What Does Dominion Lose When Customers Leave?

With a competitive service provider, you pay it and not the utility for generation, transmission and fuel – the elements of electricity supply service.

When you use a competitive service provider (CSP) instead of the monopoly electricity company, what does the monopoly provider stop collecting?  Just what part of the electric bill are big customers such as Costco and Kroger and Walmart seeking to avoid by leaving Dominion Energy Virginia?

The answer is most of it, everything covered under the bill heading “Electricity Supply Service” on the sample bill illustrated above.  With a CSP, customers would stop paying Dominion for generation, transmission and fuel.  If future legislation makes retail choice the rule in Virginia, customers could leave the utility and pay a CSP for their energy and the cost to make or buy it and get it to Virginia’s local grid. 

The State Corporation Commission is still considering the most recent dispute on this front.  It heard oral arguments August 6 from Calpine Energy Solutions LLC and Direct Energy Business LLC on their motion to force Dominion to transfer customers who have signed up for their 100 percent renewable power, customers Dominion has retained. The SCC has not acted on those motions.  It will hold a hearing August 20 on Dominion’s motion seeking a declaratory judgement that neither company is really offering 100 percent renewable power.  Watch this space for developments there.

In the meantime, what is the fight really about?  Money is one of the issues, of course.  Defenders of the monopoly, and Dominion is gearing up for a major fight to defend it, argue that massive departures from the monopoly leave those customers who remain with higher costs under that electricity supply service heading.  That argument has worked at the SCC in several cases so far.

As you can see, generation is the big cost avoided on the bill.  That’s your share of the capital, debt and equity costs of Dominion’s fleet of power plants, as approved by the SCC.  Traditionally that has been covered in the base rates, but since 2007 most new projects have created new rate adjustment clauses (RACs or “riders”) which are collected separately.

Within generation: Rider S is the Virginia City Hybrid Energy Center, Rider R is the Bear Garden Generating Station, Rider B pays for various biomass conversions, Rider W is the Warren County Power Station, Rider BW is Brunswick County Power Station and Rider GV is Greensville County Power Station.  Some of the new solar plant capital costs are recovered with Rider US-2 and another one, US-3, is coming.

Take service from a CSP and pay none of that, although what you do pay certainly may still be substantial (and some power could come from those plants after all, through the regional transmission organization PJM Interconnect LLC.)

The transmission charges you begin to avoid involve the lines connecting that flock of power plants to the grid, all those larger power lines zig zagging the countryside, including the Rider T1 that has been the subject of some controversial cases reported here on Bacon’s Rebellion.  Again, with a CSP another set of similar costs is baked into your bill, but you stop paying Dominion for that.

The final big category under electricity supply service is the fuel charge, also known as Rider A.  That rider predates the 2007 legislation that created all the other riders and is a simple pass through charge for all the coal, natural gas, enriched uranium and other annual fuel costs plus the cost of any power purchased through PJM or from an independent generator.

There is no profit for the utility in the fuel Rider A, but both generation and transmission projects use shareholder equity as financing and thus are allowed a profit or return on that equity (ROE.) A CSP makes a profit, too, but Dominion stops profiting off those customers.

The main things left are taxes (good luck avoiding those) and distribution, the system of substations, transformers and smaller wires that link to all the home and business connections.  The CSP does not (could not) seek to duplicate that, and its customers continue to pay Dominion for that service.  Some consider that the only natural monopoly.

So because CSP customers continue to pay their distribution costs to Dominion, they pay some of the other riders which have generated controversy and Bacon’s Rebellion reports:  Rider U, which covers the strategic underground project for smaller tap lines and Riders C1A, C2A and C3A, which cover various demand management and energy efficiency programs. (Some large industrial customers served directly by transmission voltage may avoid all that, too.)

If you are counting, 14 individual rate adjustment clause riders have been listed, ten of which can be avoided with a CSP.  For the full list and how they are categorized, open this. Rider E for the coal ash costs will be number 15.

To figure out what each of them is costing you, look here and open up each one, and Schedule 1 is the residential price.  For example, Rider S, the Virginia City coal plant, is adding about $4.05 cents on a 1,000-kilowatt hour monthly bill and the Greensville natural gas plant $2.29.

Would those individual costs go up to remaining customers if tens of thousands of Dominion customers suddenly went elsewhere?  That’s a fair question, and a crucial one as the pressure to end the monopoly continues to grow.  Any transition to a pure retail choice approach is going to be tricky, with only fools rushing in.

Money isn’t the only issue, but many of the large business customers seeking to leave are indeed looking for (and finding) CSPs that offer a lower cost.  The other goal customers are seeking, 100 percent renewable energy, is not always substantially cheaper but it can be.  That bears further examination in another post.

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20 responses to “What Does Dominion Lose When Customers Leave?

  1. Nice run down … It is my understanding that the cost factor also includes the avoidance of an escalating fuel cost because the PPA’s are signed for a 20 year period. That makes future budgets secure.
    AND … I believe that that 100% rule was just a catch for Dominion to block third party ownership. Do those corporations all really want to totally leave the grid? The 100% rule makes on-site generation require fully leaving the grid which could be risky even though storage is now becoming cost competitive

  2. I realize this is not exactly relevant but the NYT has a story about Wells Fargo charging customers hefty overdraft fees after shutting down their accounts:

    https://www.nytimes.com/2019/08/16/business/wells-fargo-overdraft-fees.html?action=click&module=Top%20Stories&pgtype=Homepage

  3. Good blog post – completely devoid of terms like “virtue signaling” and other partisan garbage!

    My FIRST impression is that Dominion should get full compensation for any/all of the grid it maintains that other CSP use – no question.

    My SECOND is WHY DOminion is allowed to charge for specific plants as opposed to what the CSP as well as providers to PJM do – which is manage all that infrastructure within the confines of their company to then offer to customers and PJM a bottom-line price for their electricity.

    My THIRD thought is what 24/7 “renewable” power actually means. If you buy 24 hours worth of renewable power (as opposed to buying ONLY daylight hours of renewable power) – you are paying a de-facto offset in that they have to build enough additional solar to generate that 24/7 dollop of power AND when they do that – and that 24/7 dollop of power is generated during daylight hours – it IS in fact, reducing the amount of power generation from fossil fuel/nukes.

    Think about it this way. If we had enough renewable deployed such that it was more than enough to satisfy 100% of daytime power needs – then the amount of fossil fuel/nuke power needed would be only for the night and cloudy weather – essentially cutting in half the amount of fossil fuels needed to power the grid 24/7.

    That’s a NET reduction in the burning of fossil fuels – that is displaced by the use of renewable.

    It’s done by offsetting – essentially similar to the way that pumped-storage works – they pump the water up at night when demand is lower and generate during day when more power is needed. It actually would not work if you did not have excess power available at night. So with solar, it’s the reverse, you generate MORE solar during the day to save using fossil fuels during the day – then you use fossil fuels at night – and there actually is an overall reduction in the burning of fossil fuels so paying for “green” power is real – you’re essentially buying renewables to burn to displace burning fossil fuels.

    You have to look at this in a 24/7 perspective not on an hourly basis.

    • There is Larry, virtue signaling again. In process, poor Larry tries mightily to dictate other people’s words, what they can and can’t say, and how, and smears their intelligence too.

  4. As I said, Larry, worthy of a discussion all on its own. APCo now has an approved “100 percent renewable” tariff, Dominion is pushing for one (again), and one CSP (Collegiate) has been operating for a while in both territories. Annually, monthly, hourly balancing — all part of the debate. No company will fully leave the grid, Jane, that’s way too much risk for them.

    • That was basically a rhetorical question … but I investigated supplying a company that considered building large solar generation. Their large demand was during the day but the only way we could have done it way back then was by leaving Dominion and working with PJM. Looking back I am not sure how this fits in with current rules. It was after the state ‘reregulated’ and it was a large demand.

  5. We need an audit to understand, but I provide a preliminary one:

    The generation/fuel cost there, in my mind, is massive compared to how much it would actually cost Dominion to make power from natural gas. Admittedly we also have nuclear, coal etc. But it is a helluva big charge to consumers, admittedly also includes a huge profit margin, but I repeat myself.

    Fast forward to expensive offshore wind, which seems to be coming soon if East Coast elected officials have any say, and if we paid the same cost structure, the cost would be outta sight.

    What we need to tell consumers about offshore wind, is that renewables energy is already far cheaper than fossil fuel and getting exponentially cheaper every day. Therefore it will actually be free-of-charge to construct offshore wind, and it will create tens of thousands of jobs.

    Think of it: a massive new industry , free of charge. What’s not to like?
    But in order to keep our electric bills under control, we will need taxpayer dollars to help fund the offshore wind and we will need to get out of paying big profit margins to Dominion on that activity. In this new way, we could do offshore wind, with a little smoke and mirrors.

    • Free of charge to construct and maintain a forest of wind turbines 20 miles out into the ocean? I’m sorry, you been out in Colorado smoking weed with DJ? it may or may not be a cost effective investment (TBD in a future case) but nobody thinks it will be free.

  6. Good post — but let me correct one minor error:. A customer served by a CSP will nonetheless pay Dominion’s transmission charge. That charge, like the distribution charge, is applied to all retail customers within the Dominion Zone of PJM (which zone is roughly the area in which Virginia Power serves retail customers plus wholesale co-ops and municipals). A wholesale customer in the Dominion Zone pays Dominion’s transmission charge in bulk but levies its own distribution charge.

    • Hmmm. I ran this by somebody in the business, who said the CSP replaces Dom for everything under electricity supply service….and I said that a CSP customer would be paying for that, but paying the CSP (which is a load serving entity…) This may be a distinction without a difference….perhaps I could have been clearer.

      • I believe AC is correct. A CSP operating in the Dominion service area would be a “DOM Zone” transmission customer of Dominion and would be billed for such service, just as the electric cooperatives and municipalities that make use of the Dominion transmission system are billed. The end use customer’s check would still be written to its CSP, but some of that bill would be turned over to Dominion.

  7. Thanks for this nice summary. I keep learning from your posts. Now, for some more learning:
    1. Where, and what, is the Virginia City Hybrid Energy Center? (I thought Virginia City was in Nevada.)
    2. Where is the Bear Garden Generating Station?
    3. You say that the fuel charge includes the cost of energy purchased through PJM. Doesn’t Dominion sell energy to PJM? If so, does that mean that we pay for it twice—when it is generated and then when it is purchased from PJM?

    • Bear Garden, a gas plant, is dead west of Richmond on Rt 15 to take advantage of the existing pipeline. Virginia City is deep SW Virginia, so far from Dom territory that it suffers significant line loss, but when approved as one of the last coal plants in the US it won huge political brownie points with SW Virginia legislators. No, I don’t see a double payment, just Dom getting paid either way. Which is fine. That’s the model some what, those plants all become basically merchant generators.

    • The VCHEC is near St. Paul, Virginia, in Wise County

      The fuel factor charge recovers all the costs of fuels that Dominion buys to run its generators AND when it is supplying customers with power bought from the grid, the cost of that power. It is a pass through and not a profit item for the utility.

  8. We seem to want to do things the hard way in Virginia. Here are our current choices:

    1. Keep the Current System.
    This gives utility customers few choices. They must continue to pay higher prices as the utility uses the GA to stuff its ratebase with unnecessary, expensive projects. The only choices for lowering costs are energy efficiency (paid for by the customer, if Dominion does it, it is in the ratebase and costs much more), or some self-generation (but solar net-metering is currently capped).

    2. CSPs (maybe)
    Customer pays less for energy with the CSP, or why switch? Wires are paid for by customer or CSP (and repaid by customer). No fuel costs for utility so none repaid by customer.

    That leaves the legacy costs in the ratebase that will be spread over fewer customers. This is the downward spiral that all utilities fear and Dominion is doing everything they can to keep from happening.

    What we have avoided in Virginia, but 40% of other states have embraced is choice #3.

    3. Revised regulatory scheme.

    There are many different schemes that have been adopted. I’m sure we could find a good match for Virginia. They all deal with a few basic issues:

    a. Utilities are no longer incentivized to build new projects just to increase profits. Generation must pay its own way in the wholesale market.

    b. Independent Power Producers and energy service companies are allowed to compete in the energy system to provide more choices and lower costs.

    c. The existing utilities provide the platform (the grid) over which the energy and services are transacted.

    New York is the clearest example of this. Utilities provide transactional services (billing, etc.) for all of the energy and service transactions that occur over their wires. This creates a new source of profit for utilities and an ease for commerce for all participants.

    Utilities can compete in these market too, but on an equal footing with others. There are no guaranteed profits by putting projects in the ratebase.

    d. Remaining legacy costs are spread over the utility’s full customer base. These new schemes avoid the flight of customers which would otherwise leave fewer customers to pay the legacy costs. But all customers now have more choices, which should result in lower costs.

    The utilities have a profitable path forward, but can no longer impose their will and higher costs on captive customers.

    • Whether we want it or not, the Virginia regulation scheme is unique; no other regulated state insulates so much of its utilities’ costs in these Rider silos and effectively guarantees full cost recovery plus profits and incentives. There are, as you note, many other schemes that could be tried, including traditional rate-base, rate-of-return regulation absent the rate adjustment clauses and statutorily mandated new construction of plant, transmission and generation projects.

      However, I don’t know that I’d recommend New York’s model either. According to the Bureau of Labor Statistics:

      “The 21.0 cents per kWh New York households paid for electricity in May 2018 was 54 percent more than the national average of 13.6 cents per kWh. Last May, electricity prices were 47 percent higher in New York compared to the nation. In the past five years, electricity charges for local area consumers in May were 33 to 54 percent more than the national average. ”

      https://www.bls.gov/regions/new-york-new-jersey/news-release/2018/averageenergyprices_newyorkarea_20180613.htm

  9. TBill, you say:

    “Think of it: a massive new industry , free of charge. What’s not to like?
    But in order to keep our electric bills under control, we will need taxpayer dollars to help fund the offshore wind and we will need to get out of paying big profit margins to Dominion on that activity. In this new way, we could do offshore wind, with a little smoke and mirrors.”

    Let me clarify a few things. The offshore wind development in all other east coast states appears to be proceeding with bids provided by developers for wind energy to be provided at a fixed cost over the life of the project. This will probably be done with Power Purchase Agreements direct with customers or with utilities, each getting some percentage of the output.

    The developers will be at risk for project costs and for meeting the target price at a profit. Taxpayer funds are not involved. Although a few states have funded some onshore facilities to encourage business development.

    This is quite different from how we are approaching offshore wind in Virginia, as you point out. We have chosen, or the GA has chosen for us, to let the ratepayers be at risk for cost overruns and for paying a guaranteed profit to the utility (about twice the project cost). As a result, the energy generated will likely cost a great deal more compared to the wind energy generated in other states.

    We don’t pay twice for the energy. Dominion gets paid for the energy it generates and pays for the energy it uses, and we pay the marked up retail price.

    But Dominion does get a double dip. It receives full reimbursement for all expenses in building and operating the wind facility, plus its cost of financing, plus a profit that is about twice the cost to build the project. If they sell more energy from the wind project than its customers use, Dominion keeps 25% of those profits. The remainder offsets fuel charges that would otherwise be billed to customers.

    You can see how this system incentivizes Dominion to overbuild. Every new project uses the ratepayers’ money and adds to profit. Excess generation provides more profit using facilities that somebody else paid for (us).

  10. Great post, Steve!

    We have so many add-on’s because that’s the way our regulatory system was redesigned by Dominion. Instead of one huge rate case, there are umpteen (determined by the companies) that independently deal with expenses/issues. It’s hard time-wise and financially (attorneys are required to participate) for consumers to keep up with all the cases – much less actively participate. Each standalone item looks “reasonable” and once you add them up, there’s no way to reduce the number. Operates just as it was designed to operate.

  11. Dick, I’ll take a crack at your question #3. “You say that the fuel charge includes the cost of energy purchased through PJM. Doesn’t Dominion sell energy to PJM? If so, does that mean that we pay for it twice—when it is generated and then when it is purchased from PJM?”

    The problem is, there are a lot of moving parts. PJM is the independent system operator (ISO) and runs a wholesale energy market and a wholesale capacity market and coordinates the transmission planning and market entry of new generators in its region, under a set of orders from the Federal Energy Regulatory Commission (FERC) motivated, in large part, by 1) the success of the deregulatory movement of the 1980s in transitioning to market rates for e.g. airlines and cell phones and natural gas, and 2) pressure from the States for ‘breaking up the monopoly power of the electric utilities’ (=> retail access), and 3) pressure from independent generation owners who chafed at selling to grids run by their competitors and at negotiated rather than market rates. FERC established these ISOs and their wholesale markets and, with State commission support in most areas, required the retail utilities to join these ISOs and participate in their markets. This was all happening around the mid 90s and largely under the radar except for implementing legislation at the State level (which is where Virginia’s remaining retail access rules come from). PJM was originally a “power pool” in the states of PA, NJ and MD, assembled back in the 1920s to coordinate the supply of electricity to the Pennsy Railroad’s electrified Northeast Corridor; but due to this FERC pressure and the failure of other attempts to organize smaller ISOs, PJM, which operates out of Valley Forge PA, now embraces most of the utilities from the mid-Atlantic to Chicago (there is also a smaller ISO, the Midwest ISO or MISO, operating out of Indianapolis).

    OK, how does PJM work? Every entity buying at wholesale to serve retail load (“load serving entities” or LSEs) MUST provide PJM with “capacity” (conferring on PJM the contractual right to call on, or “dispatch,” the listed generators to run, barring mechanical failure or other force majeure) in an amount equal to the LSE’s forecast annual peak load plus its share of capacity reserves (~13%). The LSE must commit to buy 100% of its energy from the ISO’s energy market (the rate is set by the market according to rules regulated by FERC which has federal jurisdiction over wholesale electric transactions), and the LSE MAY buy up to 100% of its capacity from the ISO’s aauction-based capacity market, after 1) owned generation and 2) bilateral deals with 3d parties, are taken into account. These LSEs can be traditional franchised utilities with exclusive retail service territories (like Dominion, or the co-ops), or the “competitive service providers” (CSPs) you hear about, all of which buy in the wholesale energy market and pass the energy along at a markup regulated by the state commissions (who regulate all retail sales). (Yes, CSPs have to file their contracts with customers with the VSCC also.) PJM’s part of the deal is 1) to “dispatch” all the generation in the region on a least-cost basis, lowest cost first, and pay those units that run on the basis of the marginal energy price as it varies through the day; 2) to sound the alarm if there’s not enough transmission to avoid bottlenecks or enough capacity in the construction pipeline to supply all the electricity needed (this has not proved to be a problem — independent generators have found it profitable to sell to PJM); and 3) to deliver all the electricity required by every LSE at each of the LSE’s transmission delivery points (LSEs operate their own distribution systems to take it from there).

    Meanwhile, all the generators (including those owned by utilities) submit a daily bid to PJM for what minimum energy rate they are willing to run for; this set of bids is what PJM uses to do its economic dispatch. While the generator can bid low (and thus assure that it will be dispatched, even at an operating loss) or high (assuring that it won’t run) it turns out a bid close to the generator’s marginal cost to operate (fuel, labor, maintenance) is optimal to receive the most sales revenue from economic dispatch. Remember, each generator bids its marginal cost to run, but PJM pays out the marginal cost (“running rate”) of the pool at the time it runs; therefore, if the running rate is high because demand is high and all the high cost units in PJM are being dispatched, every generator gets paid that high running rate, which rewards the low cost generators with extra revenue above their marginal cost to run. That, plus what they can make from bilateral capacity sales or in the PJM capacity, is how they pay their investors back plus a profit.

    That’s a mouthful, but here’s how it works for Dominion: Dominion wears multiple hats here and has largely separated these into separate subsidiaries to help with the accounting and ratemaking. Dominion’s LSE is Virginia Electric and Power Co. (Vepco) dba Dominion Energy. Dominion’s generation is owned by Dominion Generation. Dominion’s transmission is owned by, I believe, a separate transmission subsidiary (not sure what name) and operated/maintained by Dominion under PJM direction. Dominion’s distribution system and customer service assets (meters, service drops) are owned and operated/maintained by Vepco. Dominion’s generators run when/if PJM dispatches them and then they sell into the PJM energy market. Simultaneously or not, Vepco buys all its requirements electricity for its retail loads at multiple delivery points from PJM.

    A sale into the wholesale energy market takes place essentially at the same rate as a simultaneous purchase, so there is no double counting or PJM profit (PJM in fact is a non-profit corp.). Due to Dominion’s generation mix, however, it is rarely selling exactly the same amount into PJM as PJM is delivering to Vepco; you can think of this mismatch as a net transaction between Vepco and the energy market figured out after the fact when PJM computes its bills to LSEs and payments to generators at the end of the month. Actually, though, Dominion does not sell any energy to Vepco even indirectly. THEN, there’s that separate capacity market. PJM doesn’t bill for bilateral capacity purchases by LSEs from generators — thus Dominion Generation can charge Vepco anything it wants to for capacity from all its generators — subject of course to VSCC regulation of the reasonableness of the transaction (as a contract between affiliates and, again, as a cost component of retail rates). (The VSCC chooses to let Vepco recover these costs as fixed charges through RACs or base rates rather than as contract expenses.) Dominion Generation could, if it wished, sell its capacity bilaterally to others or participate in the PJM capacity auction with all or a portion of its generation (it does not do either with its units dedicated to Vepco — but Dominion does own generation elsewhere and sells that generation according to the rules in those markets).

    Confusing? We should make a road-trip up to PJM’s operating center sometime and see it in person.

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