NRDC Blasts Dominion’s $13 Billion Cost Projection

With least cost planning, says the NRDC, Virginia would continue to sufficiently reduce carbon emissions, in absence of Dominion’s IRP proposal.

With least cost planning, says the NRDC, Virginia would continue to sufficiently reduce carbon emissions, in absence of Dominion’s IRP proposal.

by James A. Bacon

The 15-year planning document filed by Dominion Virginia Power last week vastly overstates the cost of complying with the Clean Power Plan and is chock-full of errors, flaws and misjudgments, charged Walton Shepherd, staff attorney for the National Resources Defense Council (NRDC) and a member of a committee of stakeholders advising the McAuliffe administration on how to comply with the plan, should it meet federal court approval.

“Dominion’s IRP … outlines a gargantuan, $13 billion energy plan to reduce total carbon pollution that asks its customers to pay for a Ferrari, when it already has a finely tuned car that can safely — and more affordably — get everyone to the store and back in time for dinner,” wrote Shepherd.

In a blog NRDC post yesterday, Shepherd cited three major flaws in Dominion’s analysis.

  1. Dominion’s $12.8 billion dollar building plan assumes that it will have to replace electricity generated by every single one of its coal-fired plants. That’s not true, he said. As a result of previous initiatives undertaken before the announcement of the Clean Power Plan, Virginia “has already achieved so much of its compliance obligation that it would likely make the carbon reductions required by the Clean Power Plan even in absence of the federal regulations.”
  2. Dominion disregards the existence of the interstate electricity grid — the company is part of the PJM regional transmission organization — which allows it to tap into wholesale electricity markets. “That national grid, which of course includes all of Virginia in its continent-wide footprint, is precisely why Dominion doesn’t need to build new plants: transporting cheaper and cleaner electricity from elsewhere was the entire point of building out our vast and sophisticated transmission network.”
  3. Dominion’s plan overlooks the obligation by Virginia regulators to find the least-cost measure to meet customer needs. “Robust analysis of the CPP shows the compliance costs for the entire region (of VA, WV, PA, OH, and NJ) to reduce carbon pollution from existing and future power plants could be less than one-fifth of Dominion’s cost of $13 billion, which is a price tag for Virginians to pay alone.”

Bacon’s bottom line. The first point requires some explanation for readers not intimately familiar with this debate: That $13 billion price tag is Dominion’s estimate for what it says is the most expensive of the four Clean Power Plan compliance strategies (so-called Plan E) on the table — the plan preferred by Shepherd and the NRDC. It would impose a mass-based cap on carbon dioxide emissions from Virginia’s fossil fuel-fired generating fleet, including existing and new facilities — 27.43 million short tons of CO2 in 2030 and beyond.

To achieve that goal, Dominion maintains that it would have to go beyond the currently planned shutdown of oil-fired Unit 3 at Yorktown Power Station, coal-fired Units 3 and 4 at Chesterfield Power Station, and both coal-fired units at Mecklenburg Power Station. Dominion’s econometric modeling suggests that Plan E would require the shut-down of Units 5 and 6 at Chesterfield, both units at Clover Power Station by 2022, and the Virginia Hybrid Energy Center by 2029.

Shepherd is contesting that assertion. He is saying that simply following existing policy, which shuts down coal-fired units to meet the toxic-emission standards issued earlier this decade, got Virginia below the mass-based level at temporarily in 2012, and that it would take only modest effort to keep it below that level through 2030. (See the chart above.) This appears to be a fundamental disagreement in analysis with Dominion.

On the second point: Dominion’s 2016 IRP does indeed glide over discussion of purchasing power on the wholesale markets. One of the advantages to participating in a regional electric grid is that it is easier to balance electric-generating sources, especially variable sources like wind and solar, over a larger geographic area. PJM has said that the system should be able to accommodate as much as 30% renewable power without jeopardizing grid reliability.

However, Shepherd’s understanding of how the PJM grid works differs from mine. It is not a vehicle that Dominion can tap to import vast supplies of renewable energy. Some renewable energy, yes, but not limitless amounts. First, there are transmission constraints. There is a limited number of transmission lines with a finite amount of capacity, which cannot be exceeded without incurring significant congestion charges and creating reliability issues. Second, Dominion cannot simply be an electricity taker. It has to be able to feed power into the regional grid as well in order to help maintain the regional balance. Perhaps Dominion could purchase more electricity off the regional grid, but it’s not clear how much more.

On the third point: Dominion says compliance will cost $12.8 billion, NRDC says it will cost one-fifth that amount for Virginia and nearby states. Dominion has its econometric model; NRDC has its own econometric model. Without knowing the inputs and constructions of each model, it is impossible for disinterested citizens to know which is a more accurate representation of reality.

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27 responses to “NRDC Blasts Dominion’s $13 Billion Cost Projection

  1. I’m trying to understand the concept of an IRP for any utility that is also part of PJM.

    and I can see some potential for mischief… on the part of the State Utility along the lines of what NRDC is talking about.

    and the concept of what “dispatchable” means for in-state only verses in a PJM scenario.

    For instance a baseload Nuke for Va only probably is in excess of what Va would need – unless all coal plants were closed … and yet any “excess” Nuke baseload would certainly be available to PJM to dispatch …

    similarly -any state that has wind/solar excess to it’s needs could certainly sell it via PJM to other utilities.

    Both of those issues would seem to b far more complex planning-wise with respect to all other utilities in PJM…

    so you’d have the capital costs of the NUKE – but then could you sell that power to PJM for more than you could charge Virginia ratepayers for – or for that matter – vice versa?

    hard to see how any bureaucrat at the SCC could figure out… and in turn put numbers for VDP to abide by…

    Makes me wonder if the IRP is really a useful document in a world where DVP is part of PJM.

    • “Makes me wonder if the IRP is really a useful document in a world where DVP is part of PJM.” Precisely!

      The IRP in theory is a study of how the utility forecasts it is going to supply electricity to customers. That includes generation, transmission, and distribution, which Dominion is used to supplying as a vertically-integrated utility, on a standalone basis, semi-isolated from its neighbors except in an emergency.

      Vertically integrated supply is a totally obsolete concept in today’s world. Dominion isn’t even responsible for transmission planning any longer (although it still owns its share of the wires themselves). Dominion doesn’t dispatch its generation; rather, all the generation in PJM (from IL to NC) is dispatched by PJM on a least-cost basis, and Dominion shares in the savings for all. Dominion has to have enough generation, but it can be located anywhere in PJM, and it can be Dominion’s own generation, or bought under long-term contract, or simply supplied from the PJM spot market.

      Dominion has done very little to admit these changed circumstances or to take advantage of this resource flexibility. On the contrary, its IRP assumes it must own and build its new generation resources. Why? There is nothing about reliability that requires this; nothing about cost savings either. It’s all about control, and about maximizing profit from the return on investment, and about “that’s the way we’ve always done things in Virginia.” It’s also what the GA expects, so a report to the GA based on that traditional vertically-integrated model sells well. The SCC has a better understanding, but why rock the boat? So the traditional IRP gets submitted, year after year.

      In the Remington certificate-rejection order, the SCC warned Dominion that it would insist that Dominion compare all future proposals to build generation at ratepayer expense to other options, specifically to the option of buying power from others — including from customer-owned DG. I hope the SCC carries through with that warning. That’s why the SCC may have a lot to say, this December, in its report to the GA forwarding Dominion’s IRP, not only about NA3 but about renewables generation and DG and all that stuff criticized by the NRDC. Stay tuned!

  2. Jim: re “Shepherd’s understanding of how the PJM grid works differs from mine,” I think yours is much closer to reality. The PJM grid is composed of transmission lines that operate reasonably close to their capacity when the maximum flows occur. They can accommodate more, only if the flows run counter to (offsetting) what’s loading them already, or if the flows occur at offpeak times (offpeak, for transmission purposes, is not the same as offpeak for generation purposes, as the PJM load forecasts make clear). The regional transmission connections outside PJM, particularly in the western and southwestern US, are particularly weak, and stressed already.

    Yes, Dominion “has to be able to feed power into the regional grid . . . in order to help maintain the regional balance.” But it can do so using generation located anywhere in PJM, or, by special arrangement, even outside PJM. NRDC is correct, Dominion could buy wind power from Indiana or northwestern Ohio, where it is plentiful. Dominion could buy solar power from North Carolina and further south, where it is more plentiful than around Virginia. Dominion cannot bring an unlimited supply of cheap power from gas turbines in Oklahoma because the transmission grid isn’t strong enough to support it, and because of stability issues (you must run enough generation near your loads to maintain the local stability of the grid), but some degree of imports is the only way to use the least cost resources out there to best advantage for everyone.

    I think you have too localized a perspective on Dominion’s “place” on the grid. You say, “Perhaps Dominion could purchase more electricity off the regional grid.” There is no such thing as ‘electricity off the regional grid.’ Everything Dominion generates is dispatched and delivered by PJM operators through the grid — even when the generator is located within Dominion’s service territory. Everything Dominion takes from the grid for its customers is delivered by PJM to Dominion’s distribution system. That is why it makes no difference whatsoever whether Dominion owns, or buys from, a generator located in Surry County, VA or a generator located in NC or a generator located in Ohio. Yes, there must be enough generation located within VA that the maximum quantity of imports to each subregion required can be handled by the available transmission; but that generation does not have to be Dominion’s generation.

    There are plenty of independent generation owners out there (whether conventional or renewables-fueled), but it’s striking how few of them own any generation in Virginia. In large part, that’s because Dominion and other Virginia utilities have never sold any. And Dominion certainly has options to build or buy generatino from outside the State, although they seem determined to avoid those options. They have limited their choices unduly to those close to home.

  3. A question for Acbar or others who know. Look at this map:

    and tell me if all of these utilities are part of PJM and can buy, generate and sell power to/from PJM.

    • Every electric utility in Virginia is a member of PJM except Powell Valley Electric Cooperative, which is wholly supplied by the Tennessee Valley Authority. However, in the entire state only DVP owns any substantial generation in Virginia. Apco has a few hundred MW and ODEC (the generating arm of the coops) owns parts of 2 DVP stations. Contrary to what Acbar stated above, there are several independent power plants in Virginia. These too must bid their supply into PJM every day.

      PJM does not, contrary to popular belief, dispatch generation on a “least-cost” basis. PJM dispatches on a “least-bid” basis and adds increasingly higher bids to the generation stack dispatched each day until the market has cleared. Every winning bidder is then paid the market-clearing price, irrespective of its actual costs or its actual bid.

      • You are right, Rowinguy, there are independents in VA, but there aren’t many of them compared to surrounding states. I haven’t looked into why but it seems to be because Dominion/Apco/AEP have retained ownership of all their generation whereas several utility owners in Maryland, PA etc. sold off generation to independents in the ’90s. Whether VA has attracted more new construction of independent generation than typical, can’t say. And yes, least bid is correct. Utilities don’t have to bid at cost, and independents don’t even publish their costs.

        • It’s odd, Acbar, your mug shot in glorious county colors shows up on my desk top computer, but not on my I-Pad. There, I got only a little white head and shoulders cut out framed by gray – nary a hat, rugged mug, or ray of sunshine. What’s happening here mobile-wise, a limited hang-out?

        • In Maryland, the legislature mandated that the power companies divest their generating units. Most, if not all, was not sold to independent 3rd parties, but to affiliates of the formerly integrated utilities. Baltimore Gas & Electric’s generation, for instance, went to another subsidiary of Constellation, the parent company of BG&E.

          The Virginia General Assembly enacted slightly different “deregulatory” legislation, mandating functional divestiture, but not legal divestiture. The utilities were free to propose legal divestiture to the SCC, which was tasked to review the “functional separation plans” of the then five investor-owned utilities. Potomac Edison and Delmarva owned no generation in Virginia and had already legally divested their units in Maryland. They were allowed to legally separate their generation, transmission and distribution units of their companies, with long=term power supply arrangements as part of the bargain. Old Dominion Power, the Virginia arm of Kentucky Utilities, likewise owned no generation in Virginia, but Kentucky was uninterested in deregulation and hence, ODP’s proposal to functionally divest, was approved.

          Both DVP and Apco initially proposed the sale of their in-state generation to affiliates of DRI and AEP, their respective parent companies. While their cases were pending at the SCC, the situation in Maryland went into the toilet. BG&E raised retail rates by 72% in one year, as the power from the generating units it formerly owned was being dispatched at much higher wholesale prices due to the way the PJM market was then functioning (pre-fracking and the collapse of natural gas prices).

          The SCC denied DVP’s proposal to sell off its generating units to DRI in one of the most consequential cases in that agency’s history. Apco withdrew its legal separation proposal and instead chose to retain ownership of its generation, most of which is in West Virginia, another state that was uninterested in deregulation and would not have permitted such divestiture of those plants in any event.

          So, DVP retains legal ownership of its generating units, and its rates would have been regulated after the statutory “rate freeze” period ended in 2007. This led it to develop the so-called Electric Reregulation Act, with the separate rate riders to recover the costs, including profits, for constructing new generation in Virginia. The regulatory discretion of the SCC over ratemaking for DVP and Apco was significantly constricted by the legislature. You can speculate as to the reasons for this.

          I am not as familiar with the situation in Pennsylvania. But, I do believe that the utilities there divested most, if not all, their generating units to affiliates as well.

          Fortunately for PJM, fracking of natural gas within its “footprint” came along just in time to send wholesale prices down at about the same time that the economy collapsed in 2007. It is running the largest wholesale power market in the world, but it is not a wholly competitive market. There are bid and offer caps in place, and each generating unit must bid into the market every day, for instance. There are certain generating units scattered around the footprint that are so critical for system reliability that they have “must-run” status and are effectively not part of the “market” at all.

          But, that said, it’s the best-functioning such wholesale market we have now.

  4. and another map – that I think is PJM

    • Yes! Emphatically, yes. All those utilities in the first map, not only Dominion but also all those little cooperatives and municipals, are members of PJM. All of the coops are wholesale customers of other utilities, although some of them are also banded together in ODEC and through ODEC own some generation of their own.

      On the second map, the purple area is the “Dominion Zone” within PJM; the green is the AEP Zone, etc. Each zone includes all retail and wholesale customers served from that transmission owner’s facilities; each PJM Zone has a slightly different transmission rate (based on the transmission investment of the transmission owner in that Zone). As you can see, most ODEC members are located in the Dominion transmission zone. But throughout PJM, the principle of “network service” means that the utility buying the power it requires off the grid (to deliver to its retail customers) pays the same for whatever amount of power it takes from the grid regardless of where the power came from. It’s up to PJM, the ISO, not to Dominion, to decide how to operate all the generation within PJM to achieve the lowest cost dispatch of all the resources at any given moment across the entire PJM region.

  5. “Without knowing the inputs and constructions of each model, it is impossible for disinterested citizens to know which is a more accurate representation of reality.”

    Gonna jump on my soapbox right quick to harp on this, thank you for making that point. Open government, open data and data-driven, are some of the topics we are going to be hearing about for awhile in the near future. None of which are attainable without embracing them entirely. Different standards are going to continually bite us; industry leaders in every sector need to meet each other half away and agree on standards. They won’t, and its going to suck for all of us. Moreover, numbers, charts, stats, polls, etc., are pointless without reproducibility: this is really important around gov and spending. And actually to the point of your post I believe. Two sides with vastly different numbers, and we have no idea who is correct, and how they did it. All we know is we are paying for it. Think about that for a minute….it is ludicrous. No one would ever accept that in their personal life, it should not be acceptable in public life.

    I could go on: the 460 deal, midtown/downtown project, practically everything dom power does/wants to do, including pipeline (not just money, extractions and flows), the james river extension, etc.

    Thanks again for bringing this up. Transparency, accountability, and open government are for all citizens, no party, nor politician.

    • I agree with you, JAB, but the problem with Dominion’s IRP is not so much disclosure as the sheer intimidating complexity of it all. It’s a year’s worth of research by a large portion of a large organization captured in one document. Everything they do to summarize and explain it can easily come across as unhelpful, even obfuscation. And no doubt, if there’s something in there they don’t want the public to focus on, it’s easy to make it appear more complex than it really is, bury it in jargon, that sort of thing. So, open data is only as useful as the patience of those of us who try to read through it!

  6. how come the PJM service area for Virginia looks like the purpose Dominion map rather than the map showing all the different co-ops?

    If the co-ops want to install solar -can they do that and sell it to PJM for others in Va or the PJM service area to buy?

    can 3rd party generators set up shop in a non-Dominion Virginia area and sell power to PJM for other co-ops in Va to buy?

    • The PJM service area in Virginia includes a portion of three “transmission zones” which are defined by the geographic areas in which those three transmission owners either provide retail service or supply other providers of retail service (e.g., coops). Technically these are transmission zones, but it’s easier to define the Zone boundaries in terms of retail service territories connected to the transmission, because those are defined already by State regulators. There’s the Dominion Zone, the AEP Zone, and the APS Zone. In addition, there is a tiny piece of Virginia out west of Bristol which is not in PJM, but supplied by Kentucky Utilities which is in the grid operated by the Midwest ISO. The retail suppliers in that area are Old Dominion Power Co and Powell Valley Electric Coop, as your map shows.

      Aside from that area west of Bristol, any generation owner can connect to the PJM-operated grid and sell power to PJM. That includes the coops and it also includes retail customers: if you are simply a homeowner and have a rooftop solar array on your home and you generate more than you consume (or choose to sell it all to the grid rather than net-out), PJM will buy it, and the local distribution utility can be required to accommodate the transaction over its wires. That recent Supreme Court case that TomH was talking about had to do with whether the utility that sells you retail service can put a provision in its retail (State regulated) tariff that requires you the customer to sell any distributed generation (like DG solar) back to the utility, rather than to the grid operator (PJM). The Supreme Court said no, the sale of generation into the grid was a wholesale sale and therefore the States could not block it.

      And yes, if a coop or a homeowner or anyone else sells solar power to PJM, anyone else in PJM can buy it. In fact PJM has a separate wholesale market for renewables-generated power. If you contract with Dominion to buy renewables power, it probably comes from that market. Of course it’s just an accounting transaction because the flow of all the electrons on the grid is commingled.

      And yes, 3d party generators can locate anywhere in Virginia and, with the exception of that little piece of VA which is not in PJM, they can sell energy into the PJM energy market, and they can sell their capacity into the long range capacity market to any load-serving entity (LSE) in PJM, and any coop can buy it. “Any LSE” includes any utility selling at retail: that includes Dominion, and that includes all the cooperatives and municipal utilities that have retail customers.

  7. Thanks Acbar –

    so.. if all of that is true – then the Dominion IRP does not address those non-Dominion, other/co-op, independent generators market?

    In theory – someone other than Dominion could build a gas plant or huge solar array in Va and sell the power to PJM?

    • As to whether the Dominion IRP looks at these alternatives — it does, in a backhanded sort of way. The long range up front (‘installed’) costs it forecasts for its big units would be roughly the same whether it builds or it buys from an independent. On-going (O&M) costs would be roughly the same, for a given type and size of large generator, whether Dominion builds it or pays someone else to build and run it. But you don’t know until you sample the market whether you can issue a RFP and attract third-party proposals that beat your own projections. Or whether the market will attract sufficient development of independent generation just where you would like to have it without your doing anything but facilitating the connection to the transmission grid. And some kinds of generation and energy efficiency costs have no utility-owned comparables: what would it cost Dominion to obtain and sell to PJM significant amounts of: load reduction through customer energy efficiencies; curtailable load management; industrial cogeneration and municipal electricity-from-trash; and of course, distributed renewables generation by customers? This IRP looks almost entirely at the details of what Dominion proposes to build for itself.

    • The Dominion IRP is not, as Walton Shepherd of the NRDC characterizes it, a document prepared to show how DVP will comply with the Clean Power Plan; the contents of this document are defined by law. It is primarily a forecast by the utility of its customer load over the next 15 year planning period and a depiction by the utility as to how it will serve that load. Cooperatives are not required to file IRPs, only the investor-owned electrics–DVP, Appalachian Power and Old Dominion Power, which operates down in far western Virginia. DVP does not plan to meet the loads of the cooperatives and municipals that take service from the DVP transmissions system–the DOM Zone–as PJM calls it. They are responsible for their own planning. Most of the cooperatives are full requirements customers of Old Dominion Electric Cooperative which owns some generation and purchases some power from the PJM wholesale market to meet those loads.

      In this IRP filing, however, there are various scenarios put out by DVP regarding compliance with the CPP because these requirements were either added to the law by the General Assembly or directed by the SCC to be included. Of course, we still have no final carbon regulations to comply with and whatever emerges from the courts may bear little resemblance to the currently proposed rules. So, to a certain extent, this year’s IRP filing is a placeholder with regard to the CPP until the details of that regulation are firmed up.

      Shepherd believes that DVP can comply with the CPP less expensively than DVP forecasts and maybe it can. But in addition to complying with the CPP, Dominion is still legally required to plan for meeting and in fact to meet the demands of its customers.

      And yes, Larry, not only in theory but in fact entities other than Dominion can build (and have built) generation in Virginia with the output either sold into PJM or contracted to a known purchaser and dispatched by PJM. The 80 MW solar facility on the Eastern Shore was originally built by a 3rd party developer, with its output going into the PJM market and in essence bought by Amazon. Later, Dominion Resources bought that facility and is finishing it. There’s a big natural gas plant in Doswell that’s been operating for about 20 years and is expanding. Its ownership has changed hands a couple of times.

  8. Mostly yes; definitely yes. The State line means nothing; the power source could be located anywhere in PJM. Dominion’s generation could be anywhere that’s deliverable to where it is needed, and owned by Dominion or a contractor or an independent.

  9. Assuming the proposed CPP holds up as structured – which is up in the air- the State of Virginia needs to prepare a plan with options to meet CPP, not Dominion. And not NRDC. Dominion does have input. We’ve had a lot of divisive debates, but without much if anything from DEQ about what they think we’d actually have to do, or options. It could take several years to sort out, and it could be virtually impossible to sort out in a purple state.

  10. thanks to you guys who are helping to educate those of us – who need it!

    so if DVP’s IRP does not address the planning for the Co-ops… what percent of Virginia’s electricity needs are met by the co-ops and how does that part get planned in an IRP sense?

    and to TBill’s thoughts – what is the relationship between the Coops and the CPP or maybe the better question – what is the relationship between the CPP and non-DVP generators of electricity in Virginia?

    • Larry, the distribution coops are not required to prepare and file an IRP with the SCC.

      Most of the coops have membership ownership in ODEC, which owns some and procures by contract and market purchase the rest of the generation necessary to meet the demand of the distribution cooperatives.

      The cooperatives will aslo be affected by whatever CPP finally emerges. But, they (through ODEC) own so little generation compared to DVP that their influence on the compliance program that DEQ develops will probably not carry the weight that DVP’s views will.

  11. Thank you all for great explanations of a very confusing set of subjects

    Re: “The 80 MW solar facility on the Eastern Shore was originally built by a 3rd party developer, with its output going into the PJM market and contracted for by Amazon.”
    The facility was originally set up as a direct sale to PJM because that was the way around the restrictions in the SCC regulations … third party ownership, net metering restrictions etc. Any comments about those issues?

    • Sure, the output from the plant will still be delivered to PJM. It will not be delivered directly to Amazon, but DVP will contract to take from PJM the equivalent amount of power from PJM and deliver the power at basically the PJM wholesale rate to Amazon, which can then declare that this is indeed the green solar power produced on the Eastern Shore.

      Restrictions on direct sales to retail customers are a function of Virginia law, not SCC regulations, by the way. It is interesting that in Amazon we have a customer nearly as powerful as its supplier; perhaps we shall see some loosening of these legal restrictions on direct purchase in the future.

  12. re: law and regulations – the question is – does such law and regulation provide reasonable opportunities for other generators and retail customers or is the playing field tilted to DVP?

    I note on my Rappahannock Electric Coop bill – that there are four components –

    distribution delivery
    electric supply service
    power cost adjustment
    Virginia + local Tax

    I wonder how that compares to DVP bill…

    I assume that for distribution – there are no choices – I’m paying for the use of the grid to deliver electricity

    on the second item – I have no choice either – apparently

    and on the third item – I have no clue the how and why of it

    I bet out of …say 100 people that maybe 1 or 2 really understand how that bill “works” … but perhaps some of these guys educating here – can explain better.

  13. My DVP bill is much the same:

    Distribution Service
    Electricity Supply Svc (ESS)
    Generation
    Transmission
    Fuel

    The Distribution charges are for the wires and substations that Rappahannock has built and maintains to deliver the power to your meter. Its the little side of the “grid.” No competition for distribution. Your “electric supply service” is pretty much what my “ESS” is–the actual energy you consume and the big transmission wires (i.e., the big interstate grid) that deliver it from the generator to the substations for distribution. It is the generation component where competition in electricity is possible. Competitive factors are also at play in transmission in that PJM allows 3rd parties to bid against the franchised utility to construct transmission lines, thereby theoretically lowering the total cost of this component of our bills. But, you don’t get to choose a different transmission provider.

    Your “power cost adjustment” line item accounts for fluctuation in the charges that ODEC sends to Rappahannock for the power it generates or procures to serve you and your fellow members. My “fuel” pays the line item of the gas, coal and uranium that DVP purchases to generate its power. The coop does not mark up the PCA charge and DVP does not get a mark-up on fuel; these are straight pass through of the costs of these items to our respective electricity providers. Taxes are taxes, of course.

    While 3rd parties can build and operate generation, either conventional or renewable, in Virginia, their opportunities to directly sell power to individual customers is severely constricted–the laws are heavily tilted toward DVP and the other incumbent providers, including Rappahannock and the other coops. But, DVP is indeed the big dog and it eats first.

  14. thanks much…………………..

  15. interesting info from Energy Information Agency:

    American coal use for electricity dropped 29% in 2015, compared to peak usage in 2007

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