Commission Thursday rejected in large part the highly-touted Dominion Energy Virginia proposal to rebuild its transmission grid, approving only the elements improving cyber and physical security.  Those were the least expensive and least controversial pieces of its application.

The 2018 legislation that stated major grid investments were in the public interest also re-stated the Commission’s charge to review them for prudence and reasonableness.

It did (here’s the order) and found this:

 

“With regard to those elements that have not been approved, we agree with Consumer Counsel (of the Attorney General) that as a general matter ‘the plan as filed is significantly lacking in detail with respect to the proposed investments.’ Also, with regard to the Plan in general, we agree with Environmental Respondents Witness (Caroline) Golin who stated, ‘As a complete package, the [grid transformation] Plan is not cost-effective and will result in an economic loss for all customers,’ While we find the Plan elements related to Cyber and Physical Security are well-conceived, well-supported and cost-effective, we find that the remaining Plan elements, which will cost customers hundreds of millions of dollars, are not.”

 The Commission told the utility it was free to address the SCC’s concerns and try again with a new application.  The cyber and physical security upgrades, coupled with improved communication along the transmission and distribution lines, are slated to cost about $910 million over ten years.  The rejected portions of the plan, with financing costs and profit margins, would had added another $5 billion in customer costs, according to the SCC’s figures.

The decision aligned closely with the criticism of the plan that surfaced during the discovery and hearing process.  The SCC staff complained about the lack of detail in the application, and those complaints were repeated at a hearing in November.

The rejected proposals include:

  • Advanced Metering Infrastructure (AMI) and related elements (total costs: $1.3 billion; Phase I costs: $696.8 million)
  • Intelligent Grid Devices, Operations and Automated Control Systems, and Emerging Technology (total costs: $776.0 million; Phase I costs: $157.5 million) and
  • Grid Hardening (total costs: $3.0 billion; Phase I costs: $486.1 million)

 “While supportive of the goals of AMI technology, the Sierra Club, Environmental Respondents and Consumer Counsel all oppose Dominion’s AMI proposal as not adequately developed and therefore neither reasonable nor prudent as to costs and benefits.

 “For example, Environmental Respondents Witness Golin testified, ‘[AMI and related technologies] are beneficial and cost-effective only to the extent the Company utilizes them to maximize the potential gains of rate optionality, energy efficiency, demand response, and DERs [distributed energy resources (“DERs”)].’ Witness Golin concludes, however, that “[t]he Company does not have plans to fully optimize the Smart Metering proposed …” and “[w]ithout a well-reasoned plan, this expensive equipment could be under-utilized and provide little to no benefit to customers and the utility.’

 We agree.” 

It is likely some of the members of the General Assembly who loved the 2018 bill will also agree that what Dominion proposed is not what they were promised.   Others will wait to hear from the company.

Tomorrow is the deadline for bill filing during the 2019 General Assembly.  Several bills are pending which might carry amendments relevant to this matter, an effort to put an even heavier thumb on the scale in favor of Dominion’s expensive proposals.  In other recent statutes the Assembly has been explicit in ordering SCC approval of its desires, imposing its decision on what is reasonable and prudent.

Stay tuned.

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18 responses to “SCC Rejects Most of Dominion Grid Proposal

  1. What’s bad for Dominion is good for Virginia. Kudos to the SCC. Dominion will never convince me they are anything but a pseudo-capitalist kleptocracy until the endless river of Dominion money stops flowing to the pseudo-democratic manikins in the General Assembly.

  2. I don’t feel good about last year’s 2018 GA session because we had the Dominion thing pushed on us with all the high pressure TV ads etc, and also I don’t like the way Virginia handled the tax “comforming” issue. Fingers crossed for 2019 (but my expectations are not high).

  3. I sorta wonder what impact the new appointment from the GOP will have on the SCC.. myself.

    Now is the time for the folks in the GA both Dem and GOP to stiffen their spines , and do what’s right and protect the SCC from more asinine actions coming from the GA though with this new appointment the fix might already be in.

  4. SH, an important nit: you say, the SCC “rejected in large part the highly-touted Dominion Energy Virginia proposal to rebuild its transmission grid.” Importantly, these facilities are NOT classified as transmission, but as distribution.

    Transmission facilities are the high-voltage grid under the jurisdiction of the FERC. Pursuant to federal law and FERC orders, all of Dominion’s transmission facilities are both planned and operated by PJM. These range from 765 kV down to 230 kV and occasionally down to 110 or 69 kV, and mostly ride atop big steel towers and poles. Dominion owns a portion of the PJM transmission grid and collects FERC-approved rates for PJM’s use of it.

    Distribution facilities are the lower-voltage grid connecting the high-voltage substations down to individual customers. Distribution facilities and rates are under the jurisdiction of the SCC and the “distribution rate” appears as a line item on all Dominion customers’ bills. Most distribution facilities operate at 69 or 13 kV down to 4 kV or even lower in some locations — these are the wires you see every day running down streets and alleys and country roads.

    What Dominion proposed to do (and rammed a bill through the GA declaring this to be in the “public interest” in advance) was beef up the distribution network within its retail service area to be more storm resistant (lots of undergrounding), to permit two way power flow to accommodate customer owned generation and someday battery storage, and to better stabilize the system in light of changing patterns of customer usage and cyber security threats. What the SCC has done is look at the cost-benefit tradeoffs involved in each of these. To take one example, undergrounding, there is an obvious economic tradeoff between investing more up front to protect the wires by burial from storm damage, and the cost savings (and happier customers) from less storm repairs and shorter outages. The SCC here finds that the proposed cost to ratepayers is too great for the benefit ratepayers will receive.

    • Incidentally, LarryG, as a customer of Rappahannock Electric Cooperative, you pay nothing to Dominion for its distribution facilities; REC owns all the distribution facilities serving REC customers. But REC, and thus you, pay Dominion a rate for the use of transmission facilities in PJM’s “Dominion Zone” — transmission facilities owned by Dominion — that deliver bulk energy from the PJM energy market over the PJM grid to all the REC distribution substations. Your electric supply never passes over Dominion distribution facilities.

      REC is a “distribution co-op” and does not own any generation except through ODEC. Some of PJM’s bulk energy comes from ODEC generation that sells power into the PJM marketplace at wholesale. REC, and thus you, also contract with ODEC and others directly for generating capacity rights equal to REC’s annual reliability requirements.

    • Acbar, I agree with almost all of your characterizations of the plan and the Dominion power delivery system, except this: “Pursuant to federal law and FERC orders, all of Dominion’s transmission facilities are both planned and operated by PJM.”

      None of Dominion’s transmission facilities are actually “planned” by PJM. A few of those facilities are included in PJM’s transmission expansion plan and are therefore subject to being “approved” by PJM planners, but those planners do not tell Dominion what to build or where to build them. The planners identify a need for upgrades and Dominion plans how to do it. Sometimes competitors offer different “solutions,” and PJM may pick among them, but this is a very rate occurrence.

      Most of Dominion’s transmission spending occurs completely outside the PJM planning or competitive functions. These are the “supplemental” projects about which there is such controversy at all RTOs right now. I’ve seen estimates that up to 96% of Dominion’s transmission spending is completely discretionary on its part and not subject to any PJM planning criteria or any competition from independent suppliers.

      • You are quite correct; I was looking at it from an approval point of view, not from the point of view of who does nearly all of the hard work.

        PJM’s charter is to make sure that the transmission facilities of the dozen+ transmission facility owners within the PJM region are built and operated in a coordinated fashion. Running a grid reliably requires absolute certainty of that cooperation! Factors include: where is new generation being located — both by traditional utilities and by independent owners? Where is the new load, and what is its load profile? Where are facilities being retired? Where is there transmission congestion that it would “pay” to eliminate — i.e., the cost of building a transmission fix would be paid off by energy savings to customers in a reasonably short period of time? Where do new generators so want to connect to the grid that they will pay to upgrade in order to connect?

        Nobody knows those factors better than the dominant traditional utility in any given portion of the Region as a whole. PJM gets all the transmission owners in for a series of planning meetings to inform each other and to work out inconsistencies, and to talk through disagreements if there are any, including, who will build what piece of the coordinated improvements? The resulting plan is almost always a consensus. But: if push comes to shove, PJM can reject a transmission owner’s proposal. That rejection can be appealed, but it goes to the FERC, not the SCC.

        As you probably know but others may not, the PJM regional transmission enhancement plan, or RTEP, is assembled annually after a long process of committee meetings headed by the Transmission Enhancement Advisory Committee, or TEAC, consisting of planning reps of the transmission owners of PJM. The State Commissions and generator groups and retail utilities all participate as well. This planning process is broken down into subregions and then the final package is assembled and looks like this: https://www.pjm.com/-/media/library/reports-notices/2017-rtep/2017-rtep-book-1.ashx?la=en

  5. Thanks Acbar and Rowinguy …

    your remarks are clarifying but not yet totally understandable.

    for instance, in Spotsylvania, there is a company that wants to put up enough solar panels to generate 500mw. I’m not sure how it plays out because there is opposition but in the presentations – it was stated that S-Power chose that location because a Dominion transmission line/substation are located there and S-power bought property adjacent to it.

    Now this is located in an area where REC provides the power (I think) and S-Power is not selling to Dominion or REC but to Microsoft and some other companies including VCU I think.

    Is there some simple more clarifying words to explain this?

    here’s the map with the power line/substation and the cleared areas are
    where they are proposing the solar.

    https://goo.gl/maps/ecuJtJ3wan62

    If this gets approved and they actually do generate 500mw .. through a
    connection to the substation – what happens to that power next?

    • As I understand it, that facility has a purchase power agreement for Amazon to buy a sizeable portion (or maybe all) of the output of that solar facility. But, of course, Amazon will not receive the actual electrons that the solar facility transmits to the PJM run power grid; it will receive the credits that the solar facility generates and can claim to be responsible for sponsoring that amount of clean generation. There is not a direct retail sale from the plant to the Amazon facilities that use it, none of which, I believe, are in the REC’s service territory. There are contractual arrangements that large enough customers can use to bypass the obligation to purchase at retail from the incumbent provider where the meter is located. Does that help any?

    • A late answer to Larry’s question (and I agree with Rowinguy also):

      Yes, you are talking about this generator, S-Power, locating next to a Dominion transmission line. That location may be inside REC’s service area and REC owns all the distribution lines and substations in that service area, but REC doesn’t necessarily own any transmission facilities (in fact, most of the REA co-ops like REC have chosen over the years not to own any transmission-level facilities). If you think of the Grid as the generation and transmission that is dispatched/operated by the system operator, PJM, (but not the distribution, dispatched/operated by the local retail utility,) then a part of the Grid is transmission facilities owned by Dominion, in this case dispatched/operated by PJM to deliver power to REC’s distribution substations for re-delivery to customers like you. You’ve got to keep “transmission” and “distribution” separate in your mind to make sense of all this.

      Rowinguy and I were discussing earlier how PJM and Dominion interact in operating and planning these facilities. As he pointed out, it’s not fair to say simply that PJM calls all the shots; Dominion owns a lot of transmission facilities, including some outside its own service territory, and operates them all as part of the Grid through its own operations center in Glen Allen, VA, and plans the transmission improvements it thinks are needed for its own load growth and other upgrades to all those facilities. But it does this planning and operation in coordination with PJM and the many other transmission owners in PJM, and for both operations and planning purposes PJM’s operations center in Valley Forge, VA sets the final goals and makes the final decisions (after weighing the views of the facility owners and the affected State Commissions and wholesale customers like REC). If there’s an operations or planning disagreement that has to go to a regulator, it goes to PJM’s regulator (FERC) not Dominion’s regulator of VA retail services (the SCC). In that sense Dominion operates its transmission grid as a contractor to PJM.

      Accordingly, if S-Power wants to connect directly to Dominion’s transmission facility rather than to REC’s distribution facility, it can do so, and to do so it must apply to PJM. These applications are “queued” in order of receipt; if there is available transmission capability in the Grid to accommodate S-Power (and all applicants ahead of S-Power) then S-Power’s application is granted. If there is insufficient Grid capability, then S-Power will still be granted permission to connect conditionally; meaning conditioned upon S-Power paying to upgrade the Grid to where it IS capable of handling S-Power’s output. Dominion and PJM will figure out the cost of that upgrade and who benefits from it (and therefore should share in paying for it); again, if S-Power disagrees, PJM or FERC (not Dominion or the SCC) make the final call. Usually these local Grid upgrades involve changing out switchgear and transformers in the affected transmission substation to accommodate the generator’s output on top of REC’s needs; but the required upgrades may include building a new substation and/or upgrading a transmission line to increase its operating voltage, or even the addition of a new transmission line. When those bigger costs are are stake, the potential generator usually looks for a cheaper place to connect to the Grid.

      If the generator can connect at the lower voltage to REC’s distribution lines, that’s OK too, but in that case REC becomes the middleman and works with S-Power and PJM to figure out what upgrades if any are required at the transmission level. Most “utility scale” generation connects at transmission voltages; but as you know, Distributed Generation like rooftop solar connects at distribution voltages, usually through a retail customer’s existing service wires.

      There is one exception to this PJM/FERC role in transmission Grid matters, and that involves siting for new transmission facilities. The location of a new transmission substation or new transmission line has to be approved by the SCC — with a rarely use exception under federal law allowing FERC to override a State in case the State simply tries to block a needed transmission line entirely. I won’t get into all that, but that is why, for example, the SCC was involved in where, and whether, to allow that transmission line across the James River. By the way, federal law is different for gas pipelines; with those, it is the FERC that decides the route (with State and other environmental input).

  6. All the information is very helpful BUT the real question is how do you see the grid functioning 15-20 years from now? You are all talking about the mechanical details of how a central generation facility operates and that is not where we will be.

    CVEC did something like Larry describes for REC in Louisa. I am not sure how it works but I think the Co-Op is buying the electricity with a Power Purchase Agreement or PPA from a solar facility, also built near a substation, and owned by a third party. You could call this “sub-central” generation. That is a step forward but not down to the microgrid level which will be a central structure of that future grid.

    The SCC agreed with the criticism that said … where is the planning for “energy efficiency, demand response, and DERs [distributed energy resources)”? None of that will get done as long as we hold onto the basic monopoly regs as Tom keeps telling us. “Build more, sell more” to profit more doesn’t work with retrofitting buildings for efficiency, demand response and on-site generation.

  7. Here is an example of the fact that we need to look at generation differently…
    ConEd estimated that its substation in Brownsville, which serves parts of Brooklyn and Queens, would need to deal with an energy demand 69 megawatts beyond what it could safely provide. The traditional fix for this quandary would just be to add another energy substation to the grid. But that would do little to curb fossil fuel dependency–a goal of both New York City and state–and it would replicate the same type of energy system that failed dramatically across the city during Superstorm Sandy …

    So instead, ConEd put out a call for smaller-scale energy projects that could alleviate some of the demand from the struggling Brooklyn-Queens grid. The initiative, called Brooklyn-Queens Demand Management, asks commercial, residential, and industrial customers within the Brownsville substation’s area to propose ways to reduce their grid energy needs.

    … Last June, L&M Development Partners, unveiled its innovative microgrid system–the first for any multi-family residential development in New York City. The entire project contains 400 kilowatts of rooftop solar, a 400 kilowatt natural-gas fuel cell, and a battery system that can store up to 1,200 kilowatt-hours of energy. … The system can also ‘island’ from the grid for about 5 days which is very important for a place that is vulnerable to storms like Sandy.

    For ConEd, the project is a welcome relief. Not only is the microgrid, with a $4 million installation cost, much cheaper than building another substation, (And a new substation would cost around $1.2 billion to build.) it also provides proof-of-concept for other property managers to implement similar types of energy-savings projects to ease the strain on the grid.

    https://www.fastcompany.com/90202972/this-apartment-complexs-microgrid-is-a-lesson-in-urban-resilience

    • Jane, does it trouble you at all that the incumbent provider who is obligated (in Virginia, anyway, New York is probably different) to provide service to ALL customers in its territory, would forego the investment to upgrade a substation because a few isolated groups can afford to self-supply in case of a power outage? Will this result in a two-tiered system of power supply, with fully reliable power only to the well-heeled? I worry about such selective outsourcing ultimately degrading service for those that cannot afford a microgrid.

  8. I just do not understand how you can call a better, more reliable and cheaper solution a problem of some sort of discrimination?
    As the article says … Marcus Garvey is a low income complex and Commonwealth Edison set aside funds to get the efficiencies started like lighting upgrades etc.
    The point is … expanding the substation for $1.2 billion was no longer required, a fact that saved everyone money. Microgrids won’t just be a few rich isolated groups but are beginning with essential services and will spread to include community solar with storage etc. Some are even talking of mini-grids within microgrids because of the reliability issue. Isolating from a central grid that puts everyone in the dark when one outage occurs is a reliability issue.
    Finally …it is also a matter of easy low cost loans to pay the upfront costs required in a way that reduces annual energy costs from day 1.

  9. Jane, you touch on something I’ve seen, where an electric utility concludes that meeting load growth with new utility-owned investment is not always the best choice even for the utility shareholder. Financing new ratebase may cost way more than the embedded cost of existing ratebase, causing rates to shoot up and meet severe customer and regulatory resistance. At some point, particularly when interest rates and the cost of equity are high and the investment needs are severe, you may confront a situation where new facilities rate basing is not profitable in the short run but merely dilutes shareholder returns — especially if the rate of return authorized by the regulator is not generous. In such a case, doing what you can to meet load growth by promoting energy savings or even selling off service territory may make more sense than building new rate-based facilities, such as utility-owned generation.

    In New York today, NYISO, like PJM, operates vigorous energy and capacity markets and so load growth does not require new ratebased generation; ConEd can buy new power requirements at wholesale, and I believe that’s what it is doing. In the case of load growth triggering grid facilities upgrades, the opportunities to avoid the growth are more localized — but they still exist, such as, through energy savings promotion, DSM, local distributed generation, and distribution-level utility-scale generation — and there’s no way NYISO can help offset those needs through its markets. ConEd has to meet its distribution load growth on its own. To do so, it can work on both the demand and supply sides of that equation.

    Current interest rates are low, so dilution probably isn’t ConEd’s current concern, although debt and equity must increase in tandem. I don’t know any particulars with ConEd these days but it must have decided that building more (or upgrading) distribution facilities to accommodate retail load growth should be avoided for other reasons. Is ConEd contributing its avoided cost to subsidize any of these customer-investment ventures? Whether that’s because of generic image-building, or a more enlightened view towards carbon emissions, or a more practical view of the impact of financing new substation equipment in Brooklyn under exhorbitantly expensive circumstances driving up retail rates, including for customers not directly benefitted, or a regulatory infatuation with demand abatement or customer microgrids even if economically unmerited, or a desire to divert corporate capital to other, more profitable uses than regulated retail ratebasing, or an attempt to curry political or regulatory favor for some unrelated reason, I can only speculate. I’ve seen ’em all. Expect you have, too.

    I will say, asserting that accommodating this forecast 69 MW load growth at Brownsville Sub through an upgrade to the grid there “would replicate the same type of energy system that failed dramatically across the city during Superstorm Sandy” strikes me as so much fluff. Failing to upgrade these low-lying facilities with a storm-hardened distribution system is a large part of the problem, isn’t it; how can that task be postponed? How is installing microgrids with low-efficiency fossil-fueled emergency generators for loss of grid backup going to reduce long-run, utility+customer, fossil fuel dependence and operating expenses overall, let alone total investment? The larger grid is more efficient for a reason: the diversity of resources and demands across a wide region provides high efficiencies and high reliability at lower cost. Distribution facilities are a small part of that cost; and in any case, the distribution system should be hardened against flooding for the benefit of all customers, not just a few. I’m all for customers wanting to enhance normal reliability with their own generators and batteries to be allowed to do so, but I am utterly unconvinced that doing so will save them money — unless the retail grid-power rates they displace are artificially higher than they should be due to regulatory-imposed externalities and cross-subsidies imposed on the utility — and in that case, wouldn’t the microgrids’ exemption from those be a huge subsidy in itself? Amazon proposes to build half its new east coast HQ right in the middle of this Brooklyn-Queens neighborhood at Long Island City; shouldn’t this new customer complex be supplied by a hardened ConEd distribution system rather than be forced to fend for itself during inclement weather? Won’t this development alone make current forecasts of load growth around Brownsville Sub (let alone, any plans for dealing with it) entirely OBE?

    I agree with Rowinguy, the circumstance here, where needed distribution grid improvements would be postponed due to load growth abatement by a few customers, would also be quite unfair to all the other customers who would have benefitted from the needed reliability improvements to the distribution grid but did NOT invest in all that microgrid/backup power supply and batteries stuff. This would be, in my opinion, unlawful discrimination in quality of service. ConEd should spend the $1.2 billion for the new substation (I’ll bet that figure includes a lot of storm-water resistance and other hardening of existing facilities in addition to simply increasing the available power supply capability) — rather than contributing to the cost of a few customers isolating themselves from grid reliability problems. As Rowinguy implies, that will only “result in a two-tiered system of power supply, with fully reliable power only to the well-heeled.”

  10. Where to begin? …

    First of all you cannot directly compare build choices between NY and VA because NY has moved away from monopoly regulations with REV..

    Second … “ConEd can buy new power requirements at wholesale,”

    Yes ConEd is buying power wholesale because they are in the process of restructuring the entire system and will tell you that having the wholesale market is allowing the restructure. ConEd can work with the supply and demand side because of the REV rules changes.
    It does sound like ConEd contributed to the microgrid build as they asked the entire area connected to that substation to come up with ways to reduce demand. This was just one of the responses and is serving as a prototype.

    “unfair to all the other customers who would have benefitted from the needed reliability improvements to the distribution grid but did NOT invest in all that microgrid/backup power supply and batteries stuff”

    Nobody has said anything about needed reliability improvements to the grid not being taken care of. The point I was trying to make is that microgrids can isolate from the central grid and keep operating when another part of the grid goes down. That gives them increased reliability. Many micro0grids are bring constructed for hospitals in storm prone areas and the DOD is islanding all their bases for security reasons, 70 some are actually in harms way from climate change.

    “ConEd should spend the $1.2 billion for the new substation (I’ll bet that figure includes a lot of storm-water resistance and other hardening of existing facilities in addition to simply increasing the available power supply capability) — rather than contributing to the cost of a few customers isolating themselves from grid reliability problems.”

    Again … the added reliabililty/resiliance of the microgrid is an extra benefit.
    Noone is losing out because the housing development is taking care of their own increase in demand by generating renewable power and therefore not drawing the increase from the central grid.

    By not spending the $1.2 billion the rate base did not have to be raised and the other customers did not see higher bills. ConEd solicited projects from anyone in the substation area. There is a natural gas fuel cell and a battery system attached to the solar system, not fossil fueled generators, allowing islanding for 5 days should a storm disrupt the central grid. That is the added benefit of the microgrid structure.

    So, I completely disagree with your analysis as wrong on finance choices because the regs are very different under REV, and wrong about demand and the ability to reduce central generation. It is a sound way forward, ..,. and wrong on the idea of any discrimination because the only issue that needed actual fixing was capacity, not hardening and rebuilding the substation. Thi9s was a ConEd solicited fix.

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