Testing the Impact of Solar

Solar panels at Dominion's Philip Morris USA site with warehouses in the background.
Solar panels at Dominion’s Philip Morris USA partnership program site.

Virginia has been slow to embrace small-scale solar energy, but Dominion’s Solar Partnership Program could show how to integrate variable solar generation into local distribution systems.

by James A. Bacon

The biggest solar farm built in Virginia to date isn’t very big by anybody’s standards — only 2.5 megawatts, enough to power about 500 homes. But Dominion Virginia Power, which owns and operates the facility on land leased from Philip Morris USA, says it will apply what it learns from the project to smooth the integration of larger volumes of solar power into Virginia’s electric grid in the future.

Built for $4.9 million, the Philip Morris facility is one of ten projects either completed or underway under Dominion’s “Solar Partnership Program.” The scale is tiny: Projects conducted in cooperation with various Virginia universities and corporations total 6.7 megawatts, about one two-hundredth the capacity of the new gas-fired power station the utility is building in Greensville County.

The purpose of the program is experimental. Dominion’s system, like those of most electric utilities, is dominated by huge power plants that rely upon high-voltage transmission lines to move electric power long distances and lower-voltage lines to complete the connection to local homes and businesses. Anticipating a surge of solar power, much of it small-scale and scattered, Dominion wants to see how solar impacts the reliability of its distribution system.

“What happens when you put a new power source on a lightly loaded circuit?” says Brett Crable, director-new technology and energy conservation: “Do our traditional power grid components handle it well?”

Dominion has come under intense criticism from environmentalists who say the power company is biased toward building massive, gas-fired power stations instead of more distributed, smaller-scale solar power. Dominion has dragged its feet on solar, argues Ivy Main, author of the Sierra Club-Virginia’s Power to the People blog.

The Commonwealth had only about 22 megawatts of solar installed as of the end of 2015, but by the end of this year, we should be comfortably into the triple digits. That’s still trivial compared to neighboring North Carolina, which added over 1,000 megawatts last year alone, but it’s grounds for celebration here in the “dark state.”

Dominion counters that it is moving slowly but deliberately in order to preserve the integrity and the grid and the reliability of service. Solar is an intermittent power source — it generates power only when the sun shines. Its output can fluctuate dramatically over the course of a day as clouds sail by. While the high-capacity transmission grid is robust — PJM Interconnection maintains that its service territory, which includes Virginia, could accommodate up to 30% renewable energy sources — Crable says less is known about the impact of variability on local distribution systems. “We want to do it the most effective way possible by learning on a small scale.”

After a few months of operation at the Philip Morris location, Dominion has already made one finding: Electric power is flowing the opposite direction the circuit is designed for. That’s not necessarily a bad thing, says Crable, but only time will tell.

The Philip Morris project is one of ten small solar facilities either completed or underway in partnership with Virginia corporations and educational institutions. Participants include Canon Virginia, Old Dominion University, Capital One, Virginia Union University, Prologis, Randolph-Macon College, Western Branch High School, Merck and the University of Virginia.

Dominion approached Philip Morris, which operates a major tobacco de-stemming operation in eastern Chesterfield County. The cigarette manufacturer provided 11 acres of vacant land in a 20-year lease. Aside from wanting to be a good partner with Dominion, which has always been responsive to power outages and other issues, Philip Morris thought the solar farm would complement its reclaimed wetlands and cogeneration facility, says Greg Ray, senior vice president of manufacturing. The company saw “an opportunity to educate people about ways to make manufacturing more sustainable.”

While Dominion leases the land, it owns and operates the solar farm itself. Power from the Philip Morris facility will feed into a “lightly loaded” circuit in a rural corner of Chesterfield County, which has different conductive characteristics than more heavily loaded circuits. Dominion also is interested in how roof-mounted and ground-based solar might have different effects.

Why can’t Dominion learn from other electric utilities that have pursued solar power more aggressively? “We’re very attuned to what other utilities are doing but not all electric systems are built the same,” says Crable. Distribution lines vary in voltage, and Dominion may use different arrays of equipment to regulate the voltage. Dominion, he says, wants first-hand information about how solar works on its system.

Main with the Sierra Club is not impressed by how the program has progressed. The General Assembly passed a law in 2011 that allowed Dominion to build up to 30 megawatts of solar energy on leased property. As she wrote on Power to the People:

The program was supposed to proceed in two phases, with 10 MW in place by the end of 2013, and another 20 MW by December 31, 2015. However, the program got off to a very slow start. In August of 2014 the company acknowledged it was behind schedule and would likely not achieve more than 13 or 14 MW of the 30 MW authorized before it ran out of money. On May 7, 2015 Dominion filed a notice with the SCC that it needed to extend the phase 2 end date to December 31, 2016, and confirmed that it would install less than 20 MW altogether.

Dominion has evaluated hundreds of sites and engaged in advanced negotiations with dozens of customers, says Nathan Frost, manager of New Technology and Renewable Programs. The need to select distribution circuits with unique operating characteristics limited the number of suitable locations. Further narrowing the potential sites was the need to reach long-term agreements with willing customers.

“The ten sites that are now complete or under construction represent a significant investment in renewable energy by Dominion,” says Frost, “and will allow the company to better understand how to integrate solar in a safe and sustainable manner.”

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13 responses to “Testing the Impact of Solar”

  1. LarrytheG Avatar

    What DVP is saying – makes sense – to a point but it’s not like other power plants run 24/7 … forever… without ever shutting down and there already is variability in the grid with peak hours.. even when your primary supply is coal or nukes – which are not very flexible – either.

    I suspect what happens with coal or nukes is that you respond to varying demands by idling turbines but still burning fuel i.e. just idle the turbine but don’t stop burning fuel.

    You could add solar to that mix – and still do the same thing – when solar is putting out – idle the fossil fuel turbines… and when solar drops – re-connect the idled fossil fuel turbines…just as you would if demand dropped in a non-solar scenario.

    Wasteful – yes – but no more so than what they were doing all along when there was no solar…and they had to maintain “hot ready” coal or nukes to meet ramping up demand.

    Peaker gas plants came into being because of this. that allowed the utilities to lower the baseload – in the places where they had the peakers …so that they could fire up the peakers when demand exceeded the baseload.

    when you throw solar into the mix.. you keep your baseload… you idle the peakers as long as solar is putting out – then when solar goes down – you fire up the peakers… just as you would when the peakers were used to top off baseload when there was no solar

  2. TooManyTaxes Avatar

    Larry raises some good points.

    Procedurally, the VSCC should, if it has not done so already, open a proceeding that will monitor and investigate the integration of renewal generation sources into DVP’s system. The proceeding should be ongoing; use a “paper” process as much as possible to minimize expenses, including those for participants; supplement the paper process with periodic live hearings/public fora, as appropriate; and issue periodic orders/reports/findings/etc. The VSCC should also designate part of its staff as a “separated staff to represent small ratepayers, both residential and business. It’s mission must be to protect the interests of those parties in inexpensive and reliable power.

    All other interested parties, including DVP, the Chamber of Commerce, the Sierra Club, can also participate. But someone must represent smaller ratepayers separately.

  3. TMT. Why isn’t wind more of a factor?

    Seems like it can operate 24/7 day/night and wouldn’t seem to use up so much land area as solar takes off the table. … and if off shore gets better wind as well.

    What are the relative investment/operational costs of land-based solar vs. off-shore/mountain-top wind?

    1. TooManyTaxes Avatar

      John B. My intent is that the open proceeding should consider the impact of all renewables (typo I wrote “renewal”) on DVPs’ system. The key points to me are the proceeding should be technology neutral (solar, wind, waves, anything) and must have representation for small ratepayers (small business and residential customers).

      The interests of these customers is not the same as that of DVP, big business, the state government of Virginia or interest groups (such as the Sierra Club). There needs to be separate representation, which a part of the VSCC staff could provide, so long as they are “walled off” from the rest of the staff in my suggested docket and any related proceedings.

  4. It would be great if the SCC could take on the role of statewide planning for electrical energy use and supply. Energy efficiency and distributed renewable generation provided by third-parties can go a long way towards reducing or supplying the future demand for electricity. Virginia should not be limited to just the utility point of view in developing the ways by which our energy system evolves. It should be a collaborative process with input from a variety of sources.

    When I first read about Dominion’s solar partnership program it sounded like they were searching for ways to make solar look less useful. But they could be selecting locations that represent the extreme situations so that they can identify the outside boundaries of what might be required for grid adjustments. Getting real-world experience is valuable, as long as there is no ulterior motive attached.

    1. TooManyTaxes Avatar

      I don’t follow FERC that closely, but the FCC has had a number of dockets that involved industry planning and regulatory oversight over technology issues. They include the provision of equal access (1+ dialing) for long distances services, above and beyond what Judge Harold Greene did with the RBOCs; the expansion of toll free dialing to 888, 877, etc.; and the introduction of local number portability. At the present time, the Commission has open a proceeding entitled “Technology Transitions,” GN Docket No. 13-5 that is overseeing the transition from circuit-based switching and TDM (Time Division Multiplex) technology over copper wires to IP-based technology over fiber and wireless networks.

      There is no good reason for the VSCC not to open a similar proceeding to examine how renewable energy sources are to be integrated into the Virginia electric power system. This is an important issue that should be investigated and debated in public.

      1. TMT,

        You are so right. The imposed rate review hiatus would be a perfect time to have a thorough review of the energy technology and rate policy issues that are needed to create a 21st century energy system in Virginia. In the REV process in New York they have held numerous conferences inviting specialists from around the world to discuss the challenges and opportunities involved in creating a superior system. They are encouraging learning from everyone’s experience and the State R&D organization is funding many different pilot projects to test a variety of approaches and to gather data for all to use.

        The state legislature is supporting this initiative. In Virginia, it appears the GA interferes with the SCC rather than empowering them. We have an opportunity to create a better way for Virginia citizens and utilities.

      2. TMT, you are quite right as to FERC also. During the industry restructuring that brought us open access transmission and non-utility generators and independent system operators/grid planning/wholesale energy markets and, in most states, unbundled retail rates and retail “access,” FERC had a number of “technical conferences” beginning in the 1990s that led to investigative dockets and rulemakings that in some cases are still active. Some began before ALJs or spun off secondary proceedings conducted before ALJs, but most also involved days of public hearings before the Commissioners themselves. I recall the VSCC staff and representatives of many other State Commissions and NARUC participated in these hearings in Washington. Those hearings concerned wholesale markets and transmission (grid) operations, two matters that FERC has jurisdiction over in our unusual federal system of split electric regulatory responsibilities. The States have jurisdiction over retail sales and distribution operations, which are what’s most-immediately affected by distributed solar generation. Both the FERC and the VSCC regulate Dominion in these interconnected but parallel activities. It makes all kinds of sense for the VSCC, fully as much as FERC (and like the FCC in the communications arena), to hold investigative hearings concerning the huge changes in the electric grid and in electric consumption patterns that so many people are predicting now — as the result of cheap renewable-resource power generation and the potential for dispersing much of that generation (along with cheap battery storage) in small installations scattered all over the grid — to get a sense of how regulation and the big utilities are going to need to adapt.

        I still believe we are going to continue to need an electric grid, with coordinated planning and operations, and wholesale electric markets; the idea of going totally “off the grid” is just not compatible with normal urban life. On economics alone, the grid as structured today can absorb up to 30% or so renewables power (which by its very nature is intermittent); beyond that the grid-based structural impediments (not to mention siting impacts) start to increase steeply. But within the range of the probable, replacing only 20%-30% of total electric generation with new solar and wind power (much of it dispersed in geographic patterns unseen in the past) will have a profound impact on the operation of all other generation, and thus, on the useful life forecast for that other generation, and thus, on the necessity for (and the reasonableness of) ratepayer-based financing for that other generation.

        Dominion’s IRP does a good job of laying out the background for a discussion of all of this, but DVP punts to the SCC and the GA when it comes to recommendations. There’s a huge change coming here that we have to get our heads around; a few thoughtful hearings to sharpen the regulatory focus on renewables generation certainly won’t hurt.

  5. TMT, Larry, you are both right. TMT, I agree with your call for SCC involvement as explained below. But Larry, hold that concern about peaker gas plants and integrating Dominion’s power sources for another day; you are basically correct but that has nothing to do with Jim’s post today, and in any case, deciding what generators to run at any given time is PJM’s role as system operator, not Dominion’s as the generator owner. PJM (not Dominion) decides what to dispatch and when.

    We’ve talked before, here, about Dominion’s preference for big, utility-scale solar generation that it owns and operates. What you both, and TomH and others here, correctly focus on is the utility’s foot dragging with regard to distributed, customer-owned solar plants, the size of a typical residential or commercial customer’s load or smaller. If those are the wave of the future, as credibly predicted by many experts, DVP has to make sure its distribution system can accommodate them. Like TomH I hope there’s no ulterior motive involved in the way DVP is going about that. Jim’s post today seems to say that DVP is doing just what it ought to do to get ready. However some of what he reports makes me think Dominion still doesn’t “get it” when it comes to distributed solar, as opposed to “utility-scale” (and usually utility owned) solar.

    Some background about distribution systems is necessary here. A distribution system, roughly speaking, is what connects the customer to the nearest transmission-level substation(s). The concerns, when you embed small generators within a distribution system originally designed solely to deliver energy radially from the transmission grid, are (1) safety and (2) stability. Here is a highly-simplified look at these concerns:

    (1) Safety: Think of the way electricity flows inside your house: from the meter through the main breaker and a panel of satellite breakers, then out into your house on a bunch of different circuits. If you need to fix something on one of those circuits, you disconnect it with the “circuit breaker” and work on it. Now, what if you have a battery pack or solar panels on that circuit? You go to work on it, but it isn’t “dead”; it has live electricity on it! This is the problem of “backfeeding” and it scares the heck out of utility linemen — these guys have strict safety procedures and always disconnect circuits when they are about to work on them, but when they have switched off a line at the substation and think it’s now a dead wire but go to handle it and there’s live electricity there — ouch! This is why most commercially-sold solar installations include a package of equipment that includes a DC to AC inverter, a transformer to bring the solar output up to distribution voltage, switches to disconnect and reconnect things, and a sensor that, if it detects zero voltage on the utility’s distribution line, automatically disconnects the generator from the grid. The problem is, sometimes this disconnect equipment doesn’t read the situation correctly, or it doesn’t work correctly, or it’s installed wrong (homeowners are not all electricians!). It helps if the equipment package includes a communications link that can be monitored remotely and/or used to control the switches remotely. A commercial-scale (small business sized) solar array may have this but smaller solar installations usually won’t.

    (2) Stability: This is a concern especially where distribution lines run long distances and serve widely scattered customers, like, in the rural countryside. Electricity traveling those long distances encounters enough resistance simply in flowing through the miles of wire that its voltage can slowly drop. Utilities commonly place large capacitors etc. in their substations whose job is to boost the voltage and ‘reactive power’ back to where it ought to be, and filters and other devices to restore the electric flow to a nice “clean” sine wave oscillating 60 times a second rather than a “dirty” wave with an accumulation of chaotic variations, due to the electricity equivalent of noise or static, backfeeding from all the activities by all the customers connected to that distribution wire. They also install monitors and communications links to control the other devices. The problem with all these devices, unlike the underlying, basic wires and transformers that make up the grid, is that they are not installed to deal with multi-directional flows; the monitors may misinterpret/respond inappropriately when power starts coming onto the wire from another direction or with different voltage and ‘noise’ characteristics, and operating these devices may actually make the local situation worse. Moreover, the monitors in each substation send information back to the DVP (and ultimately PJM) control centers, where decisions are made extremely rapidly about how to operate the grid as a whole, and the operators’ response has to be based on an accurate understanding of what is happening throughout the grid, including with respect to generators on the distribution system.

    OK, enough background. What is Dominion doing here? It says it is trying out a bunch of small solar installations totalling 20 MW or so on a sampling of distribution lines. That makes sense. DVP probably has picked lines coming out of substations with a wide variety of voltage support and monitoring and communications devices in order to see how they all work together with solar power. But only ten sites?? That’s an average of 2 megawatts each! Wait a minute — what is desperately needed here is operating experience with dozens of sites in the range of 100 to 500 kilowatts (0.1 to 0.5 megawatts), the kind and size that people might actually place on their roofs or in their back yards. Moreover, Jim quotes DVP’s Frost saying, “The ten sites that are now complete or under construction represent a significant investment in renewable energy by Dominion.” OK, so DVP went out and itself built 10 sample commercial solar sites in the 2.5 megawatt size range. Those larger commercial-scale and utility-scale installations matter, but this does not demonstrate a Dominion expectation of, or commitment to learning about, distributed generation of the kind typical small customers will install, which is what the experts are forecasting. That is the commitment that’s needed.

    Jim also reports, “Why can’t Dominion learn from other electric utilities that have pursued solar power more aggressively? “We’re very attuned to what other utilities are doing but not all electric systems are built the same,” says Crable.” This is a weak answer. There are plenty of heavily-rural electric systems out there, many of them with similar substation equipment to support voltage and other stability factors. There are plenty of such systems with far more distributed generation than DVP has experienced to date. What is their experience? Of course it’s relevant! And DVP is not going to find out for itself by limiting its research to large solar arrays of the size and type that happen to appeal to a few of its largest customers and that only a utility would have the expertise to design and construct.

    So, TMT, I agree with your call for a broad SCC investigation of renewables here — but for the reason that we really don’t know much yet, and apparently aren’t going to learn it from Dominion, about how to integrate large amounts of customer-owned, small scale distributed solar generation on its distribution system. Maybe it will take an SCC inquiry to get DVP to ask the right questions.

    [BTW, Jim, I think after looking at your photo of the Philip Morris installation your reference to “2.5 kilowatts” and to a total Statewide of “6.7 kilowatts” is off by a factor of 1000; should be “megawatts.”]

    1. Acbar, Excellent commentary. Thanks for the contribution. Also, thanks for the correction.

  6. LarrytheG Avatar

    @Acbar – agree…. excellent commentary!!!

    re: backfeeding – keep in mind we already have more and more home backup generators which have specific safeguards to keep them from backfeeding during power outages. So why not require solar to be configured the same way -with safety interlocks to prevent them from feeding the grid during a power outage?

    The problem I have with DVP and won’t be fixed by the SCC is a lack of information about what DVP wants to do, a rationale, and a strategy… that would allow me to buy into their plan – be patient – and support the path they are taking – even if I might have wanted a different one.

    Their attitude is basically that this is their business… not ours.

    their attitude is that they will “inform” the public about what parts of their plan they want to – when they want to…

    I would suggest that just because DVP is a regulated monopoly that it does not relieve them of their responsibility to be – responsible to the public …. Instead, they operate as if they are more like a privately held company that only does what the govt forces them to do and even then only reluctantly.

    And I’ll give an example right here in BR – which they have chosen to promote their views – but it’s primarily a one-way communication as they seldom respond to comments much less engage in any kind of substantiative dialogue – which could actually work in their favor on some of these issues where people here are scratching their heads and trying to understand what and why DVP is doing something.

    Why are they so thick-headed on their OPPORTUNITY to actually engage the public that is really interested in their plans? Do they fear the more strident opponents or are they concerned about other market players and proprietary information or what?

    They remind me of the way that VDOT used to be a few years back (and still have some behavior remnants). Engaging the public does not mean you answer all their questions or do everything they want you to do … it just means you do engage them on some level upon which -actually ends up benefiting DVP in the longer run. It’s like they can’t see beyond their own nose on this issue sometimes.

    I’d like nothing better to have a defined DVP-certified Solar connection standard – and similar… that clears up misunderstandings and confusion as to what people can do – or not.

    What we need is LEADERSHIP from DVP on energy… rather than them sometimes acting like they’re running some cloistered business that they fear the public harming if they find out more about their business so instead they secretively lobby the GA instead and “we” find out when? after the fact? That’s no way to run a business unless you happen to be something like a payday loan outfit.

  7. Agree with you about not taking the opportunity for dialog, but as for that “DVP certified solar interconnection standard” there really is one. In fact there are four, and they are no secret:

    1. The basic one is set out in section xxv of the DVP tariff filed with the SCC. You can read it here: https://www.dom.com/residential/dominion-virginia-power/customer-service/rates-and-regulation/residential-rate-schedules.

    2. & 3. There are two “net metering” versions, one for residential and one for agricultural customers, in section xxvi. Both are limited to small units.

    4. These tariff sections also mention, but do not set out, all provisions for connecting a generator that is “under federal jurisdiction” — which is to say, one that sells exclusively to PJM — those interconnection standards are on the PJM website and are part of the PJM tariff filed with the FERC and DVP’s Virginia tariff has carve-outs for those installations. The PJM and DVP rules are generally pretty similar.

    Once you’ve read these, however, you will still have lots of questions.

  8. CleanAir&Water Avatar

    “Dominion’s Solar Partnership Program could show how to integrate variable solar generation into local distribution systems.”

    I am not sure I understand why Dominion needs to test and validate all the specified types of solar locations prior to committing to the goal of dramatically increasing solar generation in Virginia. NC has 100 times the amount of solar that we in Virginia have installed. 100 times! Much of it ‘behind the meter’ generation, some installed for specific customers and some of those actually located out of state.

    As Dominion acknowledges, Virginia is nowhere near reaching the amount of solar and wind that can be included on our grid. PJM concluded 30% was the number a few years ago. Recently the ERGIS study says the eastern grids can accommodate 30% without incurring any major issues, and a NOAA report looks toward 60% with grid improvements.

    When grid stability is discussed in a variety of places one solution always mentioned is that a grid operates more smoothly across a wide area. The sun is shining somewhere. Another solution is a sophisticated use of demand management. In anticipation of increased generation from renewables, demand-side management has not been promoted in any substantial way by the company here in Virginia.

    Finally, in the wider discussion of the reliable and safe integration of intermittent power, solar storage is seen as a viable solution to grid stability. Storage can reduce peak load at an individual end-user site or across the grid, and with additional controls can shape loads to meet the specific needs of the grid. The New York State Public Service Commission recently acknowledged, “A system consisting of weather variable and invariable generation will require a highly responsive demand side and/or the ability to store electricity on a large scale.”

    PJM, our regional grid operator, has taken the approach of increasing compensation for storage capacity because storage can respond instantly (in milliseconds) to correct deviations in frequency levels. Solar’s integration challenge will be different at different levels of solar installations. As solar eats into peak generation in the summer there is still a need for a certain amount of capacity payments to cover backup generation and replace solar’s shortfall during the winter. Eventually, as has happened in Germany,
    large amounts of solar generation erase peak demand and create a different issue with inflexible baseload power.

    Duke Energy Carolinas will also add more than 180 megawatts worth of capacity at its Bad Creek pumped-storage, hydro-electric plant by 2024. Green Mountain Power in Vermont is selling Tesla Powerwall batteries to its customers. Consolidated Edison, New York City’s major utility, recently announced it would be piloting a virtual power plant that incorporates distributed generation into an organized, modern grid, with more than 300 homes leasing high-efficiency solar panels and lithium-ion battery storage systems from Sunverge Energy. SunPower will supply panels for the project and these rooftop solar energy systems will be directly integrated with utility control rooms.

    All of these examples of companies expecting a different future. In Virginia we seem to be trying to extend the past as far as we can. Change is not always easy, but as NERC has concluded in their 2016 report … change is coming regardless of the CPP. SCC leadership and a collaborative process sounds like a very reasonable approach to move Dominion off this stage of their denial.

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