Solar Projects Progress in Orange, Campbell

Speaking of Dominion Energy Virginia’s commitment to solar (see previous post)…

Apco commits to solar… Appalachian Power Co., Virginia’s second largest electric utility, has signed an agreement to purchase electricity from the 15-megawatt Depot Solar Center in Campbell County as part its shift from coal to renewables. The deal represents the utility’s first commitment to utility-scale solar.

“Appalachian Power is excited to announce the Depot Solar Center as we move forward with the diversification of our generation portfolio,” said President Chris Beam in a press release. “We are pleased that the facility will be built and operated within our service area and provide other benefits that new construction will bring to surrounding communities.”

Depot Solar was developed by Pasadena California-based Coronal Energy, which has a office in Charlottesville. The company will sell the electricity to Apco through a 20-year renewable energy purchase agreement.

Apco selected the project after issuing an RFP in January 2017. The company received 37 proposals. Depot Solar, which will connect to Apco’s grid at the company’s Rustburg substation, is expected to be operational by September 2019.

And Orange County, too… The Orange County board of supervisors approved the county’s first large-scale solar farm, voting unanimously for a special-use permit that will allow a 400-acre, 60-megawatt solar farm to be build along Route 20.

The project, which will produce enough energy to power the equivalent of 10,000 homes, is being developed by Reston-based SolUnesco, according to the Orange County Review. Among the 20 provisions attached to the permit was a requirement to obscure visibility of the facility from Route 20.

The project is expected to bring in $2.2 million to the county in machinery and tools tax revenue over the course of its 30-year life, and bring in an additional $10,000 per year in property tax revenue. Depending on the environmental permitting process, construction is expected to begin by the end of 2018 or early 2019.

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15 responses to “Solar Projects Progress in Orange, Campbell

  1. When you travel through North Carolina these things are all over the place.

    I don’t know how it works in NC with Duke.

    And if not mistaken this is not like the way DOminion does solar, i.e. they typically do not buy solar from 3rd party producers.. who have to , themselves go find other buyers.

    Makes me wonder what might happen if Dominion DID buy 3rd party solar…

    • Dominion is buying a lot of power from third-party developers like SolUnesco. It puts out RFPs just like Apco did.

      • not aware of that… have you blogged about that?

      • For example, there’s a huge new solar installation (don’t know the MW) just being completed on the north side of US17 in eastern Essex County (near Dominion’s Dunnsville Substation) by Coronal Energy — we drive by it on the way to Mathews. There’s another one that’s just received final approvals for construction in central Gloucester County, on the east side of VA14 near Dominion’s Wan Substation. Not sure I’d characterize these as a response to RFP’s, but Dominion and APCo are certainly happy to have them as transmission customers.

        • . . . The solar plant in Gloucester County is a 20 MW installation by Strata Solar. But just a couple of days ago, an even bigger, 100 MW installation by a new solar developer, Hexagon Energy, was announced for the interior of Gloucester. And Dominion itself is building solar plants in King William and Middlesex Counties, in deals involving UVa. See:

          • Reed Fawell 3rd

            Acbar – Thanks for highlighting the Daily Press article regarding Gloucester County’s quest to become one of Virginia leading solar farm locations, plus the farms on the way on King William, Middlesex and Accomac County as well as Essex. Solar farms have arrived. Hopefully the right controls are in place as we discussed earlier. Particularly so given the rising number of independent operators.

  2. I’m talking about 3rd party to the grid . not 3rd party to Dominion and then to a specific buyer of solar.

    Is Dominion buying 3rd party solar to use itself to power the grid?

    • Larry, I have a vague recollection that transmission operators have some level of obligation to transmit power for other providers. I assume that they need to reimburse the transmission and distribution operators for that service. I’m sure our electric power industry experts can set us both straight.

  3. Jim is correct, most medium sized “utility scale” solar projects in Virginia these days are being financed and built by independent owners. They are “selling to the grid” — that is to say, they are being paid for their energy from the grid energy market (run by PJM), with the price paid whatever is dictated by the market’s varying locational marginal cost.

    But a commercial solar generating unit sells two other products besides energy. One is the “capacity” value of the unit, which load-serving-entities (LSEs) in PJM must buy annually to meet their reliability obligation to the ISO. A generator can sell its capacity value to any LSE in PJM, but often such deals are done within the LSE’s service territory because the LSE (such as DOM) likes to be known for supporting local businesses.

    The other product is RECs, which are the “renewable energy credits” that come from generating solar power on the grid. These are sold independently of the solar energy; RECs do not go automatically to the buyer of the energy and do not have to be sold to the local LSE. However the REC markets are less formal than PJM’s and are organized and handled at the State level, usually to allow LSEs to satisfy State-imposed RPS (renewable portfolio standard) requirements, or done directly between the generator and customer so the customer can meet a renewables requirement from some other source. A REC represents that 1 MWh of solar has been generated somewhere on the grid and the holder of the REC is entitled to claim credit for it. Rather than waiting until that megawatthour has actually been generated already, a solar developer may enter into an upfront deal with an LSE (or even a large retail customer, like the US Navy) to sell it the entire future stream of RECs associated with its solar output in exchange, say, for help with loans or other financial backing during the construction phase.

    I mention all this because an “independent” solar producer in Virginia may sell its energy to the grid operator, PJM, but it may have all sorts of financial side deals going involving the local LSE (e.g. Dominion or APCo or a co-op). Independent generation is big business.

    If Dominion continues to insist on owning solar installations that it could merely be supporting financially in other ways, you’d better be asking what incentive is pushing Dominion in that direction? Nine times out of ten, you can expect to find that it’s because it is advantageous in some way for Dominion, under its current retail rate structure, to put the investment in its rate base; even more so if it gets to recover the up front investment through one of those RAC adders to rates that are supposed to be “frozen.” We should all be pleased to see that era put behind us.

    In Dominion’s defense, though, the regulatory requirement Steve mentions above, that gives back 70% of any “excess profit” from retail rates that are not frozen, is a huge disincentive to a utility that’s as well run generally as Dominion is. It’s simply terrible to penalize a utility for keeping costs down; and since there’s no retroactive rate increase if profits end up on the low side, this kind of rate structure imposes risk for the utility in only one direction: down. If the GA chooses to repeal the rate freeze, let’s not just go back to the failed rate regulation that drove DOM to the freeze in the first place. I know it’s not popular to argue for the utility to retain what in hindsight are high profits, but that has to be part of the regulatory bargain. Of course the Commission can and should adjust rates (down or up) promptly going forward; but “regulatory lag” must be a two-way-street or the utility’s chance at actually earning its “authorized” rate of return becomes chimerical.

    To TMT’s question, yes, the transmission operator (PJM) does have an obligation to transmit power for third parties and the old utilities alike, on non-discriminatory terms. That is the primary reason that FERC pushed the whole idea of independent system operators (like PJM) forward in the 1990s — in order to prevent the big integrated utilities from playing games with the way they operated the grid so as to favor their own generation.

    • Thanks for your education and insights. Particularly your second to last paragraph as it relates to Dominion, and all the rest of comment as it relates to independent owners and producers, and how they interact with whole. My uninformed and inexperienced instinct whispers to me that all of this splintering and complexity of interests, functions, and contractual relationships might pose inherent risks to the grid in many known and unknown ways, including unintentional consequences, given that this new world might add complexity upon complexity, woven into now already incredibly complex systems. So how easy might it be for a small failure or wrong assumption radiate to bring a huge part of the whole down?

      Is that a reasonable worry? Or might the new system work to the reverse affect, creating redundancy or independence within systems not otherwise there? I am wandering in the dark here.

      • Read Ted Koppel’s book on the risks of the grid. A very reasonable worry. But I think the new grid’s diversity of players and of types of equipment and its very interconnectedness is one source of strong resilience. To me the greatest risk lies in the computerized control systems that respond in pre-programmed ways in micro-seconds to emergency situations. We need those to protect the grid’s hardware; but anyone hacking into those systems could bring it all crashing down in ways that could take days to recover from. As Koppel points out, the greatest risk is not from the big utilities, who are well versed in cyber-security, but from the little guys, the small municipal system, say — those that don’t even have a full time employee manning their controls, yet are (and have to be) “inside” the grid for communications and security purposes and therefore have degrees of access to everyone else’s software. All the bad guys need to do is hack into a laptop at one of those little municipal systems and go from there.

    • “In Dominion’s defense, though, the regulatory requirement Steve mentions above, that gives back 70% of any “excess profit” from retail rates that are not frozen, is a huge disincentive to a utility that’s as well run generally as Dominion is. It’s simply terrible to penalize a utility for keeping costs down; and since there’s no retroactive rate increase if profits end up on the low side, this kind of rate structure imposes risk for the utility in only one direction: down. If the GA chooses to repeal the rate freeze, let’s not just go back to the failed rate regulation that drove DOM to the freeze in the first place. I know it’s not popular to argue for the utility to retain what in hindsight are high profits, but that has to be part of the regulatory bargain. Of course the Commission can and should adjust rates (down or up) promptly going forward; but “regulatory lag” must be a two-way-street or the utility’s chance at actually earning its “authorized” rate of return becomes chimerical.”

      AC your comments on utility topics are almost always the best and most informed of any of us on this blog, but the paragraph I quoted above displays a fundamental MIS-understanding of the regulatory regime that preceded the rate “freeze” and that Steve advocates returning to. First, the freeze affected only base rates. The rate adjustment clauses (RACs) of which DVP has 10 or 12 now ALL contain built in profits that DVP is guaranteed to recover. Profits that are NOT reviewed in the base rate review at all. This includes a FERC set rate of return on equity in transmission investment, a growing piece of DVP’s portfolio. The SCC gets no say on what that is–the feds fix it. Secondly, the profits on the billions of dollars invested in the new generation are also insulated from review. However, the SCC does get to determine what the rate of return on this component of investment is. It recently determined a fair rate of return on equity for DVP would be 9.2%.

      With regard to the base rates, that rate of return would apply as well. But again here, the Assembly established a “band” within which the SCC could set its return. That band is comprised of the earned (not authorized) returns of about 15 predominantly southern utilities, mainly the operating affiliates of Southern Company, Duke Power and the Florida utilities. When the statute was written back in the mid-aughts, those utilities were earning like gangbusters. The floor of the band is determined by removing the two highest and two lowest earned returns and then taking an average of a majority of those remaining. The “ROE” determinations have been among the most bitterly contested determinations before the Commission in the last 10 years of regulation. (The “ceiling” of the band adds 300 basis points to the top of the range, incidentally)

      Now, as to those base rates, the utility retains all earnings that fall within the fair range of returns so determined by the Commission. Then it retains all earnings within the first 50 or 70 basis points above that (i.e., if the fair range of returns is 11.0-12.0%, the utility retains all profits until it reaches a return of 12.70%). Anything ABOVE THAT is shared with customers. If the utility earns above 15%, i.e., 300 basis points above the ceiling, all those returns go back to customers.

      But unless the utility overearns for 2 straight reviews, rates can never be reduced. Therefore, customers will again “overpay” through base rates and the utility has a built in earnings cushion that it can spend on any legitimate operating expense. Or, any expense legitimated by act of the Assembly, as Steve’s op-ed piece intimates. One year, the Assembly allowed the write-off of several hundred million of “development” costs for the nuclear unit that may some day be built at North Anna. That will be the day pigs are flying and the devil needs an overcoat.

      Basically, all expenses that the utility incurs that increase (such as new construction or costs to comply with environmental regs) are captured in the RACs and were never “frozen,” while any costs that are decreasing (personnel, or meter reading, for instance) are in the base rates that customers continue to pay years after the costs cease to exist.

      The risk is certainly not on Dominion. Customers have paid hundreds of millions more than they would have under traditional base rate, rate of return regulation under the Virginia only scheme of guaranteed profits on new construction of generation and transmission facilities. Under traditional regulation, rates are set to offer the utility the OPPORTUNITY to recover all costs and earn its authorized profits; with fair weather and good management that is what happens. Under the Virginia scheme, however, no management skill is required at all to earn fabulous returns–the law requires them to be included in the RACs.

      Chapter 23 of Title 56 of the Code of Virginia is a fantastically nuanced bit of legislation, all of it written by DVP’s attorneys and lobbyists. Just ask Steve; he was there.

    • I stand corrected! One of the advantages of this blog is that obsolete or simply incorrect understandings (a) get expressed anyway and (b) will usually be pointed out emphatically and (c) we learn as in any good conversation, without name-calling. The way you describe it the adjustment process even outside the bandwidth is less onerous than Steve suggested.

      My distant knowledge of the SCC’s annual review process was that what started out in the 1970s as a Commission-mandated info filing merely to facilitate periodic comparisons and trigger base rate cases (either way), mutated into a highly prescriptive formulary filing, later mandated by statute, with little opportunity for the utility to argue that the formula didn’t reflect the relevant facts, and automatic rate adjustments for straying outside the formulary bandwidth, and any challenge to this became unpleasantly political. My impression was that the formulary determination of utility rates became elevated to a high art when Dominion lost patience with the SCC and sought to put bounds on its discretion from a higher authority. But the result, as you say, is “fantastically nuanced” and a far cry from the open-ended constitutional standard of just, reasonable and nondiscriminatory rates and service. And leaving the SCC so impotent to act with the full discretion it once exercised on behalf of ratepayers in a time of rapid change in the electric industry is problematic.

      Yes, take transmission off the table jurisdictionally. But generation: my understanding was that after an initial foray into unbundling and retail access, some Virginia folks got cold feet and walked that at least part way back at the State level. Meanwhile FERC plowed ahead with its ISOs and wholesale markets. I don’t pretend to understand exactly how the rate of return is determined these days for newly ratebased generation in VA, except that the RAC process seems highly political. But north of the Potomac, in PJM, NYISO and ISONE, there has been a lot, probably the majority, of generation spun off to unregulated generation subsidiaries or sold to independents, leaving the original LSE largely grid-dependent. South of PJM the former integrated utilities have largely kept their generation ratebased (and therefore under State regulation); except I know Southern Company’s Mirant spinoff is a more complicated story, and Texas is, well, Byzantine. Virginia is something of an oddity and seems to have evolved into a reactionary regulatory scheme — not only because the VA utilities like that regulated ROE but also because the SCC (and GA?) fundamentally doesn’t trust PJM’s markets to provide long term reliability. Damned bunch of northerners, these markets are just complex ways to take advantage of us, FERC forcing us to join an ISO is like 1865 all over again, we need to control our own destiny, we Virginians can take care of ourselves, etc. — I heard stuff like that in the 90s, anyway.

      You point out one crucial difference today, which is Dominion’s use of all those RACs for generation that they used to have to put in rate-base, along with the uncertainty over when the CWIP would end up reflected in rates. It used to be that about the only automatic adjustment was for fuel, and interchange was thrown into that calculation almost as an afterthought. Now, for a grid dependent LSE, interchange may be the biggest part of the retail bill (aside from wires and customer/billing charges). Now, the co-ops and the traditional utilities are alike. But not in Virginia. Neither Dominion nor AEP want to go there.

      I have puzzled over why Dominion has been so resistant to removing its generation, or at least all new generation, entirely from State regulation. Apparently the GA has made it worth Dominion’s while not to take the risk of really going out there and competing with the independents on the grid, where generation costs and profits have neither a ceiling nor a floor, and financing new construction on that basis like the independents do. Instead, Dominion took the (substantial) risk of a retail base rate freeze (excluding RACs, fuel, interchange, and transmission). Regulation can be a profitable paradigm for those who can manipulate the process. I look forward to learning what else might explain it.

  4. well.. all this informed dialogue makes my head SPIN! WHO KNEW that electricity generation was so COMPLICATED! 😉

    Forgive me for attempting to summarize but it appears from the dialogue that Dominion has more opportunities from profit beyond the base rate.

    Second – the idea that Dominion “would not allow” independent solar producers in it’s service area seems just totally not true … as there seem to be a plethora of them now – some with no relationship to Dominion, others with such a relationship – and in general that is a dark hole – in terms of knowing the terms and relationships. There must be tremendous opportunity to build solar – for a profit. I cannot imagine folks throwing down their money for these myriad and ubiquitous farms without some reasonable hope for a return on their investment.

    Finally – if Dom is actually buying solar directly from some providers – I would assume they actually do use that power and that in buying and using it they CAN accommodate it grid-wise AND it’s financially advantageous for them to buy it and use it.

    So.. if DOM can and does have all these numerous other ways to earn additional profit besides the base rate .. then why would they or the GA want to mess with the base rate regulation other than they could actually get that favorable vote..? It certainly looks like that by doing it – there are some adverse consequences both politically and financially. Was it, in retrospect, a misguided idea that turned into a screwup?

    • To put it very briefly, looks like it to me. Yes, Dominion could have built all its new generation as unregulated market-based investments entirely on spec, not as rate-based units at regulated returns. They didn’t.

      The problem with overriding the SCC through the GA is that Dominion opened Pandora’s box. The SCC is a group of experts devoted to sifting slowly and thoroughly through all this changing complexity and coming up with the best answers for the public. The GA is a group of generalists with lots else on their plates who tried to resolve all this on the advice of a handful of lobbyists in a few highly-politicized committee hearings. Having got the GA involved in micromanaging the regulatory process, it’s very difficult ever to get them out of it.

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