Renewable energy bills to watch

People gathered with signs supporting climate action

Grassroots activists gather at the steps of the Virginia Capital on January 14. Photo courtesy Sierra Club.

Yesterday’s post launched my annual roundup of energy and climate bills with a comparison of the two major energy transition bills filed to date, HB1526/SB851, the Clean Economy Act, and HB77, the Green New Deal Act. Today I’m covering other renewable energy bills. You will be glad to see I am addressing each only briefly, given the large number of them. Bills can still be filed as late as tomorrow evening, and there is often some lag in the Legislative Information System, which posts the bills, their summaries, their committee assignments, and what happens to them. I will add to this list once I’ve seen the rest, so check back for updates.

Most of these bills will be heard in Senate Commerce and Labor, or now in the House, Labor and Commerce, committees. Both House and Senate have established energy subcommittees. In the Senate, the subcommittee is advisory and does not have the power to kill a bill outright. The House subcommittee used to be a killing field for good bills. Hopefully this year will be different.

Bills with monetary implications typically must go to Finance or Appropriations.

As always, the action will be fast and furious, and it is already underway. Blink and you will miss it.

RPS

Both HB1526/SB851, the Clean Economy Act, and HB77, the Green New Deal Act, contain a renewable portfolio standard (RPS) requiring utilities to include in their electricity mix a percentage of renewable energy that ratchets up over time. In addition, HB1451 (Sullivan) is a stand-alone RPS bill that also includes an energy storage mandate. It applies only to IOUs but otherwise appears to be identical to the RPS and storage provisions of the CEA (of which Sullivan is also the patron).

Instead of an RPS, SB876 (Marsden) establishes a “clean energy standard” applicable to both IOUs and coops. A “clean energy resource” is defined as “any technology used to generate electricity without emitting carbon dioxide into the atmosphere,” including “(i) electric generation facilities that are powered by nuclear, solar, wind, falling water, wave motion, tides, or geothermal power; (ii) a natural gas-fired generation facility with 80 percent carbon capture; or (iii) a coal-fired generation facility with 90 percent carbon capture.” Aside from the contradiction in terms inherent in this definition, the clean energy standard also suffers from a delay in its starting point to 2030, when it begins at 30%–or about where Dominion is today with its nuclear plants. Considering only offshore wind and solar development already underway, the CES would not be a meaningful spur to new renewable energy for at least another 15 years. A couple of strong points, however: the bill also requires the closure of all coal-fired generation facilities by 2030, and requires workforce transition and community assistance plans.

SB842 (Petersen) provides for all retail customers of electricity to be able to choose their supplier, and instructs the SCC to promulgate regulations for a transition to a competitive market for electricity. Existing utilities will continue to provide the distribution service. The bill also requires suppliers of electricity to obtain at least 25% of sales from renewable energy by 2025, 50% by 2030, and 100% by 2050. Renewable energy is defined to include “sustainable biomass” but not waste incineration or landfill gas.

Customer-sited solar

Solar Freedom” is back this year for another attempt to lift barriers to customer-sited renewable energy, including rooftop solar. The primary vehicles are SB710 (McClellan) and HB572 (Keam), with nearly identical versions from Lopez (HB1184) and Simon (HB912). It contains 8 provisions:

  1. Raising from 1% to 10% the cap on the total amount of solar that can be net metered in a utility territory, ensuring small-scale solar continues to grow.
  2. Making third-party financing using power purchase agreements (PPAs) legal for all customers of IOUs, removing current cap. The SCC reports the program in Dominion’s territory is now filled, putting in jeopardy Fairfax County’s ambitious solar plans. In Southwest Virginia in APCo territory, the program is even smaller and narrower, and several projects have been unable to move forward.
  3. Allowing local government entities to install solar facilities of up to 5 MW on government-owned property and use the electricity for schools or other government-owned buildings located on nearby property, even if not contiguous. This would allow Fairfax County to move forward with a planned solar facility on a closed landfill; localities with closed landfills across the state could similarly benefit.
  4. Allowing all customers to attribute output from a single solar array to multiple meters on the same or adjacent property of the same customer.
  5. Allowing the owner of a multi-family residential building to install a solar facility on the building or surrounding property and sell the electricity to tenants. This is considered especially valuable for lower-income residents, who tend to be renters.
  6. Removing the restriction on customers installing a net-metered solar facility larger than required to meet their previous 12 months’ demand. Many customers have expressed interest in installing larger facilities to serve planned home additions or purchases of electric vehicles.
  7. Raising the size cap for net metered non-residential solar facilities from 1 MW to 3 MW, a priority for commercial customers.
  8. Removing standby charges on residential facilities sized between 10-20 kW. Current charges are so onerous that few customers build solar arrays this size, hurting this market segment.

Other PPA and net metering bills

HB1647 (Jones) is similar to Solar Freedom but includes community solar and leaves out meter aggregation.

Five of the eight provisions of Solar Freedom also appear in the Clean Economy Act, omitting only numbers 3,4 and 5. SB532 (Edwards) is a stand-alone bill to make PPAs legal, using an approach similar to that of Solar Freedom and the CEA. HB1067 (Kory) deals with a specific situation where a customer has solar on one side of property divided by a public right-of-way, with the electric meter to be served by the solar array on the other side. The legislation declares the solar array to be located on the customer’s premises. (Item 4 of Solar Freedom would also solve the problem.)

Resilience hubs

HB959 (Bourne) directs DMME to establish a pilot program for resilience hubs. These are defined as a simple combination of solar panels and battery storage capable of powering a publicly-accessible building in emergency situations or severe weather events, primarily to serve vulnerable communities.

HOAs

HB414 (Delaney) and SB504 (Petersen) clarifies the respective rights of homeowners associations (HOAs) and residents who want to install solar. The law allows HOAs to impose “reasonable restrictions,” a term some HOAs have used to restrict solar to rear-facing roofs regardless of whether these get sunshine. The bill clarifies that HOA restrictions may not add more than $1,000 to the cost of solar facility, or decrease the expected output by more than 10%.

Community solar.

Three years ago legislation passed to allow utilities to set up so-called community solar programs. A couple of coops followed through, notably one from Central Virginia Electric Cooperative. Dominion received SCC approval to launch a small program back in 2018, but still hasn’t done so. That leaves a large base of potential customers—people without sunny roofs, apartment dwellers, or anyone who can’t afford to install solar—with no options.

The Clean Economy Act has detailed provisions for community solar, supported by the trade organization Community Solar Access. An alternative as a stand-alone bill is SB629 (Surovell). It creates an opportunity for subscribers in the territory of investor-owned utilities to buy from small (under 2 MW) “solar gardens” developed by third-party owners. Utilities would credit purchasers at the retail rate minus the utility’s costs. Preference would be given to solar gardens with low-income subscribers.

HB573 (Keam) does not establish a new program. It affects the utility-controlled and operated “community solar” programs required by 2017 legislation (and still not rolled out yet, though I assume the facilities have been selected). The bill requires that “an investor-owned utility shall not select an eligible generating facility that is located outside a low-income community for dedication to its pilot program unless the investor-owned utility contemporaneously selects for dedication to its pilot program one or more eligible generating facilities that are located within a low-income community and of which the pilot program costs equal or exceed the pilot program costs of the eligible generating facility that is located outside a low-income community.” I read this to mean utilities must select more expensive sites and develop more expensive programs in low-income areas than elsewhere, which seems . . . odd.

HB1634 (Jones) requires utilities to establish shared-solar programs that allows customers to purchase subscriptions in a solar facility no greater than 5 MW. (For what it’s worth, the GA passed a similar law in 2017, and we are still waiting for Dominion’s program.)

Resolving local disputes over utility-scale projects

Developers of utility-scale solar and wind sometimes face pushback at the local level. Opposition can come from residents who worry about viewsheds or who have been subjected to anti-renewables propaganda, and from local officials who want to collect tax revenue above the local real estate tax rate. Industry organizations and counties have worked to come up with a number of bills to resolve the concerns, though in some cases the counties have split on whether to support them.

HB1327 (Austin) allows localities to impose property taxes on generating equipment of electric suppliers utilizing wind turbines at a rate that exceeds the locality’s real estate tax rate by up to $0.20 per $100 of assessed value. Under current law, the tax may exceed the real estate rate but cannot exceed the general personal property tax rate in the locality. Wind developer Apex Clean Energy helped develop the bill and supports it.

Bills supported by the solar industry organization MDV-SEIA include:

  • HB656 (Heretick) and SB875 (Marsden) allow local governments to incorporate into their zoning ordinances national best practices standards for solar PV and batteries.
  • HB1131 (Jones) and SB762 (Barker) authorize localities to assess a revenue share of up to $0.55 per megawatt-hour on solar PV projects, in exchange for which an existing tax exemption is expanded.
  • HB657 (Heretick) and SB893 (Marsden) exempt solar facilities of 150 MW or less from the requirement that they be reviewed for substantial accord with local comprehensive plans.
  • HB1434 (Jones) reduces the existing 80% machinery and tools tax exemption for large solar projects.
  • SB870 (Marsden) authorizes local planning commissions to include certain regulations and provisions for conditional zoning for solar projects over 5 MW.

Other RE siting bills

HB1133 (Jones) makes it in the public interest for utilities to build or purchase, or buy the output of, wind or solar facilities located on previously developed sites.

A couple of bills appear designed to make wind and solar projects harder to site, or are intended to rile up sentiment against solar: HB205 (Campbell) adds unnecessary burdens to the siting of wind farms and eliminates the ability of wind and solar developers to use the DEQ permit-by-rule process for projects above 100 megawatts. HB1171 (Poindexter) is a make-work bill requiring an annual report of the acreage of utility scale solar development, as well as the acreage of public or private conservation easements. HB1636 (Campbell) prohibits the construction of any building or “structure” taller than 50 feet on a “vulnerable mountain ridge.” You can tell the bill is aimed at wind turbines because it exempts radio, TV, and telephone towers and equipment for transmission of communications and electricity.

Grants, tax deductions, tax credits and other financing

HB754 (Kilgore) establishes the Virginia Brownfield and Coal Mine Renewable Energy Grant Fund, which will support wind, solar or geothermal projects sited on formerly mined lands or brownfields. (See also Jones’ HB1133, which makes it in the public interest for utilities to build or purchase, or buy the output of, wind or solar facilities located on previously developed sites. And see Kory’s HB1306, which directs DMME to adopt regulations allowing brownfields and lands reclaimed after mining to be developed as sites for renewable energy storage projects.)

HB461 (Sullivan) establishes a tax credit of 35%, up to $15,000, for purchases of renewable energy property. It is available only to the end-user (e.g., a resident or business who installs solar or a geothermal heat pump).

HB633 (Willett) establishes a tax deduction up to $10,000 for the purchase of solar panels or Energy Star products.

HB654 (Guy) authorizes DMME to sponsor a statewide financing program for commercial solar, energy efficiency and stormwater investments. The effect would be to boost the availability of Commercial Property Assessed Clean Energy (C-PACE) in areas of the state where the locality has not developed a program of its own.

HB947 (Webert) expands the authority of localities to grant tax incentives to businesses located in green development zones that invest in “green technologies,” even if they are not themselves “green development businesses.” Green technologies are defined as “any materials, components, equipment, or practices that are used by a business to reduce negative impacts on the environment, including enhancing the energy efficiency of a building, using harvested rainwater or recycled water, or installing solar energy systems.”

SB542 (Edwards) repeals the sunset date on crowdfunding provisions and provides fixes for certain existing obstacles to this financing approach. The bill is the result of lessons learned in developing a 2019 “solar bonds” program for five commercial and non-profit customers.

SB754 (Marsden) authorizes utilities to establish on-bill financing of energy efficiency, electrification, renewable energy, EV charging, energy storage and backup generators.

Customer rights to buy renewable energy

HB868 (Bourne) and SB376 (Suetterlein and Bell) allows customers to buy 100% renewable energy from any licensed supplier, regardless of whether their own utility has its own approved tariff.

HB 889 (Mullin) and SB 379 (McPike), the Clean Energy Choice Act, is broader than HB868. The legislation allows all customers to buy 100% renewable energy from any licensed supplier regardless of whether their utility has its own approved tariff. In addition, large customers (over 5 MW of demand) of IOUs also gain the ability to aggregate their demand from various sites in order to switch to a competitive supplier that offers a greater percentage of renewable energy than the utility is required to supply under any RPS, even if it is not 100% renewable. Large customers in IOU territory who buy from competing suppliers must give three years’ notice before returning to their utility, down from the current five years. The SCC is directed to update its consumer protection regulations.

Offshore wind

The CEA contains detailed provisions for the buildout and acquisition of offshore wind. HB234 (Mugler) directs the Secretary of Commerce and Trade to develop an offshore wind master plan. SB860 (Mason) puts the construction or purchase of at least 5,200 MW of offshore wind in the public interest.

HB1607 (Lindsey) and SB998 (Lucas) allows Dominion to recover the costs of building offshore wind farms as long as it has a plan for the facilities to be in place before January 1, 2028 and that it has used reasonable efforts to competitively source the majority of services and equipment. All utility customers in Virginia, regardless of which utility serves them, will participate in paying for this through a non-bypassable charge. Surely this bill came straight from Dominion.

 

A first look at the Clean Energy Act and the Green New Deal

Three young women holding climate action signs

Students joined more than 200 other grassroots activists for a lobby day at the General Assembly on Tuesday. Photo Ivy Main

Climate and energy activists have been pinning their hopes on the 2020 legislative session to produce a framework for transitioning our economy to 100 percent carbon-free energy.

After years of talking big but delivering little in the way of carbon reductions and clean energy, the General Assembly is under pressure to finally deliver.

Much of the initial focus and discussion so far has been on two very different omnibus bills, the Clean Economy Act and the Green New Deal Act. But dozens of other bills also aim to reform Virginia energy law in ways both big (breaking up the monopolies) and small (clarifying HOAs’ abilities to regulate solar panels) — and everything in between (removing barriers to customer solar, taxing fossil fuel investments).

In the coming days I’ll post summaries of many of these bills. But for now, let’s take a look at the two omnibus bills that have energized so many activists. Both have their strong points; both would benefit from strengthening amendments. And both are guaranteed to be better than anything Dominion will put forward in the coming days, if rumors of such a bill prove correct.

The Clean Economy Act

HB1526 (Del. Rip Sullivan, D-Fairfax) and SB710 (Sen. Jennifer McClellan, D-Richmond) are the Clean Economy Act put forward by a coalition of renewable energy industry and environmental groups. This is a massive bill, running to 37 pages and covering diverse aspects of the electric sector, and yet it is also surprisingly restrained in its ambitions.

The CEA’s goal is a zero-carbon electricity supply by 2050, a goal that allows nuclear energy to keep its role in the mix, and also one that, after an initial kick, requires a ramp-up of renewable energy of only 3% per year from 2021 to 2050. Utilities also must achieve energy efficiency savings that start slow and creep upwards to a top rate of 2% per year in 2027; utilities generally can’t build new generation unless they first meet the efficiency targets.

The very modest pace of the required investments in renewable energy and efficiency leaves no room for utilities to argue that the targets cannot be met or will cause economic pain. On the contrary, critics can justly complain they are too easy. On the other hand, the bill has lots of elements utilities still won’t like, including an energy storage mandate, community solar, net metering reforms and a limited moratorium on new fossil fuel generation.

The bill includes provisions for joining the Regional Greenhouse Gas Initiative to reduce statewide electric sector carbon emissions 30% by 2030, in accordance with DEQ’s regulations finalized last year. The state would auction carbon allowances, with 50% of proceeds funding energy efficiency programs for low-income, disability, veteran and elderly residents; 16% going to energy efficiency measures on state and local property; 30% for coastal resilience; and 4% for administrative costs.

The renewable portfolio standard provisions look more complicated than they are, but even so, understanding what’s going on is not a job for the meek. First off, note that the RPS only applies to “total electric energy,” which does not mean, you know, total electric energy. The code defines the term to mean total electric energy minus electricity produced by nuclear power. Since nuclear provides about 30% of Virginia’s electric generation, that means the RPS percentages look 30% bigger than they really are. (This is a neat trick Dominion devised years ago to make our voluntary RPS sound more meaningful. People fell for it, which is why our voluntary RPS is widely described as targeting 15% renewable energy by 2025 instead of about 10%.)

Thus, the nominal RPS goal of 41% by 2030 does not mean that Virginia would get 41% of its electricity from renewable energy by 2030. The true percentage would be 41% of 70%, or — oh Lord, now I have to do math — somewhat under 30%.

Not incidentally, 30% by 2030 is the renewable energy target Governor Ralph Northam set in his Executive Order 43 back in September, and that squares pretty well with Dominion’s building plans. (The CEA, however, strives mightily to ensure that less expensive independent developers get a good share of the business.)

The drafters of the Clean Economy Act also chose not to change the code’s existing kitchen-sink definition of renewable energy, foregoing an opportunity to fix the mischief Dominion has got up to lately with what I call its Green Power for Suckers program and the Great Thermal REC Boondoggle. Instead, the RPS provisions exclude biomass and sometimes waste, then limit which specific technologies qualify for each tier of the RPS. The result is that even without changing the definition of renewable energy, biomass and thermal RECs have no place in the CEA mix, municipal waste incineration is limited to existing facilities and old hydro dams will cease to qualify when their contracts run out.

The system of tiers also allows the CEA to prioritize among technologies and project sizes.

  1. Offshore wind has its own tier beginning in 2027, as well as detailed instructions for how it will be developed.
  2. Tier II covers distributed (under 3 MW) Virginia-based wind, solar and anaerobic digestion (presumably meaning biogas from things like pig manure, reflecting Dominion’s deal with Smithfield Foods). This tier is divided into sub-tiers that ensure smaller projects are represented, and 10% of each tier is supposed to be sourced from projects serving low-to-moderate income persons. This tier begins at 3% of the RPS total in 2021, increasing to 9% in 2028, and then bouncing around strangely between 7 and 9% thereafter.
  3. Tier III can be met with Virginia wind, solar, wave, tidal, geothermal or energy from waste (poorly defined, but with a limit on the number of eligible RECs that, I’m told, just covers the output of existing waste incinerators in Virginia), or landfill gas (also from existing landfills and with a limit). These projects don’t have a size limit. Utilities are instructed to issue annual requests for proposals to acquire Tier III resources. Tier III begins at 30% of the RPS, gets as high as 43% in 2030, and then declines as offshore wind in Tier I takes a greater share.
  4. Tier IV can be met with renewable energy certificates from wind, solar and some hydro sources inside or outside Virginia, but within the PJM, the regional transmission organization that coordinates the electric grid in all or parts of 13 states, including Virginia, and the District of Columbia. Tier IV starts at 38% of the RPS total, goes as high as 51% in 2023, and then declines by fits and starts until it is less than 20% in the out years.
  5. The fifth tier consists of the old hydro RECs from PJM with existing purchase contracts. These begin at a whopping 29% of the total but decline rapidly to 6% in 2023 and even less thereafter.

Solar installers who focus on Virginia may be dismayed by the modesty of the in-state requirements. Only Tier II serves distributed generation, and all its sub-tiers and low-income provisions don’t make up for the fact that distributed generation must account for less than 0.3% of total statewide demand in 2021 (3% of the initial 14% goal, adjusted downward for nuclear). This may well be less than the amount of net-metered solar we will have then anyway, with or without the CEA. By 2030, distributed renewables would still account for less than 2.5% of total generation in Virginia, a far cry from the 25% or more that studies have shown is possible.

Meanwhile, Tiers IV and V allow RECs from utility-scale facilities located anywhere within PJM, accounting for more than half the RPS total for the first several years. If utilities choose to buy these out-of-state RECs instead of building new renewable energy in Virginia for this tier, ratepayers will be paying for economic development and jobs in other states, rather than supporting clean energy jobs at home.

(As I’ll describe below, this is an even bigger drawback of the Green New Deal Act.)

Defenders of the PJM RECs approach cite market efficiency and cost; RECs from states that don’t have RPS laws tend to be cheap, and allowing them to qualify for our RPS means projects will get built wherever it is cheapest to do it. That justifies allowing a small percentage of PJM RECs, but not making those RECs the centerpiece.

The CEA already has another, and better, cost-containment measure. If prices of RECs go too high, utilities have an option of paying into a fund administered by the state Department of Mines, Minerals and Energy instead. The money will be used for energy efficiency and renewable energy projects in Virginia benefiting mainly low-income residents. This “deficiency payment” alternative is a standard feature of other states’ RPS laws; it provides a critical cost cap while not letting utilities off the hook.

The CEA also includes community solar provisions and removal of certain barriers to net metering. It raises the net metering cap to 10%, raises the commercial size cap to 3 MW, removes all caps on third-party power purchase agreements, eliminates standby charges on residential and agricultural customers, and allows customers to install facilities large enough to meet 150% of their previous year’s demand. (These net-metering provisions intentionally duplicate five of the eight provisions of the Solar Freedom legislation, HB572, SB710 and others.)

In addition to all of this, the CEA includes a mandate for 2,400 megawatts of energy storage by 2035, with interim targets beginning with 100 MW by the end of 2021.

And just in case Dominion thinks that somehow all this still leaves room for any new fossil fuel plants, the CEA ends with a one-year moratorium on the permitting of any new carbon-emitting generating units that an investor-owned utility might want to build, until the government produces a report with recommendations for achieving a carbon-free electric sector by 2050 at least cost to ratepayers.

If I’d been writing this bill, I would have accelerated the timeline and focused the RPS more on Virginia projects, including rooftop solar. But as a framework this is still a strong bill, and it’s possibly the best we can do this year.

The Green New Deal

HB77 (Del. Sam Rasoul, D-Roanoke) is the Green New Deal Act. Its major features include a moratorium on any new fossil fuel infrastructure; a very aggressive timetable for 100% renewable energy by 2036; energy efficiency standards and a mandate for buildings to decrease energy use; low-income weatherization; job training; a requirement that companies hire workers from environmental justice communities; and assistance for workforce transition for fossil fuel workers.

The GND looks almost nothing like the Clean Energy Act. Its moratorium on new fossil fuel infrastructure is far broader than that in the CEA, covering not just electric-generating plants but also pipelines, refineries, import and export terminals and fossil fuel exploration activities.

It directs DMME to develop a climate action plan that addresses mitigation, adaptation and resiliency, supports publicly-owned clean energy and incorporates environmental justice principles. Forty percent of funds spent under the plan are to be targeted to low-income communities and communities of color.

The GND’s energy efficiency mandates are tougher than the CEA’s, requiring savings of 2.4% per year beginning immediately. These savings will be achieved not just by weatherizing buildings, upgrading heating and cooling, etc., but also by dramatically improving new buildings and requiring installation of rooftop solar wherever feasible.

DMME is also required to set performance benchmarks for scholarships, low-interest loans, job training programs and renewable energy projects to serve EJ communities (“until such date that 100 percent of the energy consumed in such communities is clean energy”), as well as a mandate that 50% of the workforce for energy efficiency and clean energy programs come from EJ communities.

(We should pause here for a reality check. We’re talking about Virginia, where many excellent programs that are already on the books currently go unfunded, and underinvestment in education and social services means companies can’t find enough qualified workers as it is.)

With all its aims of putting the energy transition on steroids, the Green New Deal also has a surprisingly weak RPS. In fact, it appears utilities would not have to build renewable energy projects in Virginia at all — or for that matter, close any fossil fuel plants.

The bill doesn’t actually say so, but it appears to contemplate that the very fast ramp-up of renewable energy to 80% by 2030 can be achieved by utilities buying renewable energy certificates from other states. I’m told Delegate Rasoul has confirmed this is his intention. There is no requirement for utilities to buy from in-state producers.

There is a practical reason for this: given how far behind Virginia is in developing wind and solar, allowing utilities to buy out-of-state RECs is probably the only way to meet an 80% by 2030 target. These RECs are traded on the open market; that makes it easy for utilities to comply, and eliminates reliability concerns because utilities can continue to run their existing fossil fuel plants as usual.

But there’s the rub: the bill contains no requirement to build wind and solar in Virginia, and utilities can run their fossil fuel plants as usual. That’s not the energy transition a lot of people are looking for.

The strange case of thermal RECs

Renewable energy advocates are hoping that 2020 will be the year Virginia finally begins to make wind and solar the centerpiece of its energy planning, rather than a grudging add-on. The General Assembly will consider at least two bills that adopt a mandatory renewable portfolio standard as well as legislation to lower carbon emissions and open the private market to greater investments in renewables.

But good intentions don’t always produce effective legislation. Sloppy drafting causes unanticipated consequences. Minor amendments offered by an opponent produce major consequences only the opponent anticipated.

For a case in point, let’s consider Virginia’s existing, voluntary RPS. Worse than useless, it has enabled all kinds of mischief by defining “renewable energy” to include things that do not contribute carbon-free renewable power to the grid

As currently written, our renewable portfolio standard never has been, and never will be, responsible for a single electron of wind or solar energy. That means that any bill that takes as its starting point the definition that currently exists in the Virginia Code, or even uses the term “renewable energy” without narrowly defining it, risks failing right out of the gate.

Part of the problem is biomass. But a much greater problem is one that has been largely overlooked, mainly because no one understands it. It’s called “thermal” energy, and it is a major piece of mischief all by itself.

Added to the statute in 2015, thermal renewable energy certificates quickly became the primary means for Dominion Energy Virginia to meet its RPS targets, after counting the energy from the utility’s own hydro and biomass facilities and those from which it buys power under contract.

The thing is, no one seems to know where thermal RECs come from. The code offers three possibilities. One is “the proportion of the thermal . . . energy from a facility that results from the co-firing of biomass.” Another is “the thermal energy output from (i) a renewable-fueled combined heat and power generation facility that is (a) constructed, or renovated and improved, after January 1, 2012, (b) located in the Commonwealth, and (c) utilized in industrial processes other than the combined heat and power generation facility.” Finally, there is a tiny (and mainly unused) category for solar hot water systems and swimming pool heating.

The second definition, added to the code in 2015, is so specific that it was clearly written with a particular industrial facility or facilities in mind. From that definition, we can determine that thermal RECs don’t represent renewable electricity added to the grid.

What no one but Dominion seems to have known was that thermal RECs would instantly become the leading category for RECs, and one that would eliminate any chance for wind or solar to ever compete for RPS dollars in Virginia.

The Virginia statute is an oddity. “Thermal” is not a recognized category in the regional registry for purchase and sale of RECs among utilities and voluntary buyers (known as PJM GATS). I also haven’t found another state RPS program that includes thermal in its definition of renewable energy, aside from solar thermal.

A year ago I asked Dominion what kind of industry supplies thermal RECs; I was promised an answer, but none came. So a week ago I asked the staff of the State Corporation Commission. They don’t know either.

Every year in November, Dominion submits a report to the SCC about its renewable energy activities, including information the law requires about a utility’s RPS program. The reports are available on the SCC website.

None of the reports include any discussion of thermal RECs, including the report submitted covering 2015, the first year these RECs were allowed. The reports don’t indicate where thermal RECs come from, what kind of industrial process produces them, or whether there might be a lot more available that could supply Dominion in the future as RPS goals increase.

However, by law Dominion has to provide other information that, read together, allows us to deduce a few bits of information about thermal RECs, and about their role in the RPS:

  • They are generated by one or more Virginia facilities.
  • The facility or facilities were placed in service this decade, confirming that we are talking about that second meaning of thermal.
  • The facilities are not owned by Dominion.

All or almost all the RECs Dominion purchases are thermal RECs. Thermal RECs make up all or nearly all the energy and RECs Dominion has banked to use in future years. (Virginia law allows a utility to hang on to a REC for up to five years after it was generated.) If these were wind and solar RECs instead of thermal RECs, the value of the banked RECs would exceed $40 million, even at the low REC prices currently prevailing in the PJM marketplace.

I compiled the information from these reports into the table below. The 2019 filing, containing information for 2018, also gives us a view into the current year. It states: “The company began 2019 with banked renewable energy and RECs of 4,252,354 MWh and expects to have a bank of approximately 4,113,477 MWh of renewable energy and RECs toward future RPS targets at year-end 2019.”

Source: Virginia State Corporation Commission. (Ivy Main)

As you can see, Dominion has enough RECs banked that, when added to generation from Dominion’s own or contracted renewable energy facilities, Dominion has no need to purchase any RECs from any source until 2022 (when it still won’t need much).

Dominion doesn’t report what it paid for thermal RECs, but they are undoubtedly cheaper than any other qualifying source. One reason: with no competitive market for thermal RECs, Dominion is almost certainly the only buyer. In antitrust parlance, the term for this is “monopsony,” a word I hope you will now want to work into your dinner table conversation.

Monopsony power includes the power to set the price of a product, because the seller has no one else to sell to. In the case of thermal RECs, we don’t know who the seller is, but clearly its primary business is not the production of thermal RECs for sale. In fact, the money it gets for these RECs likely represents a windfall, and it is happy to get anything that covers its administrative cost in documenting its use of thermal energy.

On the other hand, Dominion doesn’t have to be overly stingy, since Virginia law allows the utility to pass on to ratepayers the cost of purchasing RECs for the RPS. One can imagine Dominion CEO Thomas Farrell having a nice dinner with the CEO of the corporation owning the industrial facility that uses the thermal energy, and together deciding what Virginia consumers will pay for these RECs. As long as it is less than the cost of other RECs available to Dominion, who will complain?

Whatever the price is, a monopsony price of thermal RECs will be less than the price of wind and solar RECs in Virginia, because wind and solar have a competitive market and buyers who are willing to pay more.

For years, critics have complained that the voluntary RPS is a failure for every purpose except greenwashing. But with no appetite for reform in the General Assembly, it’s been easy to ignore how the definition of renewable energy was expanding like a slime mold escaping its petri dish.

This year, though, the reformers are on the move. One or more bills requiring utility investments in renewable energy seem likely to gain traction. Advocates will be keeping their fingers crossed—and reading the definitions.

 

This article was originally published in the Virginia Mercury on January 7, 2020.

 

What’s not to like about biomass? Deforestation, pollution and overpriced power.

What if you could get your electricity from a fuel that destroys forests, produces more air pollution than coal, and is priced higher than alternatives?

“Wow, sign me up!” you would not say, because as a sane person you don’t like deforestation, pollution and overpriced power.

Also, because you are not Dominion Energy Virginia. Dominion burned wood at one power plant from 1994 until last year; converted three small coal plants to wood-burning in 2013; and burns wood along with coal at its Virginia City coal plant. This “biomass” energy makes up about one percent of the electricity Dominion sells to Virginia ratepayers, according to its most recent IRP.

Biomass counts as renewable under the Virginia Code, so in theory it can also be used to supply customers who are willing to pay extra for renewable energy. Lots of people want renewable energy these days. Unfortunately for Dominion, they want clean, non-polluting renewables like wind and solar. No one is clamoring for biomass.

That’s especially true because biomass costs more than wind or solar, not to mention more than fossil sources. Who’s going to buy dirty energy when they can get clean energy for less money?

We recently learned just how much more expensive biomass is when the State Corporation Commission held a hearing on Dominion’s latest effort to get a renewable energy tariff approved. Rider TRG combines wind, solar and hydro with biomass, originally including biomass burned at the Virginia City coal plant.

Pretty much everyone hates the proposed tariff, as the Virginia Mercury reported. Counties looking to buy renewable energy objected. Corporate customers said they wouldn’t buy it.

So, in a halfway step meant to mollify opponents, Dominion offered to remove the Virginia City coal plant from the list of sources, while leaving in the rest of the biomass facilities.

Here’s the interesting part: taking Virginia City out made the program more affordable. Having biomass as part of the renewable energy mix, it turns out, doesn’t save money for participants; it costs extra.

In that case, you might say (again, you being a sane person), Dominion ought to remove all the biomass from Rider TRG and save participants even more money, while making it a program people might actually want.

And indeed, the SCC staff calculated that if all the biomass were to be removed, it would reduce the cost by almost two-thirds. For average residential customers using 1,000 kilowatt-hours per month, removing biomass from Rider TRG would mean the added cost of making all their power renewable would fall from $4.21 per month to $1.78.

A no-brainer, right? Making the program both cleaner and more affordable would make it more popular and spur construction of new renewable energy facilities.

Dominion refused. Having the program be successful, you see, is not the point. As I wrote this summer, the purpose of Rider TRG isn’t to offer a product people want to buy, it’s to prevent anyone else from selling renewable energy. If the commission approves Dominion’s tariff, under state law competitors will be locked out of the Virginia market.

If the biomass turns out to be a kind of poison pill for the program, so that no one signs up, that really doesn’t matter to Dominion because, again, the whole point of Rider TRG isn’t to attract customers, it’s to kill competition.

The SCC hasn’t ruled on the program yet. Post-hearing briefs are due Dec, 20, so we can expect an order in the case early next year.

But why biomass?

At this point you may be asking yourself why Dominion chose to invest in all those biomass plants in the first place. The answer is subsidies. During its early years, Virginia’s voluntary renewable portfolio standard rewarded Dominion with tens of millions of dollars annually as a bonus for meeting the renewable energy goals set out in the law. Section 56-576 of the Virginia Code very helpfully defines renewable energy to include “biomass, sustainable or otherwise, (the definitions of which shall be liberally construed).”

Fun fact: as recently as 2008, only “sustainable biomass” qualified as renewable energy. The definition was altered in 2009, at the same time it was expanded to cover biomass burned in a coal-fired power plant such as the one Dominion had just announced it would build.

The RPS bonus money boondoggle came to an end in 2013 when public outrage reached a fever pitch. Then-Attorney General Ken Cuccinelli reached a deal on legislation to repeal the bonus money provisions of the statute. (Utilities could still recover the costs of the RPS program from ratepayers.) Left intact was everything else, including defining renewable energy as “biomass, sustainable or otherwise.”

Liberally construing “sustainable or otherwise” has not been good for southeastern forests. Dogwood Alliance and Southern Environmental Law Center document widespread clear-cutting, loss of forests, and replacement of mixed hardwood forests with pine plantations. As these groups and others have also pointed out, burning wood produces more pollution than coal and isn’t carbon-neutral in the time frame that matters for the climate pickle we’re in.

Dominion is not the worst offender; pride of place belongs to wood pellet manufacturer and exporter Enviva, which just received a permit to expand its Virginia facility in Southampton.

Dominion also isn’t the only Virginia utility to have invested in burning trees. Northern Virginia Electric Cooperative provides its customers with electricity from a biomass plant in South Boston. NOVEC doesn’t have an RPS to meet, so it sells renewable energy certificates to Maryland utilities. It’s a lousy deal for the Maryland residents who get higher bills and no clean energy to show for it, but meanwhile NOVEC brags about its “environmentally friendly” plant.

So now what?

There are really two questions when it comes to burning trees for fuel: one, should government give it preferential treatment; and two, should an electric utility be doing it at all?

The General Assembly will almost certainly consider legislation this year requiring utilities to increase the proportion of electricity they sell that comes from renewable energy. If biomass is allowed to qualify, the result will be less new wind and solar and less progress towards a carbon-free grid. The lesson from other states that have renewable energy mandates is simple: states that allow junk get junk. (Here’s looking at you, Maryland.)

But as we’ve seen, biomass can’t compete with other energy sources on cost if it doesn’t get subsidies. Dominion can follow NOVEC’s lead in selling RECs to Maryland or other states that haven’t wised up yet, but REC payments won’t make up the cost difference between biomass and other fuels.

Worse—or better, depending on your point of view—other states may decide not to support the biomass racket. Maybe Dominion could still sell the renewable energy certificates (RECs) to the ultra-cheap Green Power for Suckers program that the SCC approved a couple weeks back. But selling cheap RECs to chumps would net the company only—ahem—chump change.

In fact, the SCC should take a hard look at biomass when Dominion files its next Integrated Resource Plan. Requiring the utility to get out of the wood-burning business wouldn’t just clean the air and protect forests, it could be a smart way to save money for customers.

 

This article originally appeared in the Virginia Mercury on December 2, 2019. 

Green Power for Suckers program wins regulatory approval

Trees clearcut.

Don’t think of biomass as destroying forests, think of it as a way to feel good about subsidizing pollution. Photo by Calibas, Creative Commons.

Virginia’s State Corporation Commission (SCC) has approved Dominion Energy Virginia’s request to offer a new product to electric utility customers who want to buy renewable energy at a discount but lack the knowledge to understand when they are being taken for chumps.

“Rider REC” is an ultra-cheap version of the company’s Green Power Program (itself of questionable value). For less than a buck a month on their electric bills, customers will be able to buy renewable energy certificates that cost Dominion next to nothing because no one else wants them. And for good reason: these are the dregs of the renewable energy category.

You won’t find any wind or solar in Rider REC, but you might find paper mill waste, trees burned after clear-cutting, or century-old hydro dams—all officially “renewable” under the generous provisions of Virginia law. Dominion will scrounge up these old and dirty leftovers, package them up, and put a green bow on them.

“Caveat emptor,” says the SCC with a shrug. The SCC seems to think anyone dumb enough to pay extra voluntarily deserves whatever they get.

This is not the first time the SCC has shown disregard for eco-conscious consumers. Four years ago it gave Dominion the nod for a program the company was calling “community solar,” which wasn’t actually selling any solar and had nothing to do with communities. Dominion never did roll out that program, perhaps because there was no way to market it without courting accusations of consumer fraud. But it had the SCC’s blessing for it!

(In case you are confused: this was before the company’s most recent iteration of community solar, also approved, also not actually community solar, and which we are still waiting for. Dominion executives could probably do with a thesaurus.)

In response to concerns that customers wouldn’t know what they are getting, the SCC order did impose one labeling requirement. Dominion’s marketing materials must “clearly identify the source of the RECs available for purchase under Rider REC (i.e., the less expensive of PJM Tier II RECs or national Green-e eligible RECs).”

Perhaps Dominion will even tell buyers what those things mean, though the SCC doesn’t seem to be saying it has to. In the interests of clarity, Dominion could explain that “PJM Tier II RECs” translates to “some stuff we found behind the refrigerator and think might still be edible.” But it probably won’t.

That’s because, just as with the old community solar thing, the problem is that if buyers understand what’s in it, they won’t be buyers.

 

This article was originally published in the Virginia Mercury on November 8, 2019. 

Governor Northam’s Executive Order, Dominion Energy’s about-face on offshore wind: is Virginia off to the clean energy races?

Man at podium

Arlington County Board Chair Christian Dorsey speaking to clean energy supporters on September 21, following the Board’s adoption of its new Community Energy Plan. Arlington’s plan would produce a carbon-free grid 15 years earlier than Governor Northam’s plan, while also tackling CO2 emissions from transportation and buildings.

A single week in September brought an unprecedented cascade of clean energy announcements in Virginia. On Tuesday, September 24, Governor Northam issued an Executive Order aimed at achieving 30 percent renewable energy by 2030 and 100 percent carbon-free energy by 2050, and with near-term state procurement targets.

On Thursday, Dominion Energy announced it would fully build out Virginia’s offshore wind energy area by 2026, in line with one of the goals in the Governor’s order.

Then, Saturday morning, the Democratic Party of Virginia unanimously passed resolutions endorsing the Virginia Green New Deal and a goal of net zero carbon emissions for the energy sector by 2050.

Saturday afternoon, Arlington became the first county in Virginia to commit to 100 percent renewable electricity by 2035, and economy-wide carbon neutrality by 2050.

So is Virginia off to the clean energy races? Well, let’s take a closer look at that Executive Order.

The governor’s order sounds great, but how real are its targets?

Executive Order 43, “Expanding access to clean energy and growing the clean energy jobs of the future,” directs the Department of Mines, Minerals and Energy (DMME) and other state agencies to “develop a plan of action to produce 30 percent of Virginia’s electricity from renewable energy sources by 2030 and one hundred percent of Virginia’s electricity from carbon-free sources by 2050.”

The difference between “renewable energy” and “carbon-free” sources is intentional. The latter term is a nod to nuclear energy, which provides about a quarter of Virginia’s electricity today. Keeping Dominion’s four nuclear reactors in service past 2050 may not prove feasible, economical or wise, but the utility wants to keep that option open.

The order also doesn’t define “renewable energy.” It talks about wind and solar, but it doesn’t specifically exclude carbon-intensive and highly-polluting sources like biomass and trash incinerators, which state code treats as renewable. Dominion currently meets Virginia’s voluntary renewable energy goals with a mix of old hydro and dirty renewables, much of it from out of state. Dominion will want to keep these subsidies flowing, especially for its expensive biomass plants, which would undermine the carbon-fighting intent of the order.

Finally, there is the question whether all of the renewable energy has to be produced in Virginia. Old Dominion Electric Cooperative, which supplies electricity to most of the member-owned cooperatives in the state, buys wind energy from outside Virginia. Surely that should count. But what if a Virginia utility just buys renewable energy certificates indicating that someone, somewhere, produced renewable energy, even if it was consumed in, say, Ohio? Those had better not count, or we’ll end up subsidizing states that haven’t committed to climate action.

What will DMME’s plan look like?

In describing what should be in the action plan, Northam’s order largely recites existing goals and works in progress, but it also directs DMME and the other agencies to consider going beyond existing law and policy to achieve specific outcomes:

  • Ensure that utilities meet their existing commitments to solar and onshore wind energy development, including recommending legislation to reduce barriers to achieving these goals. These goals include 500 MW of utility-owned or controlled distributed wind and solar. Customer-owned solar is not mentioned.
  • Make recommendations to ensure the Virginia offshore wind energy area is fully developed with as much as 2,500 MW of offshore wind by 2026.
  • Make recommendations for increased utility investments in energy efficiency, beyond those provided for by the passage of SB 966 in 2018, the Grid Modernization Act.
  • Include integration of storage technologies into the grid and pairing them with renewable generation, including distributed energy resources like rooftop solar.
  • Provide for environmental justice and equity in the planning, including “measures that provide communities of color and low- and moderate-income communities access to clean energy and a reduction in their energy burdens.”

Can the administration do all that?

Nothing in this part of the order has any immediate legal effect; it just kicks off a planning process with a deadline of July 1, 2020. Achieving some of the goals will require new legislation, which would have to wait for the 2021 legislative session.

That doesn’t mean the governor will sit on his hands until then – delay is the enemy of progress — but it could have the effect of slowing momentum for major climate legislation in 2020.

Cynics, if you know any, might even suggest that undercutting more aggressive Green New Deal-type legislation is one reason for the order.

A second part of Northam’s order, however, will have immediate effect, limited but impressive. It establishes a new target for state procurement of solar and wind energy of 30 percent of electricity by 2022, up from an 8 percent goal set by former Governor Terry McAuliffe. This provision will require the Commonwealth to negotiate amendments to the contract by which it buys electricity for state-owned facilities and universities from Dominion. The order also calls for at least 10 MW annually of power purchase agreements (PPAs) for on-site solar at state facilities, and requires agencies to consider distributed solar as part of all new construction.

State facilities will also be subject to new energy savings requirements to reduce state consumption of electricity by 10 percent by 2022, measured against a 2006 baseline, using energy performance contracting.

These provisions do for the state government what the action plan is intended to do for Virginia as a whole, but 8 years faster and without potential loopholes.

Thirty percent by 2030? Gee, where have we heard that before?

Just this spring, Virginia’s Department of Environmental Quality finalized regulations aimed at lowering carbon emissions from Virginia power plants by 30 percent by 2030. These numbers look so similar to Northam’s goal of 30 percent renewable energy by 2030 that it’s reasonable to ask what the order achieves that the carbon rule doesn’t. (This assumes the carbon regulations take effect; Republicans used a budgetary maneuver to stall implementation by at least a year.)

The answer goes back to the reason Dominion opposed the carbon rule. Dominion maintains—wrongly, says DEQ and others—that requiring lower in-state carbon emissions will force it to reduce the output of its coal and gas plants in Virginia and buy more power from out of state. That, says Dominion, would be bad for ratepayers.

As the company’s August update of its Integrated Resource Plan showed, Dominion would much prefer a rule requiring it to build more stuff of its own. As it turns out, that would be even more expensive for ratepayers, but definitely better for Dominion’s profitability.

So legislation to achieve Governor Northam’s renewable energy goals would take the pain out of the carbon regulations for Dominion. Whether it might also lower carbon emissions beyond DEQ’s 30 percent target remains to be seen.

The 2050 carbon-free goal, on the other hand, goes beyond anything on the books yet. Dominion’s corporate goal is 80 percent carbon-free by 2050, and it has no roadmap to achieve even that.

Is there anything in the order about pipelines?

No. In fact, there is no mention of any fossil fuel infrastructure, though shuttering coal and gas plants is the main way you cut carbon from the electricity supply.

That doesn’t mean Northam’s order leaves the Mountain Valley and Atlantic Coast pipelines in the clear. If Dominion joins Duke Energy in its pledge to go to zero carbon by 2050, the use of fracked gas to generate electricity in Virginia and the Carolinas has to go down, not up, over the coming decades (Duke’s own weird logic notwithstanding). As word gets around that Virginia is ditching fossil fuels, pipeline investors must be thinking about pulling out and cutting their losses.

What about Dominion’s offshore wind announcement?

I saved the best for last. For offshore wind advocates like me, Dominion’s announcement was the really big news of the week: it’s the Fourth of July, Christmas and New Years all at once. Offshore wind is Virginia’s largest long-term renewable energy resource opportunity, and we can’t fully decarbonize without it.

Dominion has taken a go-slow approach to offshore wind ever since winning the right to develop the federal lease area in 2013. Until this year, it refused to commit to anything more than a pilot project. The two, 6-MW turbines are currently under construction and will be installed next summer.

Then in March, Dominion CEO Tom Farrell told investors his company planned to build one commercial offshore wind farm, of unspecified size, to be operational in 2024. In its Aug. 28 resource plan update filed with the state regulators, Dominion Energy Virginia included for the first time an 880-MW wind farm, pushed back to 2025.

A mere three weeks later, the plan has changed to three wind farms, a total of 220 turbines with a capacity of 2,600 MW, with the start date moved up again to 2024, and all of them in service by 2026, exactly Northam’s target (except his was 2,500 MW).

Certainly the case for developing the full lease area has been improving at a rapid clip. Costs are falling dramatically, and it appears Dominion expects to maximize production by using massive 12 MW turbines, which did not even exist until this year.

But if the situation has changed that dramatically from August to September, all I can say is, I can’t wait to see what October brings.

Maybe it will bring answers to questions like who will build these wind farms, who will pay for them, and how Dominion expects to meet this accelerated timeline. As Sarah Vogelsong reports, several northeastern states have wind farms slated for development in the early-to-mid-2020s, too. Industry members are already worried about bottlenecks in everything from the supply chain to installation vessels, workforce training and the regulatory approval process.

That is to say, we’re coming to the party pretty late to expect good seats. But hey, it’s going to be a great party, and I’m glad we won’t miss it.

This article originally appeared in the Virginia Mercury on September 27, 2019.

Fairfax County plans a historic solar buy—if Dominion Energy doesn’t stand in the way

Worker installing solar panels on a roof.

A worker installs solar panels at Washington & Lee University. Photo courtesy of Secure Futures LLC.

In June, Fairfax County announced it was seeking proposals from solar companies to install solar at up to 130 county-owned facilities and schools, with another 100 sites to be considered for a later round. The request for proposals (RFP) covers solar on building roofs, ground-mounted solar and solar canopies over parking lots.

This massive solar buy could add as much as 30-40 megawatts of solar, according to one industry member’s calculation. This would easily triple the amount of solar installed to date in the entire NoVa region. What’s more, Fairfax County’s contract will be “rideable” so that other Virginia localities can install solar using the same prices and terms.

“It’s hard to overstate how significant a move this is,” says Debra Jacobson, an energy lawyer who serves on the county’s Environmental Quality Advisory Council. “It’s not just the largest solar buy by a local government in Virginia. It also opens the door for other Virginia counties and cities to buy solar because it makes the process simple and straightforward.”

Jacobson says approximately 15 solar companies attended a bidder’s conference hosted by Fairfax County, indicating strong interest. The county intends to select a contractor by early fall.

One problem stands in the way: Virginia law currently places an overall limit of 50 MW on projects installed in Dominion territory using third-party power purchase agreements (PPAs), the primary financing mechanism for tax-exempt entities.

Even without Fairfax County’s projects, the solar industry warns the cap will likely be met by the end of this year, as schools, universities, churches and other customers across Virginia sign PPAs at an accelerating rate.

The solar industry is asking the State Corporation Commission for action to keep the market alive. Secure Futures LLC, a Staunton-based solar developer, submitted a letter to the SCC on June 24 asking the commission to raise the program cap from 50 MW to 500 MW in Dominion territory and 7 to 30 MW in Appalachian Power territory and to increase the size limit for individual projects from 1 MW to 3 MW.

PPAs allow customers to have on-site solar installed with no upfront cost; the customer pays only for the electricity the solar array produces, at a price that is typically below the price of electricity purchased from the utility. It’s an especially critical tool for cash-strapped local governments and school systems, letting them save taxpayer money while lowering their carbon footprint. Every kilowatt-hour they get from solar replaces electricity they would have to buy from the grid, which in Virginia still comes almost entirely from fossil fuels and nuclear.

For-profit monopoly utilities like Dominion Energy Virginia and Appalachian Power don’t like losing sales when customers generate their own electricity. Virginia’s customer-owned electric cooperatives negotiated legislation this year to remove PPA barriers for non-profits in their territories, but Dominion and APCo didn’t sign on. Both utilities fought Solar Freedom legislation and other bills that would have lifted the PPA cap, claiming there was still plenty of room for projects under the 50 MW cap.

But there may be a simple solution — if the utilities don’t fight it. The legislation that created the PPA program in 2013 directs the SCC to review it every two years beginning in 2015, and to “determine whether the limitations [on the program size and project sizes] should be expanded, reduced, or continued.”

The SCC has never opened a case docket or consulted stakeholders in any previous review of the program — but no one seems to have asked until now. Secure Futures’ letter requests that the SCC open a public docket for this year’s review and consult with stakeholders, including the solar industry and customers.

In his letter, Secure Futures’ CEO Tony Smith notes that Virginia remains well behind North Carolina and Maryland on solar installations, solely for reasons of state policy. Installations using PPAs also lagged until the past year, but are now expanding “at an exponential rate,” according to Secure Futures, with notifications filed for almost 20 MW of projects as of June 12. This number does not include the Fairfax County projects or many others that are still in the early stages of development.

Other solar developers have also asked the SCC to lift the PPA cap. Ruth Amundsen, manager of the Norfolk Solar Qualified Opportunity Zone Fund, told the SCC in a July 20 letter that her fund has identified $117 million of potential solar sites in the Norfolk and Virginia Beach area. The fund brings in investors and installs solar on businesses and non-profits in Virginia Qualified Opportunity Zones, which are low income census tracts that offer tax benefits for investors, at no upfront cost to the customer.  It also hires residents of the Opportunity Zones as solar installers, training them and providing employment.

But, Amundsen’s letter notes, “Without PPAs, none of this is possible. If the PPA cap remains at 50MW, we cannot in good conscience advise these investors to invest in solar in the Virginia QOZs, as there would be no feasible financing method once the cap is reached.”

Amundsen also wants the ability to use PPAs for installation on private homes, which is currently not allowed under the terms of the PPA program in Dominion territory. “The original intent of the Norfolk Solar QOZ Fund was to mitigate the energy burden of low-income home owners.  But because of the current limitation on Power Purchase Agreements (PPAs) in Virginia, we cannot install on private homes via a PPA.  Removal of that limitation, and clarification that PPAs are legal with all customers, would allow us to better serve the most affected residents as far as crushing utility bills.”

 

This article originally appeared in the Virginia Mercury on August 1, 2019.