2018 Guide to Wind and Solar Policy in Virginia

[A downloadable PDF of this guide is available here.]

Introduction

Advocates for wind and solar finally begin to feel cautiously optimistic about the prospects for clean energy in Virginia. Prices for wind and solar have dropped to the point where the question is no longer whether they can compete with fossil fuels, but whether fossil fuels can compete with them. Support for renewable energy is high in the General Assembly, new solar projects are popping up across the state, and interest in offshore wind is on the rise again, after a years-long nap.

Still, Virginia’s energy laws were written by and for monopoly utilities that are heavily invested in coal, gas and nuclear. The Virginia Code contains a thicket of barriers that protect utility profits from competition and limit the options of developers, consumers, local governments and businesses.

This survey of current policy is intended to help decision-makers, industry, advocates and consumers understand what options for wind and solar exist today, where the barriers lie, and what we could be doing to take fuller advantage of the clean energy opportunities before us.

A few disclaimers: I don’t cover everything, the opinions expressed are purely my own, and as legal advice it is worth exactly what you’re paying for it.

  1. Overview: Virginia making headway on solar, but still no wind
Virginia Maryland North Carolina W. Virginia Tennessee
Solar* 631.26 932.7 4,411.65 6.05 236.36
Wind** 0 191 208 686 29
Total 631.26 1,123.7 4,619.65 692.05 265.36

  Installed capacity measured in megawatts (MW) at the end of 2017. One megawatt is equal to 1,000 kilowatts (kW).

*Source: Solar Energy Industries Association **Source: American Wind Energy Association

Virginia installed almost 400 megawatts (MW) of solar last year, bringing the total at the end of 2017 to 631 MW, up from 238 at the end of 2016. This nudges us closer to Maryland, though it leaves us further behind North Carolina than ever.

Most of the Virginia solar to date has been installed to serve large tech companies, not the general public. This reflects the companies’ renewable energy commitments, their buying power, and their willingness to pursue new financing models that make the most of solar’s increasingly low cost.

Corporate demand will likely continue to drive the majority of Virginia installations in the near term, but Virginia utilities are starting to add solar to the resource mix that serves ordinary customers.

On the other hand, Virginia remains the only state in our 5-state neighborhood without a wind farm. To be fair, all 5 states have been stuck in the doldrums; an American Wind Energy Association update showed no new wind farms opening in any of them in 2017. That leaves Apex Clean Energy’s 75 MW Rocky Forge wind farm still in limbo; it received its permit more than a year ago and remains construction-ready whenever a buyer shows up.

Among the recent developments showing momentum for solar:

  • In 2017, Dominion Energy Virginia acknowledged for the first time that solar had become the cheapest form of energy in Virginia. In May of this year, a news source reported that the utility’s parent company, Dominion Energy, has given up on building any new combined-cycle (baseload) gas plants and will build only large solar plants, though the company proposes many more of the smaller gas combustion turbines.
  • A new law passed in 2018 (SB 966) puts 5,000 MW of utility wind and solar “in the public interest,” although this language is not a mandate.
  • The 2018 law also makes it in the public interest for utilities to develop up to 500 MW of distributed solar (some parts of the bill say just 50 MW).
  • Dominion’s 2018 Integrated Resource Plan (IRP) includes up to 6,400 MW by 2033 in most of the scenarios it modeled. The IRP is not binding, but it gives regulators and the public a look into how a utility plans to meet customer demand over a 15-year period.
  • Some rural cooperatives and municipal electric utilities in Virginia are now adding solar.
  • Solar projects keep getting bigger. A few years ago, a 20 MW solar farm was considered huge; today it is at the low end for utility-scale. In 2015 Amazon Web Services stunned us all by announcing an 80 MW facility. By the end of 2017 it had contracted for 260 MW of solar in Virginia, including a 100 MW project. In March of this year Microsoft announced it had reserved 315 MW of a planned 500 MW project.
  • An analysisby the Solar Foundation found that Virginia could add over 50,000 jobs by building enough solar to meet 10% of the Commonwealth’s electricity supply over five years.

The Virginia Department of Environmental Quality (DEQ) website contains a list of projects that have begun the permitting process under Virginia’s permit-by-rule provisions, which govern projects up to 150 MW. Larger projects need permission from the State Corporation Commission (SCC). All projects must also obtain local permits.

Like onshore wind, offshore wind still hasn’t taken off in Virginia. In 2014 Dominion Energy Virginia won the right to develop an estimated 2,000 MW of wind power offshore of Virginia Beach, but it still hasn’t offered a timeline for a commercial offshore wind project or even included one in its IRP. The 2018 IRP does include Dominion’s two-turbine, 12 MW pilot project, with a projected in-service date of 2021. Last year Dominion formed a partnership with Danish energy giant Ørsted (formerly DONG Energy) to see the pilot project through.

  1. Customers’ ability to purchase renewable energy is still limited

 Currently, the average Virginia resident or business can’t pick up the phone and call their utility to buy electricity generated by wind and solar farms. Customers of a few rural cooperatives are the exception; see the next section on green power programs, and section 4 on community solar.

Section 56-577(A)(6) of the Virginia code allows utilities to offer renewable energy tariffs, and if they don’t, customers are supposed to be able to go elsewhere for it. Neither of our two major investor-owned utilities, Dominion Energy Virginia (formerly Dominion Virginia Power) and Appalachian Power Company (APCo), currently has an approved tariff for renewable energy. The SCC has previously rejected renewable energy tariffs from APCo and Dominion that the SCC ruled were not in the public interest, mostly because they were too expensive.

Both utilities are trying again. APCo’s latest proposed renewable energy tariff, dubbed Rider WWS, combines wind, hydro, and new solar, and would cost residential customers a premium of 4.25 percent over brown power—a huge drop from the 18 percent increase associated with the earlier, rejected program. (The case is PUR-2017-00179.)

Dominion’s new renewable energy tariff is intended for residential and non-residential customers with a peak demand of less than 1 MW. Rate Schedule CRG-S (case PUR-2017-00157) would consist of hydro, wind and new solar, but possibly also other sources from within the PJM region. Dominion calculates the premium at 17.87 percent over brown power, a surprisingly high premium given how cheap solar, wind and hydro have become.

The SCC has not yet ruled on either program, so it is not clear when, or if, Dominion and APCo will implement these renewable energy tariffs.

Can you go elsewhere? Since the State Corporation Commission has ruled that REC-based programs do not qualify as selling renewable energy, under the terms of §56-577(A)(6), customers are currently permitted to turn to other licensed suppliers of electric energy “to purchase electric energy provided 100 percent from renewable energy.”

That means you should be able to go elsewhere to buy wind and solar, at least for the limited time before Dominion and APCo can get tariffs approved. But Virginia utilities claim that the statute’s words should be read as requiring not only that another licensed supplier provide 100% renewable energy, but that it also supply 100% of the customer’s demand, all the time. Obviously, the owner of a wind farm or solar facility cannot do that. Ergo, say the utilities, a customer cannot really go elsewhere.

In spite of the roadblocks, an independent power seller called Direct Energy announced plans in 2016 to sell a renewable energy product to Virginia residents in Dominion’s territory. (The company described the product as a combination of wind and municipal waste biomass.) Dominion fought back, but in 2017 the SCC confirmed Direct Energy’s right to enter the Virginia market; however, the SCC also ruled that Direct Energy will have to stop signing up customers once Dominion has its own approved renewable energy tariff.

Legislation defeated in the General Assembly this year would have allowed customers of Dominion and APCo to purchase electricity generated 100 percent from renewable energy from any supplier licensed to business in the state, regardless of whether the utility had its own approved program.

Ron Cerniglia, Director of Corporate and Regulatory Affairs for Direct Energy, says Direct Energy “will be ready to begin offering a full suite of product and service offerings that customers currently receive in other competitive markets including a 100% renewable product by August to non-residential customers (e.g, commercial and industrial) within the Dominion Virginia Power service territory.”

Dominion will soon have a solar option. Legislation passed in 2017 under the misleading banner of “community solar,” authorizes Dominion and APCo to contract for power from solar farms to sell to consumers. Dominion’s program is awaiting approval at the SCC (case PUR-2018-00009). Rider VCS will be available to all retail customers at a premium of about 2.01 cents/kWh in the first year. As of this writing, APCo does not appear to have proposed a similar program.

The legislation states that these “community solar” programs explicitly do not count as ones selling “electric energy provided 100 percent from renewable energy,”though ironically, they may be the first programs from Dominion and APCo to do exactly that for residential and small commercial consumers.

Large customers have more options. As discussed in section 14, Dominion has worked with large tech companies, including Amazon, Microsoft and Facebook, to meet their demands for electricity from solar. Customers of this size also have the market power to sidestep utility control to achieve their aims through the wholesale energy market.

Other companies, institutions, and even local governments can aggregate their demand to achieve the same result, without affecting their retail purchase contracts with their utility (and thus not incurring the ire of the utility). For example, the Northern Virginia Regional Commission has hired a consultant to help area governments develop large-scale solar projects using a wholesale power purchase agreement, an undertaking I wrote about last fall.

  1. “Green power” products: mostly brown power painted green

Instead of offering renewable energy tariffs, for years Dominion and APCo have offered voluntary programs under which the utilities pay brokers to buy renewable energy certificates (RECs) on behalf of the participants. Participants sign up and agree to be billed extra on their power bills for the service. Meanwhile, they still run their homes and businesses on regular “brown” power.

As I wrote a few years back in What’s wrong with Dominion’s Green Power Program, there is little evidence that voluntary RECs from Midwestern wind farms are driving any new renewable energy, whether you buy them from a utility or a third-party supplier like Arcadia. But if you’re considering this route, read this post first so you understand what you are getting. Personally, I recommend instead making monthly tax-deductible donations to GRID Alternatives to put solar on low-income homes.

The situation is better with some rural cooperatives. Old Dominion Electric Cooperative (ODEC), which supplies power to most of Virginia’s coops, signed long-term contracts for the output of three wind farms in Maryland and Pennsylvania, which it resells to some member coops. Customers of participating coops can choose to buy wind power for an additional cost. (See the information posted by Shenandoah Valley Electric Cooperative as an example.) ODEC has contracted for two solar farms in Virginia as well.

But not all coops do this. Most have REC-only offerings. In the case of Rappahannock Electric Cooperative, the RECs come from a biomass plant somewhere “in the greater mid-Atlantic area.” That is, customers voluntarily pay extra to subsidize the burning of trees for power, probably at a facility out of state. Because of wood’s high moisture content, this kind of biomass is a highly polluting way to make energy and an important source of carbon dioxide emissions, calling into question the value of the program to customers who want to support renewable energy.

  1. Community solar: what’s in a name? 

Community solar, in its purest form, enables people to work together to develop and own a solar facility in their community for the use of all the participants. This kind of community solar is not currently an option in Virginia. Solar advocates have introduced enabling legislation for several years running, but it has been defeated every year in the face of utility opposition.

Two Virginia rural electric cooperatives offer programs that come close. In both cases, the coop has contracted for the output of a solar project in its territory and offers shares of the electricity to coop members. BARC, in southwestern Virginia, was the first to offer such a program, using a small 500 kW solar facility. This year Central Virginia Electric Cooperative(CVEC) launched a 4 MW program. Subscribers can lock in the rate for 20 years, one of the most attractive features of community solar.

As noted in Section 2, legislation enacted in 2017 enables a kind of pseudo-community solar controlled by a utility. Using this authority, Dominion has contracted for the development of a number of smaller (up to 2 MW) solar projects around Virginia, and will offer customers the option of paying a 2.01 cents/kWh premium to buy solar. Unlike a true community solar program (or CVEC’s), the price is not fixed but will change annually based on market factors, and it includes a profit margin for Dominion.

It looks like a renewable energy tariff, and it quacks like a renewable energy tariff, but all concerned call it community solar. The program now awaits approval by the SCC (case PUR-2018-00009) and is expected to be available to Dominion customers by the end of the year.

  1. Virginia’s RPS: modest, and with much to be modest about

Most states have adopted renewable portfolio standards (RPS) or other mandates to require utilities to build or buy renewable energy. Leading states have been ratcheting up their percentages while tightening the rules for what qualifies, giving priority to new wind and solar.

Virginia is not among these leading states.

Virginia Code §56-585.2 creates a voluntary RPS, which means utilities have the option of participating but don’t have to. Renewable energy is defined in §56-576 to include not just wind, solar, and falling water, but also highly polluting forms of energy like trash incineration and burning trees, a/k/a biomass (“sustainable or otherwise”), as well as old, large hydroelectric plants that don’t qualify for other states’ programs. Utilities are also allowed to include up to 20% of RECs from renewable energy research and development activities, providing a subsidy to a few Virginia universities with good lobbyists.

Utilities demonstrate compliance with the RPS through the retirement of renewable energy certificates (RECs). The SCC insists that utilities take a least-cost approach to meeting the RPS, which means RECs from trash incinerators, wood burning, and old out-of-state hydro will always edge out wind and solar, simply because there is little competition for those junky RECs. If utilities build wind and solar, they are required to sell the high-value RECs from these projects (to utilities out of state or to the voluntary market) and buy low-cost junky ones instead. Thus, no matter how much solar Dominion builds, customers will never see solar as part of the RPS.

Perhaps it goes without saying that the RPS makes no provision for Virginia utilities to buy RECs from solar homes or businesses.

The targets are also modest to a fault. Although nominally promising 15% renewables by 2025, the statute uses a 2007 baseline, ignoring load growth, and contains a sleight-of-hand in the definitions section by which the target is applied only to the amount of energy after nuclear is excluded. Nuclear makes up a third of Dominion’s energy mix. Thus the combined result is an effective RPS target of well under 10% in 2025.

According to Dominion’s 2017 Annual Report to the State Corporation Commission on Renewable Energy, the “fuel” types used to meet the RPS in 2016 consisted entirely of hydro, municipal solid waste incineration, woody biomass, landfill gas, research and development, and “thermal energy” (another unusual source). The in-service dates of facilities generating renewable energy or RECs range from the 1910s to the 2010s, with the majority clearly pre-dating adoption of the RPS. Almost half the energy or RECs come from out of state. The report does not say who Dominion bought and sold RECs from and to, or for how much.

The General Assembly has rejected numerous bills to make the RPS mandatory, and efforts to narrow the definition of renewable energy have repeatedly failed in the face of utility and other industry opposition. The utilities have offered no arguments why the goals should not be limited to new, high-value, in-state renewable projects, other than that it would cost more to meet them than to buy junk RECs.

But with the GA hostile to a mandatory RPS and too many parties with vested interests in keeping the kitchen-sink approach going, it is hard to imagine our RPS becoming transformed into a useful tool to incentivize wind and solar.

That doesn’t mean there is no role for legislatively-mandated wind and solar. But it would be easier to pass a bill with a simple, straightforward mandate for buying or building a certain number of megawatts than it would be to repair a hopelessly broken RPS. The GA passed up an opportunity to do just that in this year’s SB 966, which makes up to 5,500 MW of solar and wind “in the pubic interest,” but not mandatory.

Short of that, the GA could require that Dominion apply the RECs from its solar projects to the voluntary RPS, instead of selling them, and allow the utility to buy other RECs only to fill any gaps left over.

  1. Customer-owned generation

The low cost of solar panels and the federal 30% tax credit make it cost-effective for most customers to install solar on a sunny roof or field, with homeowners reporting payback periods of less than 10 years. The federal tax credit will be available in full for projects that commence construction by the end of 2019. It drops to 26% for projects commenced in 2020 and 22% for projects commenced in 2021. Thereafter it drops to 10% for commercial and utility projects but disappears for homeowners entirely. Virginia itself offers no cash incentives or tax credits for wind or solar.

The emergence of bulk purchasing coops, sometimes also called “solarize” programs, such as those offered through nonprofits Solar United Neighbors of Virginia and LEAP, makes the process easy for homeowners and businesses and reduces costs.

Virginia allows net energy metering at the retail rate, though with limits (see section 7). Commercial customers can also reap the advantages of solar in reducing high demand charges.

In 2016 the General Assembly passed legislation enabling Property Assessed Clean Energy (PACE) loans for commercial customers. Localities now have an option to offer low-cost financing for energy efficiency and renewable energy projects at the commercial level. Arlington County has launched the first C-PACE program and is accepting applications now. Several other counties have initiated studies or are developing their own programs. PACE is not available for residential customers.

The lack of a true RPS in Virginia means Virginia utilities generally will not buy solar renewable energy certificates (SRECs) from customers. Back in the old days utilities in other states would buy SRECs generated in Virginia, but those markets have gradually closed. Pennsylvania, which had been the last remaining SREC market for Virginia residents, closed its borders last year.

The fact that the federal tax credit is such an important part of financing solar presents a challenge to customers who don’t pay any taxes, or enough taxes to use the credit. This includes non-profits, government entities, and low-income residents. Third-party financing offers a viable solution for tax-exempt entities, where available (see Section 10), but serving low-income residents remains a challenge.

  1. Limits on retail net metering

Section 56-594 of the Virginia Code allows utility customers with wind and solar projects to net energy meter at the retail rate. System owners get credit from their utility for surplus electricity that’s fed into the grid at times of high output, such as during the middle of a sunny day. That offsets the grid power they draw on when their systems are producing less than they need. Their monthly bills reflect only the net of the energy they draw from the grid.

Residential customers can net meter systems up to 20 kW, although standby charges will apply to those between 10 and 20 kW, generally making the larger sizes uneconomical.

Commercial customers can net meter up to 1,000 kW (1 MW). There is an overall cap of 1% of a utility’s peak demand that can be supplied by net metered systems (as measured at their rated capacity).

If a system produces more than the customer uses in a month, the credits roll over to the next month. However, at the end of the year, the customer will be paid for any excess credits only if they have entered a power purchase agreement with the utility. This will likely be for a price that represents the utility’s “avoided cost” of about 4 cents, rather than the retail rate, which for homeowners is about 12 cents. This effectively stops most people from installing larger systems than they can use themselves.

In 2015, the definition of “eligible customer-generator” was tightened to limit system sizes to no larger than needed to meet 100% of a customer’s demand, based on the previous 12 months of billing history. The SCC wrote implementing regulations (see20VAC5-315-10 et seq.) but failed to address what happens with new construction; in practice, utilities have simply told customers how much they can install.

In 2018 the House Commerce and Labor subcommittee on energy defeated a bill that would have increased the limit to 125% of previous demand and extended this to new construction, for residents in Dominion territory. Dominion had agreed to the change, recognizing that there is already a financial disincentive for customers to install more solar than they can use.

A number of other barriers also restrict customer solar. A building owner cannot install a solar facility and sell the output to tenants. A condo association or homeowners association cannot build a central solar facility to share the output. The owner of two or more separately metered buildings cannot share the output of a solar facility on one building with another building, with a limited exception for farmers (see section 8). A local government cannot install a solar facility at one site to serve another site.

These barriers reflect an argument, promoted by utilities, that customers who install solar for their own use don’t pay their fair share of the upkeep of the grid, shifting costs to those who don’t own solar. A range of “value of solar” studies in other states have generally found the reverse, concluding that distributed solar provides a net benefit to utilities, other customers, and society at large. A stakeholder group in Virginia completed the initial phase of a value of solar study in 2014 but got no further after the utilities pulled out of the process.

Over many years the utilities and the solar industry have tried to resolve their differences on net metering, without success. Efforts began in 2013 with the Small Solar Working Group, a broad stakeholder group facilitated by DEQ. That morphed into the Solar Working Group in 2014, then collapsed when the utilities walked away from a “Value of Solar” report the group drafted. In 2016 the utilities and the solar industry began meeting again privately in the “Rubin Group” (named for the moderator, Mark Rubin). This group produced consensus legislation in 2017 and 2018, primarily enabling the utilities to pursue their own solar goals, but they found no common ground on customer-owned solar.

In the absence of state tax credits or rebates, net metering remains critical to the financial viability of most customer-owned solar, making solar installers unwilling to give it up. For their part, utilities have put themselves into a box by insisting that customers ought to share grid costs equally. Reaching a resolution that allows the private solar market to grow will require taking the top off the box and valuing benefits as well as costs.

The issue is poised to come to a head this year. In addition to ongoing Rubin Group discussions, the Northam Administration has announced that net metering issues will be one focus of attention as the Department of Mines, Minerals and Energy (DMME) develops the 2018 Energy Plan, due at the end of October. DMME appears to have handed the solar work over to Dominion, which, as part of 2018’s SB 966 legislation, had tasked itself with conducting a study of net metering. Dominion has hired a consultant, Meridian Institute, “to design and facilitate a stakeholder engagement process” to consider “improvements” to net metering.

  1. Agricultural customers and meter aggregation

Under a bill passed in 2013, owners of Virginia farms with more than one electric meter are permitted to attribute the electricity produced by a system that serves one meter (say, on a barn) to other meters on the property (e.g., the farmhouse and other outbuildings). This is referred to as “agricultural net metering.” Unfortunately, there have been complaints from installers about a lack of cooperation from utilities in actually using this provision.

Advocates had hoped that agricultural net metering would be a first step towards broader meter aggregation options, but 2017 legislation instead took agricultural customers in a new direction. Farmers can now elect to devote up to a quarter of their acreage to solar panels, up to 1.5 MW or 150% of their own electricity demand. The electricity must be sold to the utility at its avoided cost, while the farmer must buy all its electricity from the utility at retail. A farmer who chooses to do this cannot also use agricultural net metering. Agricultural net metering will be terminated entirely in 2019 in territory served by electric cooperatives, though existing customers are grandfathered.

  1. Homeowner associations cannot ban solar (but they sure keep trying)

 Homeowner association (HOA) bans and restrictions on solar systems have been a problem for residential solar. In the 2014 session, the legislature nullified bans as contrary to public policy. The law contains an exception for bans that are recorded in the land deeds, but this is said to be highly unusual; most bans are simply written into HOA covenants. In April of 2015 the Virginia Attorney issued an opinion letter confirming that unrecorded HOA bans on solar are no longer legal.

Even where HOAs cannot ban solar installations, they can impose “reasonable restrictions concerning the size, place and manner of placement.” This language is undefined. The Maryland-DC-Virginia Solar Energy Industries Association has published a guide for HOAs on this topic.

Because of the vagueness of “reasonable restrictions,” HOAs continue to be a problem for many would-be solar homeowners.

  1. Limits on third-party financing (PPAs)

One of the drivers of solar installations in other states has been third-party ownership of the systems, including third-party power purchase agreements (PPAs). In a typical third-party PPA, the customer pays no money upfront and is charged only for the power produced by the system. At the end of the contract, or at some intermediate point, the customer usually can buy the system outright at a greatly reduced cost.

For customers that pay no taxes, including non-profit entities like churches and colleges as well as local government, PPAs are an especially important financing tool because they can’t use the 30% federal tax credit to reduce the cost of the system if they purchase it directly. Under a PPA, the system owner can take the tax credit (as well as accelerated depreciation) and pass along the savings in the form of a lower electricity price.

The Virginia Code seems to sanction this approach to financing solar facilities in its net metering provisions, specifically §56-594, which authorizes a “customer generator” to net meter, and defines an eligible customer generator as “a customer that owns and operates, or contracts with other persons to own or operate,or both, an electrical generating facility that . . . uses as its total source of fuel renewable energy. . . “ (emphasis added).

Notwithstanding this provision, in 2011, when Washington & Lee University attempted to use a PPA to finance a solar array on its campus, Dominion Virginia Power issued cease and desist letters to the university and its Staunton-based solar provider, Secure Futures LLC. Dominion claimed the arrangement violated its monopoly on power sales within its territory.

Given the threat of prolonged and costly litigation, the parties turned the PPA contract into a lease, allowing the solar installation to proceed but without the advantages of a PPA. (Note that PPAs are sometimes referred to as “leases,” but they are distinct legally. Leasing solar equipment is like renting a generator; both provide power but don’t involve the sale of the electricity itself. I have never heard of a utility objecting to a true lease.)

In 2013 Dominion and the solar industry resolved the dispute via compromise legislation that specifically allows customers in Dominion territory to use third-party PPAs to install solar or wind projects under a pilot program capped at 50 MW. Projects must have a minimum size of 50 kW, unless the customer is a tax-exempt entity, in which case there is no minimum. Projects can be as large as 1 MW. The SCC is supposed to review the program every two years beginning in 2015 and has authority to make changes to it. I’m not aware the SCC has reviewed the program to date.

Although the program got off to a slow start, PPA projects are beginning to come online at a rapid clip, and solar companies say an increase in the program size will be needed so installations don’t suddenly stall.

Outside of Dominion territory, the story is less rosy. Appalachian Power and the electric cooperatives declined to participate in the PPA deal-making. In 2017, the legislature passed a bill to allow private colleges and universities—but no one else—in APCo territory to use PPAs to install a maximum of 7 MW of renewable energy. This year a bill to expand the program for APCo customers was scuttled at the last moment due to APCo’s opposition.

Meanwhile, Secure Futures has developed a third-party-ownership business model that it says works like a PPA for tax purposes but does not include the sale of electricity. This allows the company to install larger projects in more parts of Virginia (including most recently a 1.3 MW solar array at Carilion New River Valley Medical Center in Christiansburg, which I have to mention here because the project combines solar and sheep farming and therefore will make for cute photos). Currently Secure Futures is the only solar provider offering this option, which it calls a Customer Self-Generation Agreement.

Solar schools. The availability of PPA financing has had a direct and noticeable impact on the ability of pubic schools to install solar. The projects that I know about include the following; most (but not all) of these use the PPA structure.

  • Bath County (three schools)
  • Arlington County (two schools; county is currently evaluating bids for other schools)
  • Albermarle County (six schools)
  • City of Lexington (one school)
  • Middlesex County (two schools)
  • Augusta County (seven schools)
  • City of Richmond (ten schools)
  • City of Harrisonburg (RFP issued)
  1. Personal property tax exemption for solar developers

In 2014 the General Assembly passed a law exempting solar generating equipment “owned or operated by a business” from state and local taxation for installations up to 20 MW. It did this by classifying solar equipment as “pollution abatement equipment” under §58.1-3660 of the Code. Note that this applies only to the equipment, not to the buildings or land underlying the installation, so real estate taxes aren’t affected.

The law was a response to a problem that local “machinery and tools” taxes were mostly so high as to make third-party PPAs uneconomic in Virginia. In a state where solar was already on the margin, the tax could be a deal-breaker. A separate code provision (§58.1-3661) permitted localities to exempt solar equipment from taxation, but seeking the exemptions on a county-by-county and city-by-city basis proved crushingly onerous for small developers.

The initial 20 MW cap was included at the request of the Virginia Municipal League and the Virginia Association of Counties, and it seemed at the time like such a high cap as to be irrelevant. However, with solar increasingly attractive economically, Virginia’s tax exemption rapidly became a draw for solar developers, including Virginia utilities.

In 2016 Dominion proposed changing the exemption to benefit its own projects at the expense of those of independent developers. In the end, the statute was amended in a way that benefits utility-scale projects without unduly harming smaller projects. Many new projects are now only 80% exempt, rather than entirely exempt. However, the details are complex, with different timelines and different size classes, and anyone looking to use this provision should study it carefully.

The exemption applies only to solar, not to wind.

  1. Dominion-owned distributed solar

Solar Partnership Program (commercial customers). In 2011, the General Assembly passed a law allowing Dominion to build up to 30 MW of solar energy on leased property, such as roof space on a college or commercial establishment. The demonstration program was intended to help Dominion learn about grid integration. The SCC approved $80 million of spending, to be partially offset by selling the RECs (meaning the solar energy would not be used to meet Virginia’s RPS goals). The “Solar Partnership Program” resulted in several commercial-scale projects on university campuses and corporate buildings, but the program did not offer any economic advantages, and it seems to have fizzled out. The Dominion Energy web pageon distributed generation still mentions it, but the link does not lead to more information (and didn’t last year either).

Dominion seems to be ready to try again. The 2018 legislation (SB 966) contains language saying it is in the public interest for utilities to develop or own up to 500 MW of distributed solar. Elsewhere in the same legislation the limit is shown as 50 MW, and it is not clear which one is the typo. Either number gives Dominion plenty of leeway to try out fancy technology involving grid integration of renewables to enhance system reliability and community resilience, or just make another go at undercutting customer-owned solar.

Dominion Solar Purchase Program (residential and business customers). The same 2011 legislation that enabled the “Solar Partnership” initiative also authorized Dominion to establish “an alternative to net metering” as part of the demonstration program. The alternative Dominion came up with was a buy-all, sell-all deal for up to 3 MW of customer-owned solar. As approved by the SCC, the program allows owners of small solar systems on homes and businesses to sell the power and the associated RECs to Dominion at 15 cents/kWh, while buying regular grid power at retail for their own use. Dominion then sells the power to the Green Power Program at a hefty markup. It is not clear whether the program continues to be available; as with the Solar Partnership Program, the links on the Dominion Energy website don’t lead anywhere helpful.

I ripped this program from the perspective of the Green Power Program buyers who pay for other people to install solar on their homes. While some installers advertised it as an option, others felt it was a bad deal for customers, given the costs involved, the likelihood that the payments represent taxable income, and the fact that selling the electricity could make new system owners ineligible for the 30% federal tax credit on the purchase of the system.

There are many good ways Dominion could work with the General Assembly to offer alternatives to net metering that also support customer solar. This program isn’t one of them.

  1. Utility renewable energy tariffs for large customers

Large customers that want wind and solar have had to force the issue in the past. In 2013, Dominion Power introduced a Renewable Generation (RG) Tariff to allow customers to buy renewable power from providers, with the utility simply acting as a go-between and collecting a monthly administrative fee. The program was poorly designed and got no takers.

In 2015, Amazon Web Services made Dominion’s RG tariff irrelevant. Amazon contracted directly with a developer for an 80 MW solar farm, avoiding Dominion’s monopoly restrictions with a plan to sell the electricity directly into the PJM (wholesale) market. Dominion Energy bought the project, and negotiated a special rate with Amazon for the power. This contract became the basis for an “experimental” tariff (Schedule MBR) that Dominion Energy Virginia offered to customers with a peak demand of 5 MW or more, with a program cap of 200 MW.

Since that first deal, Dominion and Amazon have followed up with contracts for an additional 180 MW of solar in five Virginia counties.

Dominion used a different approach for a deal with Microsoft. After the SCC turned down Dominion’s application to charge ratepayers for a 20-MW solar farm in Remington, Virginia, Dominion reached an agreement with Microsoft and the Commonwealth of Virginia under which the state buys the output of the project, while Microsoft buys the RECs. This seems to have been done as a favor to Dominion by then-governor Terry McAuliffe, as a way to move the Remington project forward, and I wouldn’t expect to see it repeated.

In the fall of 2017, Facebook negotiated its own terms with Dominion for 130 MW of a 300 MW solar project. With this as its basis, Dominion created yet another new tariff, Schedule RF.

The alphabet soup of tariffs suggest Dominion is still finding its way in serving large corporations. The utility has a strong incentive to make deals with large corporations that want a lot of renewable energy: if they don’t like what Dominion is offering, they can make an end run around the utility by working through the PJM wholesale market, as discussed above in section 2. This appears to be Microsoft’s plan for a 500 MW solar farm announced last year. Perhaps we should watch for Dominion to propose yet another new tariff, if they haven’t run out of letters.

For a customer without the market power of Amazon, Facebook or Microsoft, buying renewable energy from Dominion remains challenging. As noted in section 2, the SCC already rejected one set of voluntary schedules Dominion had proposed for customers with a peak demand of at least 1,000 kW (1 MW). The rejection can’t be called a loss for customers, since the plan was to use a mix of sources that count as renewable under the Virginia Code but still pollute, including biomass—making it only sort-of green. The SCC said the tariff was too expensive, possibly because biomass is expensive compared to other kinds of renewable energy.

While that particular renewable energy tariff was more an effort to close off competition from Direct Energy than to serve the needs of customers, Dominion seems serious about finding solar options for large customers. One of the tasks the Rubin Group says it plans to take on this year is considering further changes to help large customers who want solar.

  1. Dominion plans for utility-scale solar

As early as 2014, Dominion had announced it wanted to begin developing large-scale solar projects in Virginia. In 2015, two bills promoted the construction of utility-scale solar by declaring it in the public interest for utilities to build or buy solar energy projects of at least 1 MW, and up to an aggregate of 500 MW. This year’s legislation increased that number to 5,000 MW and included wind in the total.

Dominion got off to a rocky start when the SCC rejected the company’s plan to charge ratepayers for its first project, a 20 MW solar farm in Remington, Virginia because the company had not considered cheaper third-party alternatives. Governor McAuliffe helped save the project by working out a deal with Microsoft, as discussed above. Further projects fared better, however, and Dominion is now so enthusiastic about solar that its 2018 Integrated Resource Plan (IRP) calls for up to 480 MW per year, all for the benefit of its regular ratepayers.

Dominion’s website currently lists several solar projects in Virginia, but only three of them, totaling 56 MW, serve the Dominion Energy Virginia rate base. Even with the boost from the General Assembly, future projects will still have to gain SCC approval. And while Dominion will be able to charge ratepayers for projects that do get approved, the SCC will probably insist that the RECs be sold—whether to utilities in other states that have RPS obligations, or to customers who want them for their own sustainability goals, or perhaps even to voluntary green power customers. If this happens, the result will be that Dominion still won’t use solar to meet the Virginia RPS, and ordinary customers will still not have solar as part of the electricity they pay for. That’s the weird world of RECs for you.

  1. Governor McAuliffe’s program to purchase solar for state government will be continued under Northam

Following a recommendation by the Governor’s Climate Change and Resiliency Commission, on December 21, 2015, Governor McAuliffe announced that the Commonwealth would commit to procuring 8% of its electricity from solar, a total of 110 MW, with 75% of that built by Dominion and 25% by private developers.

The first deal to count towards this goal was an 18 MW project at Naval Station Oceana, announced on August 2, 2016. The Commonwealth will buy the power and the RECs. (The Remington Project did not count, because as the buyer of the RECs, only Microsoft can claim the right to be buying solar power.) Two solar farms supplying the University of Virginia and its Darden School of Business also counted towards the 8%.

Although no other projects have been announced since McAuliffe left office, Deputy Secretary of Commerce and Trade Angela Navarro confirmed to me that the 110 MW goal remains in place. She adds, “We also have around 2 MW of agency-owned solar installed or slated to be installed this year. We’re still working toward the 110MW goal, and we hope to announce an even more ambitious goal through the Energy Plan process.”

  1. Onshore wind

No Virginia utility is actively moving forward with a wind farm on land. Dominion Energy’s website used to list 248 MW of land-based wind in Virginia as “under development,” without any noticeable progress. The current web page doesn’t mention specific projects or sizes, only that “we are evaluating wind energy projects in Virginia.” If so, none of them has made it into any recent IRP.

On the other hand, Appalachian Power continues to try to add wind power to its mix, though so far not from any Virginia sites. In April of this year, the SCC denied APCo’s request to acquire two wind projects in West Virginia and Ohio, saying the company didn’t need the power.

With no utility buyers, Virginia has not been a friendly place for independent wind developers. In previous years a few wind farm proposals made it to the permitting stage before being abandoned, including in Highland County and on Poor Mountain near Roanoke.

Nonetheless, Apex Clean Energy has obtained a permit to develop a 75-MW Rocky Forge wind farm in Botetourt County. The company says the project is construction-ready and believes it can produce electricity at a competitive price, given its good location and improved turbine technology. However, the company will not move forward until it has a customer.

Looking forward a few years, the ability of wind to complement solar may give it a role as solar dominates new capacity additions in Virginia. Currently, Dominion’s IRP proposes to pair solar with gas combustion turbines, not battery storage. Wind energy paired with solar would reduce the need for gas back-up, perhaps tilting the equation in favor of battery storage instead.

  1. Offshore wind

Progress towards harnessing Virginia’s great offshore wind resource remains slow. Dominion won the federal auction for the right to develop about 2,000 MW of wind power off Virginia Beach in 2013, and last year the company received approval for its Site Assessment Plan (SAP).

We had originally been told the federal government’s timeline would lead to wind turbines being built off Virginia Beach around 2020. Later, however, the Bureau of Ocean Energy Management said Dominion has five years from approval of the SAP to submit its construction and operations plan, after which we’ll have to wait for review and approval. Presumably the project will also require an environmental impact statement.

That would put first construction in the mid-2020s—if Dominion can be prodded into going forward. Right now the company’s Integrated Resource Plan (IRP) does not include offshore wind in any of its scenarios for the next 15 years, except for 12 MW from two test turbines.

Those test turbines may become a reality, now that Dominion has partnered with the Danish energy company, Ørsted, formerly known as DONG Energy, to see the 12 MW project through to completion. Dominion is expected to make some sort of filing with the SCC this summer to move the project along. The IRP lists an in-service date of 2021.

All this is promising, as Ørsted clearly has its eyes on the commercial lease area. Governor Ralph Northam also seems keen to reignite offshore wind in Virginia. This spring DMME issued a Request for Proposals for a plan “to position Virginia as the East Coast offshore wind supply chain industry location of choice,” the first step in what advocates hope will become a Master Plan for Virginia offshore wind.

DMME is also including offshore wind as one focus of the 2018 Energy Plan, with plans for a public listening session and a facilitated stakeholder group.

  1. State carbon trading rules

The Trump administration’s pullbacks on the Paris accord and the Clean Power Plan prompted Governor McAuliffe last year to order the Department of Environmental Quality (DEQ) to write rules lowering carbon emissions from Virginia power plants by 30% by 2030. Under draft rules set to be finalized this fall, Virginia power plants will trade carbon allowances with those in member states of the Regional Greenhouse Gas Initiative (RGGI).

Any rules that put pressure on carbon-emitting power plants should be good for wind and solar, but at this writing there is still some uncertainty about what the final rules will look like.

Governor Northam pushed for legislation this year that would have had Virginia formally join RGGI, rather than just trading with it. Joining RGGI would allow Virginia to auction carbon allowances instead of merely handing them out free to power plants. Auction money would support investments in wind and solar, among other priorities. Republicans in the General Assembly defeated the legislation, but advocates expect it to be re-introduced next year.

Virginia legislators face a flood of new solar bills

Photo courtesy of Department of Energy, via Wikimedia Commons.

It’s true that Republicans remain in control of the General Assembly, and the way things run in Richmond, having only the narrowest of margins diminishes the majority’s power remarkably little. Yet the Blue Wave swept in a set of younger, more diverse, and more progressive delegates, many of whom are as interested in reforming energy policy as they are in social and economic issues.

As a result, I count more than 50 bills dealing with solar, energy efficiency, electric vehicles and battery storage; several more that affect clean energy by addressing carbon emissions; and still others that deal with utility regulation in ways that have implications for renewables and storage. And bills are still being filed.

In this post, I cover just the renewable energy bills of general interest filed to date, saving energy efficiency, storage, EVs and climate for later.

Most of these bills cover renewable energy generally. Bills submitted by the Rubin Group (the private negotiating group consisting mostly of utilities and solar industry members) are limited to solar.

One bill this year takes a new run at a mandatory renewable portfolio standard (RPS). This is Delegate Sullivan’s HB 436, which narrows the kind of resources eligible for the program (now mostly wind, solar and hydro) as well as making it mandatory. As currently drafted it is so ambitious that it would likely mean utilities would have to buy a lot of Renewable Energy Certificates from out of state to meet the early year targets, but changes to the bill may be in the works.

Delegate Sullivan has also proposed HB 54, which would provide a state tax credit of 35% of the cost of installing certain kinds of renewable energy property, up to a maximum credit of $15,000.

Several bills enable community solar programs, to provide options beyond the utility-controlled program passed last year that more closely resembles a green tariff. SB 313 (Edwards) SB 311 (Edwards) offer two different customer-controlled models. SB 586 (Gooditis) would authorize, but not require, utilities to set up utility-controlled programs; it differs from last year’s bill in that customers would have a direct connection with a specific renewable energy project. Since it would not be limited to solar, it could open a new option for community wind.

The Rubin Group drafted three pieces of legislation. The centerpiece bill, SB 284 (Saslaw) and HB 1215 (Hugo) raises from 500 megawatts (MW) to 4,000 MW (by 2024) the amount of large-scale solar utilities can build or buy that is deemed to be “in the public interest,” a designation that takes this determination away from the State Corporation Commission. The bill also makes it in the public interest for utilities to own or buy up to 500 MW of small-scale solar projects (under 1 MW each). These will be distributed projects, but utility-controlled, along the lines of Dominion’s not-very-successful Solar Partnership Program.

SB 284 and HB 1215 don’t actually require the utilities to do anything, but the legislation is widely seen as signaling their intent to move forward with additional solar development. While a very welcome signal, legislators should keep in mind that a Solar Foundation analysis earlier this year noted it would take as much as 15,000 MW of solar to provide just 10% of Virginia’s electricity supply.

Recognizing this reality, Delegate Mark Keam has introduced HB 392, which declares it in the public interest for the Commonwealth to get 10% of its electricity from solar, and raises to 15,000 MW the amount of utility solar in the public interest.

The two other Rubin Group bills deal with land use, putting language into the code giving people the right to put up solar panels on their own property for their own use, except where local ordinances specifically prohibit it, and subject to setback requirements, historic districts, etc. The bills are SB 429 (Stanley), its companion bill HB 508 (Hodges), SB 179 (Stanley) and companion bill HB 509 (Hodges).

The Rubin Group tried and failed to negotiate changes to Virginia’s net metering program, which affects most customer-sited solar projects, including residential rooftop solar. This is hardly a surprise; a group that works on consensus gives every member veto power. With utilities hostile to any perceived incursion on their monopoly power, and solar advocates pledged to protect the rights of residents, there aren’t a whole lot of opportunities for consensus here.

With the Rubin Group out of the net metering space, legislative champions have stepped into the vacuum to propose a host of bills that would support customers who install solar for their own use:

  • HB 393 (Keam) removes the 1% cap on net metered projects, and provides that when net metered projects reach 1% of a utility’s electric load, the SCC will conduct a study of the impact of net metering and make recommendations to the General Assembly about the future of the program. HB 1060 (Tran) simply removes the cap.
  • SB 191 (Favola) provides that Virginia customers who wish to self-generate electricity with renewable energy using the net metering provisions of the Code may install up to 125% of their previous 12 months’ electric demand, or in the case of new construction, of the electric demand of similar buildings. A 2015 law currently limits customers to 100% of previous demand.
  • HB 421 (Sullivan) allows owners of multifamily residential buildings to install renewable energy facilities and sell the output to occupants. This bill does not provide for the electricity to be net metered.
  • HB 930 (Lopez) requires the SCC to establish a net metering program for multifamily customer-generators, such as condominiums, apartment buildings, and homeowner associations.
  • HB 978 (Guzman) requires utilities to justify standby charges with a value of solar study. As currently written, the bill does not appear to have retroactive effect, so it might not repeal the existing, much-hated standby charges already approved by the SCC.
  • SB 82 (Edwards) expands the agricultural net metering program, increasing the project size limit from 500 kW to 1 MW, providing that the electricity can be attributed to meters on multiple parcels of land, and repealing the 2017 law ending agricultural net metering in coop territory.

Finally, several bills once again tackle third-party power purchase agreements (PPAs), which the Virginia Code appears to make legal, but which utilities have consistently maintained are a violation of their monopoly on the sale of electricity. HB 1155 (Simon) reaffirms the legality of PPAs. SB 83 (Edwards) replaces the existing PPA pilot program that dates from 2013 and directs the SCC to establish a broader program.

HB 1252 (Kilgore) replaces the existing pilot, which has different rules for Dominion and APCo, with a new program renamed “net metering power purchase agreements” that would be consistent for both utilities. It would open up APCo territory more than at present, by allowing any tax-exempt entity to participate rather than just the private colleges and universities that won inclusion last year. However, as currently drafted, it would narrow the program as it exists in Dominion territory by eliminating the eligibility of for-profit customers. Although it is the least customer-friendly option among the PPA bills, Kilgore’s position as chairman of House Commerce and Labor, which will hear the bill, gives it the strongest chance of passage.

Note that most of the renewable energy bills (other than those dealing with tax credits and land use) will go to the Commerce and Labor committees. In the House, a subcommittee usually meets once to hear all the bills (and typically to kill all but the ones anointed by chairman Terry Kilgore). While the schedule is not set, in the past the subcommittee meeting has been held in early February.


Important dates:

First Day of Session: Wednesday, January 10

Bill filing Deadline: Friday, January 19

Crossover (last day on which bills passed in one chamber can go to be heard in the other): Wednesday, February 14

Sine Die (end of Session): Saturday, March 10 

How to research a bill:

I’ve hot-linked the bills discussed here, but you can also find them all online pretty easily. On the home page of the General Assembly website, you will see options at the lower right that direct you to the Legislative Information Service, or LIS. If you know the number of a bill, you can type it into the first box (omitting spaces), and click “GO.” This will take you to a page with information about the bill, including a summary of the bill, the bill’s sponsor (called a “patron” in Virginia), the committee it has been assigned to, and its current status. Follow links to learn more about the committee, such as who is on it and when it meets. You will also see a link to the full text of a bill as a PDF.

Always read the full text of a bill rather than simply relying on the summary. Summaries sometimes contain errors or omit critical details, and bills can get amended in ways that make them very different from what the summary says. For the same reason, make sure you click on the latest version of the bill’s text.

If you don’t know a bill number, the General Assembly home page also lets you search “2018 Regular Session Tracking.” When you hit “GO,” this button brings you to a page with options for finding a bill, including by the name of the legislator (“member”), the committee hearing it, or the subject.

When you click on the name of a committee, you will see the list of bills referred to that committee, with short descriptions. It also tells you who is on the committee, when the committee meets and where. You can click on “Agendas” to see which bills are scheduled to be heard at the next committee meeting. Unfortunately the agendas are not set until a day or two before the meeting.

 

Want more solar in Virginia? Here’s how to get it.

A Solar Foundation analysis showed Virginia could create 50,000 new jobs by committing to build enough solar to meet 10% of energy demand. Photo credit: Dennis Schroeder, NREL

If there is an energy issue that Republicans and Democrats can agree on, it is support for solar energy. It’s homegrown and clean, it provides local jobs, it lowers our carbon footprint, and it brings important national security and emergency preparedness benefits. Dominion Energy Virginia even says it’s now the cheapest option for new electric generation.

Yet currently Virginia lags far behind Maryland and North Carolina in total solar capacity installed, as well as in solar jobs and the percentage of electricity provided by solar. And at the rate we’re going, we won’t catch up. Dominion’s current Integrated Resource Plan calls for it to build just 240 megawatts (MW) per year for its ratepayers. How can we come from behind and score big?

First, our leaders have to set a serious goal. Virginia could create more than 50,000 new jobs by building enough solar to meet just 10 percent of our electricity demand by 2023. That requires a total of 15,000 MW of solar. Legislators should declare 15,000 MW of solar in the public interest, including solar from distributed resources like rooftop solar.

The General Assembly should consider a utility mandate as well. Our weak, voluntary Renewable Portfolio Standard (RPS) will never be met with wind and solar, and making it mandatory wouldn’t change that. (To understand why, read section 4 of my 2017 guide to Virginia wind and solar policy, here.) Getting solar into the RPS would require 1) making it mandatory; 2) increasing the targets to meaningful levels (including removing the nuclear loophole); 3) including mandatory minimums for solar and wind so they don’t have to compete with cheap renewable energy certificates (RECs) from out-of-state hydroelectric dams; and 4) providing a way for utilities to count the output of customer-owned solar facilities in the total, possibly through a REC purchase program to be set up by the State Corporation Commission.

The other way to frame a utility mandate would be to ignore the RPS and just require each utility to build (or buy the output of) its share of 15,000 MW of solar. Allowing utilities to count privately-owned, customer-sited solar towards the total would make it easier to achieve, and give utilities a reason to embrace customer investments in solar.

Second, the General Assembly has to remove existing barriers to distributed solar. Customers have shown an eagerness to invest private dollars in solar; the government and utilities should get out of the way. That means tackling several existing barriers:

  • Standby charges on residential solar facilities between 10 and 20 kilowatts (kW) should be removed. Larger home systems are growing in popularity to enable charging electric vehicles with solar. That’s a good thing, not something to be punished with a tax.
  • The 1% cap on the amount of electricity that can be supplied by net-metered systems should be repealed.
  • Currently customers cannot install a facility that is larger than needed to serve their previous year’s demand; the limitation should be removed or raised to 125% of demand to accommodate businesses with expansion plans and homeowners who plan to buy electric vehicles.
  • Customers should be allowed to band together to own and operate solar arrays in their communities to meet their electricity requirements. This kind of true community solar (as distinguished from the utility-controlled programs enabled in legislation last year) gives individuals and businesses a way to invest in solar even if they don’t have sunny roofs, and to achieve economies of scale. If community solar is too radical a concept for some (it certainly provokes utility opposition), a more limited approach would allow condominiums to install a solar facility to serve members.
  • Local governments should be allowed to use what is known as municipal net metering, in which the output of a solar array on government property such as a closed landfill could serve nearby government buildings.
  • Third-party power purchase agreements (PPAs) offer a no-money-down approach to solar and have tax advantages that are especially valuable for universities, schools, local governments and non-profits. But while provisions of the Virginia Code clearly contemplate customers using PPAs, Virginia utilities perversely maintain they aren’t legal except under tightly-limited “pilot programs” hammered out in legislation enacted in recent years. The limitations are holding back private investment in solar; the General Assembly should pass legislation expressly legalizing solar third-party PPAs for all customers.

Third, the Commonwealth should provide money to help local governments install solar on municipal facilities. Installing solar on government buildings, schools, libraries and recreation centers lowers energy costs for local government and saves money for taxpayers while creating jobs for local workers and putting dollars into the local economy. That makes it a great investment for the state, while from the taxpayer’s standpoint, it’s a wash.

If the state needs to prioritize among eager localities, I recommend starting with the Coalfields region. The General Assembly rightly discontinued its handouts to coal companies in that region, which were costing taxpayers more than $20 million annually. Investing that kind of money into solar would help both the cash-strapped county governments in the area and develop solar as a clean industry to replace lost coal jobs.

Coupled with the ability to use third-party PPA financing, a state grant of, say, 30% of the cost of a solar facility (either immediately or paid out over several years) would drive significant new investment in solar.

Fourth, a tax credit for renewable energy property would drive installations statewide. One reason North Carolina got the jump on Virginia in solar was it had a robust tax credit (as well as a solar carve-out to its RPS). One bill has already been introduced for Virginia’s 2018 General Assembly session offering a 35% tax credit for renewable energy property, including solar, up to $15,000. (The bill is HB 54.)

Fifth, Virginia should enable microgrids. Unlike some other East Coast states, we’ve been lucky with recent hurricanes. The unlucky states have learned a terrible lesson about the vulnerability of the grid. They are now promoting microgrids as one way to keep the lights on for critical facilities and emergency shelters when the larger grid goes down. A microgrid combines energy sources and battery storage to enable certain buildings to “island” themselves and keep the power on. Solar is a valuable component of a microgrid because it doesn’t rely on fuel supplies that can be lost or suffer interruptions.

The General Assembly should authorize a pilot program for utilities, local governments and the private sector to collaborate on building solar microgrids with on-site batteries as a way to enhance community preparedness, provide power to buildings like schools that also serve as emergency shelters, and provide grid services to the utilities.

One way or another, solar energy is going to play an increasingly large role in our energy future. The technology is ready and the economics are right. The only question is whether Virginia leaders are ready to make the most of it in the coming year.

Virginia legislative session wraps up with action on solar, coal ash, and pumped storage

Next year I'm bringing him to lobby with me. Photo credit: Sierra Club

Next year I’m bringing him to lobby with me. Photo credit: Sierra Club

The Virginia General Assembly wraps up its 2017 session on Saturday, February 25. As usual, the results are a mixed bag for energy. On the plus side is the promise of a new solar purchase option for customers. On the downside, utility opposition to energy efficiency and distributed generation meant a lot of worthwhile initiatives never made it out of subcommittee.

Putting it into perspective, it could have been worse. For clean energy advocates in Virginia, that’s what we call a success!

Governor Terry McAuliffe has already acted on some of the bills that passed and will have until March 27 to act on the remaining bills. Under Virginia law, the governor can sign, veto, or amend the bills for legislators’ consideration.

“Rubin Group” bills move renewable energy forward—and back.

Negotiations between utilities, the solar industry trade association MDV-SEIA, and the group Powered by Facts produced three pieces of legislation that appear likely to become law (and all of which I’ve discussed previously). The most significant of these “Rubin Group” bills (named for facilitator Mark Rubin) is SB 1393 (Wagner), the so-called “community solar” bill, which is designed to launch a utility-controlled and administered solar option for customers. The utilities will contract for the output of solar facilities to be built in Virginia and will sell the electricity to subscribers under programs to be approved by the State Corporation Commission. Critical details such as the price of the offering will be determined during a proceeding before the State Corporation Commission.

This was the only one of the Rubin Group bills that had participation from members of the environmental community (Southern Environmental Law Center and Virginia League of Conservation Voters), and it received widespread (though not unanimous) support from advocates.

Broader legislation that would have enabled true community solar programs did not move forward. SB 1208 (Wexton) and HB 2112 (Keam and Villanueva), modeled on programs in other states, had the backing of the Distributed Solar Collaborative, a stakeholder group composed of everyone but utilities. In the Senate, Wexton’s bill was “rolled into” Wagner’s bill, but only her name, not the provisions of her bill, carried over.

SB 1395 (Wagner), a second Rubin Group bill, increases from 100 MW to 150 MW the size of solar or wind projects eligible to use the state’s Permit by Rule process, which is overseen by the Department of Environmental Quality. The legislation also allows utilities to use the PBR process for their projects instead of seeking a permit from the SCC, if the projects are not being built to serve their regulated ratepayers.

The third Rubin Group bill establishes a buy-all, sell-all program for agricultural generators of renewable energy. Although supported by MDV-SEIA as part of the package deal, passage of SB 1394 (Wagner) and HB 2303 (Minchew) should be considered a loss for solar. The program replaces existing agricultural net metering rules for members of rural cooperatives and could lead these coops to reach their 1% net metering cap prematurely, blocking other customers from being able to use net metering. And while negotiators say the program should be economically beneficial to participants, it appears to offer generators no options they don’t already have under existing federal PURPA law.

The governor has until March 27 to act on these bills.

Appalachian Power PPAs for private colleges only

Under HB 2390 (Kilgore), the existing pilot program that allows some third-party power purchase agreements (PPAs) in Dominion Power territory will be extended to Appalachian Power territory, but only for the private colleges and universities who could afford to hire a lobbyist to negotiate the special favor, and only up to a 7 MW program cap. APCo is expected to use passage of the bill to assert that PPAs for all other customers are now illegal. The governor has not indicated whether he will sign the bill.

Intellectual property

SB 1226 (Edwards, D-Roanoke) allows solar developers to keep confidential certain proprietary information that would otherwise be subject to disclosure under the state’s Freedom of Information Act (FOIA). It resolves a problem that has held up a solar project on the Berglund Center, a public building in Roanoke.

Storage, pumped or otherwise

HB 1760 (Kilgore) and SB 1418 (Chafin) allow Dominion Power to seek rate recovery for a scheme to use abandoned coal mines for pumped storage facilities. If you think this sounds weird and possibly dangerous, you are not alone. Usually the idea is to keep water out of coal mines to avoid the leaching of toxic chemicals into groundwater. Apparently no one has ever used coal mines for pumped storage before, and neither the company that would construct the project, nor the sites under consideration, nor the technology to be used, have been revealed.

SB 1258 (Ebbin) adds storage to the mandate of the Virginia Solar Energy Development Authority.

Dominion’s nuclear costs, and the politics of the “rate freeze”

HB 2291 (Kilgore) allows Dominion to charge ratepayers for the costs of upgrading its nuclear facilities. Because the charges will appear as a rider on top of base rates, consumers would not be protected by the “rate freeze” Dominion pushed through in 2015’s SB 1349.

That 2015 legislation, of course, was supposedly designed to shield customers from the impact of the EPA’s Clean Power Plan, a ruse that has been since laid bare. Instead, it will allow Dominion to keep an estimated billion dollars of customers’ money it would otherwise have had to refund or forego. This year, with the CPP on death row under Trump, Senator Chap Petersen introduced SB 1095, which would repeal the rate freeze. His bill was promptly killed in committee, but continues to gain support everywhere outside the General Assembly. Governor McAuliffe belatedly announced his support for Petersen’s bill, but did not use his authority to resurrect it.

Petersen is encouraging the Governor to offer an amendment to Kilgore’s HB 2291 that would repeal the rate freeze, an option allowed by Virginia’s legislative procedure since both provisions affect the same provision of the Code.

Dominion, of course, says the CPP isn’t actually dead and buried just yet, and Republicans seem to fear its resurrection. HB 1974 (O’Quinn) requires the Department of Environmental Quality to submit any Clean Power Plan implementation plan to the General Assembly for approval, so they can stab it with their steely knives.  The governor is expected to veto the bill.

State’s failures on energy efficiency will now be tracked

SB 990 (Dance) requires the Department of Mines, Minerals and Energy to track and report on the state’s progress towards meeting its energy efficiency goals. Or in Virginia’s case, its lack of progress.

HB 1712 (Minchew) expands the provisions of state law that allow public entities to use energy performance-based contracting.

That’s it for energy efficiency legislation this year. Several good bills were offered but killed off in the House Energy Subcommittee, notably HB 1703 (Sullivan), which would have required electric utilities to meet efficiency goals, and HB 1636 (Sullivan again), which would have changed how the SCC evaluates energy efficiency programs. Delegate Sullivan, by the way, introduced a companion bill to SB 990, but his was killed in that same House subcommittee, all on the same day.

Coal ash legislation watered down but passes

SB1398 (Surovell) will require Dominion Power to monitor pollution and study options for the closure of its coal ash impoundments, including removal of the ash to secure, lined landfills. Unfortunately amendments in the House will allow Dominion to proceed with capping the waste in unlined pits while it completes the study. As one editorial put it, “Why not do it right the first time?” The editorial—along with a lot of people who have to live near the coal ash dumps—would like to see the governor offer amendments to the bill, but we’ve heard nothing from the governor’s office on that yet.

Republicans keep trying to throw taxpayer money down a rathole; Governor vetoes

Governor McAuliffe has already vetoed HB 2198 (Kilgore), which would reinstate the coal employment and production incentive tax credit and extend the allowance of the coalfield employment enhancement tax credit. SB 1470 (Chafin) is identical to HB 2198 and so likely faces a veto as well.

Renewable energy bills begin an uncertain journey through Virginia’s general assembly

VA capital Corrina BeallThree Senate Republicans and one Democrat met on Thursday to consider the fate of many of this year’s renewable energy bills. Reported out were two bills introduced by Frank Wagner that were crafted by utilities, the solar industry trade association MDV-SEIA, and Powered by Facts (a group currently focused on farms).

Other bills were not as lucky as these two. In theory all bills get another bite at the apple in the full Senate Commerce and Labor Committee, where they are on the docket for Monday afternoon. However, expectations are that the bills voted down in subcommittee will meet the same fate in full committee.

Wagner, the chairman of the Senate committee, named himself to his subcommittee along with fellow Republicans Ben Chafin and Glen Sturtevant, and Democrat Rosalyn Dance. So it was not surprising that this hand-picked group supported his bills. More disappointing was the solid opposition to anyone else’s proposals, including ones with even better potential to improve the solar market. That opposition came not only from the Wagner, Chafin and Sturtevant, but also from MDV-SEIA.

The two Wagner bills reported out are SB 1393 (the so-called community solar program) and SB 1394 (small agricultural generators). The bills have undergone some more recent changes, which I will get to in a bit.

The committee voted down Edwards’ SB 917 (containing minor fixes to the agricultural net metering law), Edwards’ SB 918 (expanding authorized uses of third party power purchase agreements), and Wexton’s SB 1208 (a more expansive community solar bill). Following a common practice in the General Assembly, SB 1208 was “rolled into” SB 1393, which is simply a polite way of extinguishing a bill. Similarly, SB 917 was rolled into SB 1394, even though the two are only vaguely related.

Over in House Commerce and Labor, several renewable energy bills will be heard by the energy subcommittee when it meets Tuesday afternoon. These include Keam’s HB 2112, the companion to Wexton’s SB 1208, and Minchew’s HB 2303, the companion to Wagner’s SB 1394. (The text of some House bills has not yet been updated to conform to changes in the Senate bills, but this seems likely to happen.)

Two new bills on third-party power purchase agreements have been added since my initial roundup. Chairman Kilgore introduced HB 2390, a bill that would, for a narrow class of privileged customers, extend to Appalachian Power territory the PPA pilot program currently running in Dominion territory. The pilot program specifically allows certain third-party power purchase agreements while forbidding all others. In Dominion territory the program is capped at 50 MW; the bill would place a 10 MW cap on the APCo program.

The PPA pilot program has allowed customers like Albermarle County Public Schools and the University of Richmond to install solar cost-effectively, and APCo customers have been itching to join it.

But Kilgore’s bill contains a limitation that is really pretty offensive. Unlike the pilot project in Dominion territory, where participants may include any non-profit of any size, as well as commercial customers with facilities of over 50 kW, Kilgore’s bill would allow only private colleges and universities to compete for the 10 MW in APCo territory. No public colleges, no churches, no community centers or town buildings. For a guy with a folksy demeanor, Kilgore seems to be one heck of an elitist.

A better PPA bill is Toscano’s HB 1800, stating that nonresidential and agricultural customers have the right to contract with other people to own and operate renewable energy facilities on the customer’s premises. Although a hearing examiner recently agreed with the solar industry and environmentalists that this right already exists in the Virginia Code, utilities have blocked on-site PPAs. Toscano’s bill would put an end to this harassment, while giving up on residential consumer PPAs. (The concession sounds bad but isn’t; residential customers can use leases to achieve the same result that PPAs afford.)

Other House bills. Also up in the House subcommittee on Tuesday will be the three worthy energy efficiency bills from Delegate Sullivan. In addition, Villanueva’s Alternative Energy and Coastal Protection Act is back for a third year as HB 2018. It would provide money for renewables and efficiency as well as badly-needed funds to help communities adapt to consequences of climate change such as sea level rise.

Now, about those Wagner bill changes:

Following revisions, “community” solar still looks like a winner, except for the community part. SB 1393 met with support from all corners of the room at the Senate subcommittee meeting on Thursday. Everyone, it seems, wants more solar options for consumers and is excited that the utilities seem willing to move forward to meet this growing demand.

Just don’t expect community solar. As now drafted, utilities control every aspect of the program. Although third-party developers would build the solar projects, the utilities can choose to buy the electricity through a PPA or buy and own the project themselves. Also, the project size limit of 2 MW, which has a community-scale feel to it, does not apply if a utility is simply designating 2 MW of a larger project to this program. In effect, if the utility contracts for a number of large projects across the state (which Dominion is indeed doing), it can simply designate parts of each as “community solar,” and fill the program that way.

That doesn’t make it a bad bill, just not a community solar bill. And while it looks like a tariff for the sale of renewable energy to participating customers, the bill continues to state that it is not a tariff for the supply of 100% renewable electricity—language that supposedly dodges the fight about under what circumstances third parties can legally sell renewable energy in Virginia.

Even with changes, agricultural RE bill’s possible benefits for some come at a cost to others. SB 1394 was reported unanimously from the Senate subcommittee Thursday, but drew opposition from both the Sierra Club and the solar consumer group VA-SUN. The current language of the bill contains improvements over the original (discussed here), but however well intentioned, it remains a bad bill.

The legislation establishes a pilot program that allows farmers to use a portion of their land for solar and enter a buy-all, sell-all contract with the utility. They will buy their power at retail and sell at a price that might not be much more than wholesale, so whether the program pencils out for farmers is uncertain. But that’s not my beef with it.

The problem is that this program is offered as a replacement to an entirely different program, one that allows farms to attribute the power output of a single solar array or wind turbine to all the various meters on the farm under the net metering statute. That’s a valuable option for farmers who want to meet their electric needs with renewable energy. Removing this option is a backwards step for wineries, breweries, organic farms, and any other farmer for whom solar power is an important part of their branding and marketing. (Consider that this bill applies to wind as well as solar; a small farmer would likely have only one wind turbine to serve the whole farm. You can’t put a little wind turbine on every building with an electric meter.)

The date at which agricultural generators can no longer opt to use the agricultural net metering provisions has been moved to 2019 (from 2018 in the original draft legislation), and the termination of the net metering option now applies only to coop members, not customers of Dominion and APCo. Existing agricultural net metering customers can continue to use the net metering provisions for 25 years, up from 20. These are all incremental improvements but don’t change the fundamental problem that the legislation trades away the rights of some customers in an effort to help others.

There is another problem. Projects developed under the buy-all, sell-all program would count against the 1% cap on the total amount of electricity produced by net metering in a utility’s service territory. This is wrong as a matter of principle (if they aren’t net metering, it shouldn’t count against a net metering limit) and also because a few large farmers using the buy-all, sell-all program would max out the 1% and leave nothing for homeowners or other coop customers.

From the coops point of view, that’s not a bug, that’s a feature; killing net metering is precisely their goal. That’s why the buy-all, sell-all program is not being offered as an option, which would be fine, but as a replacement, which is not.

I asked Dana Sleeper, Director of MDV-SEIA, why her organization was supporting the bill. She responded:

We felt that with the changes made in committee, it was more additive (creating options) then limiting. We had some models made in order to confirm that the proposed legislation would be a viable path for businesses to pursue, and my intent is to make those models publicly available so they may be helpful to those interested in pursuing the AgGEN option, should the bill pass. 

As for why MDV-SEIA opposed other pro-solar bills like Wexton’s and Edwards’, she answered:

MDV-SEIA was a participant in the Rubin stakeholder group process over the course of many months and, along with the other stakeholders, agreed to support a slate of bills that moved the needle on solar issues in VA. As part of the group, we included professional lobbyists in order to ensure that political perspective was built in. One of the recommendations from the lobbyists was to draw clear lines around those bills coming out of our stakeholder process versus those put forward by other groups, as it would cause confusion among legislators who have a lot on their plates during a short session. 

For that reason, any bills that were seen by legislators as being duplicative were folded into the Rubin group bills. That’s not to say we don’t see the merit of them, it’s simply that there were many concerns about those proposals which were addressed by the Rubin bills. Our lobbyist, when asked, noted that while we appreciated the thought and effort put into the legislation, we recommended folding them into our bill. There were some bills that did not cover the same topics as those discussed in the working group (for example, the tax credit bill), and we supported them wholeheartedly. 

Lobby efforts underway. MDV-SEIA is inviting supporters to its second Clean Energy Lobby Day on Tuesday; register here.

Separately, Secure Futures LLC and other solar industry members are also encouraging advocates of distributed generation to attend the House subcommittee meeting on Tuesday. They urge support for HB 1800 and HB 2112, and opposition to HB 2303 and HB 2390. (Opposition to HB 2303 puts them at odds with MDV-SEIA on the agricultural solar issue.)

Virginia General Assembly session opens. What can we expect?

Photo credit: Corrina Beall

Photo credit: Corrina Beall

The General Assembly failed to act on clean energy bills in 2016, but as the 2017 legislative session gets underway, advocates hope the delay will have only increased pressure for progress this year.

New energy legislation includes the four bills negotiated over the summer by the utilities and the solar industry promoting utility, community-scale, and agricultural renewable energy projects. The “Rubin Group” (named for facilitator Mark Rubin) brought together utilities, the solar industry trade group MDV-SEIA, and a group called Powered by Facts, but largely excluded environmental and consumer interests. Not surprisingly, the resulting bills are heavily weighted towards utility-scale solar, and utility control of solar in general.

But if the chairmen of House and Senate Commerce and Labor thought the Rubin Group’s work would mean no one else would float new renewable energy bills, they were certainly wrong.

Community-scale solar. I’ve previously addressed the Rubin Group’s legislation that enables a utility-administered, community-scale program to sell solar to participants on a voluntary basis. I see Senator Wagner will be carrying the bill in the Senate, now designated SB 1393. I haven’t had time to compare the current bill to the draft previously shared with stakeholders, but I’m cautiously optimistic that it will produce a viable solar option for consumers. Even better would be HB 2112 from Delgate Keam and SB 1208 from Senator Wexton, which authorize a broader set of community solar models. Delegate Krizek’s solar gardens bill, HB 618, also authorizes shared solar.

Utility-scale solar. Another bill from the Rubin Group, SB 1395 (Wagner), would raise from 100 MW to 150 MW the size of wind and solar projects that qualify as “small renewable energy projects” subject to Permit By Rule (PBR) permitting by DEQ, and allowing utilities to use that process for facilities that won’t be rate-based. In contrast, Senator Deeds’ SB 1197 would undo much of the streamlining gained by the PBR process, sending projects to the SCC if they either disturb an area of 100 acres or more or are within five miles of a boundary between political subdivisions.

The third Rubin Group bill, Wagner’s SB 1388, would allow utilities to earn a margin when they obtain solar energy via power purchase agreements with (lower cost) third-party developers rather than building projects themselves.

Senator Marsden’s SB 813 exempts investor-owned utilities from the requirement that they consider alternative options, including third-party market alternatives, when building solar facilities that have been declared in the public interest. This is surely an attempt to smooth the way for utility-owned solar at the SCC. However, if you’re trying to get utilities to keep costs down by using third-party installers, this is the wrong incentive.

Agricultural net metering. The last bill from the Rubin Group, Senator Wagner’s SB 1394, would revoke the recently enacted code provisions that allow agricultural customers to attribute electricity from a renewable energy facility to more than one meter on their property for the purposes of net metering. The proposed legislation would terminate this provision in 2018 (grandfathering existing net metering customers for 20 years) and instead offer farmers a buy-all, sell-all option for their renewable production.

Under the proposed bill, negotiated between the utilities and Powered by Facts, farmers would have to buy all their (dirty) power from their utility at retail, and sell their renewable power to the utility at the utility’s avoided cost—essentially wholesale. This doesn’t sound like a good deal for the farmers, but we’re told it more or less pencils out. On the plus side, the bill would allow farmers to build up to 1.5 megawatts of renewable capacity on up to 25% of their land, or up to 150% of the amount of electricity they use, whichever is less, which is more than they can under today’s rules. (But since federal law allows anyone to sell power they produce from a qualifying facility into the grid at avoided cost, even this part of the bill is of dubious added benefit.)

Regardless, removing the net metering option seems both unnecessary and unwise; many farmers specifically want to run their farms on solar, for marketing reasons or otherwise, and taking away their ability to aggregate meters and use net metering will be viewed as a serious setback.

The first draft of this bill that I had seen contained a provision that projects under the new program would apply against the state’s 1% cap on total net metering output, even though the projects would not be net metered. Fortunately, I don’t see that in the current version. [Update: this provision does appear in the version of the bill reported out of the Senate subcommittee on January 27, presenting a reason sufficient in itself to oppose the legislation.]

An agricultural bill that is more readily supportable is Senator Edwards’ SB 917, which eases the rules for agricultural customer-generators and increases the size of projects that can qualify for meter aggregation under the net metering statute. It also extends the law to include small hydro projects.

PPAs. Two bills attempt to resolve the ongoing dispute over customers’ rights to use third-party power purchase agreements for their on-site renewable facilities. Delegate Toscano’s HB 1800 essentially reiterates what solar advocates believe to be existing law allowing on-site PPAs, but—as a peace offering to utilities—narrows it to exclude residential customers. Senator Edwards’ SB 918 takes a different approach, replacing the Dominion PPA pilot program with a permanent statewide program to be designed by the State Corporation Commission.

Tax credits. Delegate Hugo’s HB 1891 provides a tax credit for residents who install geothermal heat pumps—a nice idea, but it will face tough sledding in a tight budget year. That budget reality could also doom Delegate Sullivan’s HB 1632, offering a broader renewable energy property tax credit (it would include geothermal heat pumps).

In spite of the current budget deficit, Republicans are making a new attempt to reinstate taxpayer subsidies for coal mining companies (Delegate Kilgore’s HB 2198). Delegate Morefield’s HB 1917 takes a better approach, offering a new tax credit for “capital investment in an energy production facility in the coalfield region.” This is worth watching, as it is not limited to coal facilities but applies to any facility that has “the primary purpose of producing energy for sale.”

Climate. Republicans seem inclined to make a renewed attack on the EPA’s Clean Power Plan (Delegate O’Quinn’s HB 1974), even though Trump’s election seems likely to send it to an early grave. This probable fate inspired Senator Petersen’s SB 1095, which says that if and when the Clean Power Plan is really declared dead, then the notorious “rate-freeze” imposed two years ago will end. As readers know, that law (Wagner’s SB 1349 from the 2015 session), will allow Dominion to keep an estimated $1 billion in excess revenues; at the time, Dominion said the law was needed to protect its customers from rate hikes required by compliance with the Clean Power Plan. Unfortunately the condition in Petersen’s bill doesn’t seem likely to kick in for at least a year or two, and possibly more; we’d prefer to see the legislation revoke the freeze immediately, and put the ill-gotten gains to use as a massive stimulus package supporting clean energy jobs.

On the flip side, Delegate Villanueva is gamely making another run at getting Virginia to join the Regional Greenhouse Gas Initiative (HB 2018) as a way to change utility incentives and raise money for climate adaptation and clean energy.

Nuclear. Delegate Kilgore has introduced HB 2291, a bill to make it easier for Dominion Virginia Power to stick ratepayers with the costs of any upgrades it makes to its nuclear power plants. The bill further attacks and undermines the SCC’s authority to determine whether expenses are reasonable, the sort of favor to Dominion that has become a theme in recent years. Kilgore doesn’t even represent any Dominion customers; he’s in APCo territory. I guess that’s why he’s okay with raising rates for Dominion customers.

Energy efficiency. Efficiency bills suffered the same fate as renewable energy bills last year; many were offered, but few were chosen. (Actually, it might have been none. We don’t do much energy efficiency in Virginia.)

Delegate Sullivan is trying again to set energy efficiency goals with HB 1703, or at the very least to have government track our progress towards meeting (or rather, not meeting) the state’s existing goal, with HB 1465. He is also trying again to change how the SCC evaluates energy efficiency programs to make them easier to implement (HB 1636). Senator Dance’s SB 990 also sets an energy consumption reduction goal.

Delegate Krizek’s HJ 575 would authorize a study of infrastructure investments that yield energy savings. Delegate Minchew’s HB 1712 authorizes energy performance-based contracting for public bodies.

Miscellaneous. Delegate Kilgore’s HB 1760 supports a new pumped storage facility in the Coalfields region (news to me). Senator Ebbin’s SB 1258 would add energy storage to the work of the Virginia Solar Development Authority, which seems eminently sensible.

More bills are likely to be filed in the coming days, and I would promise to update you on them if I weren’t marking Trump’s inauguration by leaving the country for a week. Serious advocates should peruse the LIS website and perhaps sign up for the bill tracking service “Lobbyist in a Box.” Also watch for a clean energy lobby day that MDV-SEIA will organize, likely on the yet-to-be-announced day the House Commerce and Labor Subcommittee on Energy meets, usually in early February.

This year’s legislative session lasts a mere 45 days, weekends included. Cynics say the tight schedule limits the damage politicians can do, but in reality it just means lawmakers have to lean heavily on lobbyists and constituents—and as the lobbyists are on hand, and the constituents are at home, the schedule favors the lobbyists. So if you want to make your voice heard, now’s the time.

Even Appalachian Power doesn’t like its third-party solar option

Colleges in APCo territory want to use PPAs to install solar facilities like the one recently installed at the University of Richmond, in Dominion territory.

Colleges in APCo territory want to use PPAs to install solar facilities like the one recently installed at the University of Richmond, in Dominion territory.

Facing a withering report from a Virginia hearing examiner recommending denial of its request for a renewable energy “Rider RGP,” Appalachian Power Company (APCo) has responded with a simple message to the State Corporation Commission: um, never mind.

APCo proposed Rider RGP as an alternative to third-party power purchase agreements (PPAs) for customers wanting to install rooftop solar. The proposal would have put APCo in the middle of the deal and created a buy-all, sell-all scheme. But the proposal was roundly criticized at last year’s hearing and in witness statements as convoluted and expensive.

On September 19 APCo asked to withdraw its application, citing changed circumstances. In reality, of course, nothing has changed since the Hearing Examiner’s August 31 report, other than APCo learning it was about to lose.

The company probably doesn’t mind being rejected for a program that witnesses said no one would sign up for. The much bigger issue for the company is that if the SCC adopts the hearing examiner’s view, APCo could lose its battle to block PPAs in its service territory.

For those of you just coming to the story, here’s the Cliff Notes version (this earlier post has the unabridged telling): APCo’s customers want the ability to install solar on their property through PPAs, a financing arrangement in which a solar developer installs and owns the panels, selling the electricity that’s generated to the customer. Often this means the customer can reduce its electricity bills without incurring an up-front cost. For tax-exempt institutions like colleges that can’t take advantage of the federal 30% tax credit for solar, the PPA model means the developer can take the tax credit and pass along the savings.

Virginia utilities say this arrangement violates their monopoly on the sale of electricity. Customers point to two statutory provisions that make PPAs legal. One provision allows customers to buy renewable energy from third parties if their utility doesn’t offer it. (No utility in Virginia does.) The other provision defines a net metering customer to include one who contracts with someone else to install and operate a solar facility on the customer’s property—an apt description of a PPA arrangement. Customers would seem to have the better of the argument, surely, but no bank will finance a PPA when a deep-pocketed utility is threatening to sue.

Dominion temporarily settled the issue in its territory with a pilot program that allows some PPAs, but APCo declined to participate. Under pressure from educational institutions that want solar, APCo proposed Rider RGP as an alternative for its territory. Customers and solar advocates seized the opportunity to seek a clear ruling from the SCC on the legality of PPAs. They argued, and the Hearing Examiner agreed, that Rider RGP wasn’t just badly designed, but unnecessary, given the provisions of the statute that already allow PPAs.

APCo doesn’t want the SCC commissioners to confirm this conclusion. It hopes that by withdrawing Rider RGP, the SCC will dismiss the case and not reach the merits of the argument on PPA legality. It is urging the SCC not to consider the point at all, or if it does so, not to take it up until it considers APCo’s plan, announced in April, to offer a green tariff to customers.

That green tariff is the “changed circumstances” APCo says makes Rider RGP unnecessary. If the SCC approves the green tariff, APCo will offer to sell real renewable energy to customers who want it. APCo clearly believes that having that tariff available to customers closes off the statutory provision that allows customers to go to third-party sellers if their own utility doesn’t offer renewable energy.

The green tariff would not, however, affect the legality of PPAs under the other statutory provision, the one that defines net metering customers to include those who have renewable energy facilities located on their property but owned and operated by someone else. Nor does the offer of a green tariff seem likely to satisfy customer demand for PPAs; buying electricity from a utility through a green tariff is a very different animal from having solar panels on your own roof.

The SCC is considering APCo’s request to withdraw its proposal for Rider RGP. It issued an order asking the parties to the case to comment by September 26. Advocates are expected to oppose APCo’s request and to ask the SCC to rule definitively on the legality of PPAs. By doing so, the Commission would finally bring legal clarity to an issue that has been holding back solar development in Virginia.


Update: September 26, Dominion Virginia Power filed a motion to intervene out of time, with a brief begging the SCC not to even look at the legality of PPAs, or if it did, to reject the hearing examiner’s reading of the statute on the grounds that her opinion disagrees with Dominion’s.  Dominion’s brief notes that it wrote its own opinion into a tariff, which the SCC approved, and therefore that ought to be more important than whatever the General Assembly actually said.

On October 7, the SCC allowed APCo to withdraw its proposal, ducking the issue of PPA legality and ensuring that more time and money will be wasted on future proceedings.