COVID-19 throws a lemon at Virginia’s plan for an energy transition. It’s time for lemonade.

solar panels on a school roof

The solar panels on Wilson Middle School are saving money for Augusta County taxpayers. Photo courtesy of Secure Futures.

In mid-March, the Virginia General Assembly passed legislation to transition our economy from fossil fuels to clean energy over the coming years. Two weeks later, Virginia shut down in response to the COVID-19 pandemic. Among the businesses whose very existence is now in peril are the energy efficiency companies and solar installers we will be counting on to get us off fossil fuels.

Home weatherization and energy efficiency programs have come to an almost complete halt in Virginia, including programs run by Dominion Energy Virginia. Nationwide, the energy efficiency sector has lost almost 70,000 jobs. Meanwhile, companies that install solar, especially rooftop systems, report plummeting sales. The Solar Energy Industries Association reports that nationally, 55 percent of solar workers are already laid off or suffering cutbacks.

The timing seems terrible — although to be fair, there’s no good time for an economy-crushing, worldwide pandemic. Eventually, however, the virus will run its course or be defeated through vaccine or cure. At that point, we will face a choice: we can stagger blinking out into the sunlight aimlessly wondering now what?, or we can execute the well-developed plan we have spent these weeks and months formulating.

Let’s go with the second option.

First, it’s worth remembering that nothing happening now will change the trajectory of clean energy. Solar and wind had banner years in 2019, continuing their steady march to dominance. Wind has become the largest single source of electricity in two states, Iowa and Kansas. The island of Kauai in Hawaii is now 56 percent powered by renewable energy, mostly solar. Across the U.S. wind, solar and hydro produce more electricity than coal. Wind is the cheapest form of new electric generation nationally; solar takes pride of place in Virginia.

Meanwhile, fossil fuel is even more firmly on its way out. Six of the top seven U.S. coal companies have gone into bankruptcy since 2015. That was before the lockdown sent energy demand down, further hurting high-priced coal.

Fracked gas helped kill coal but is itself vulnerable to price competition from renewables. Odd as it sounds, the collapse in oil prices will make natural gas more expensive. That’s because oil producers in Texas and North Dakota are closing wells that produced natural gas along with oil. The tightening supply of gas may finally make fracking companies in Appalachia profitable, but it means higher prices for utilities. Wind and solar will just keep looking better.

The Trump administration is still trying futilely to hold back the tide, but the U.S. will get a lot farther riding the wave than struggling against it. Congressional leaders should declare the country “all in” on clean energy. Instead of bailing out the highly polluting fossil fuel industries, they should put that money to work creating more jobs and economic development — and actually doing something about climate change — with energy efficiency and renewables.

Congress should return the Investment Tax Credit for solar (and offshore wind) to the 30 percent level in effect last year and keep it there, instead of continuing the phase-out now in effect. Congress should also give solar owners the option of taking the credit as a cash grant, as it did during the last recession, and for the same reason: tax-based incentives are less useful in a recession, when companies can’t use the credits.

Virginia’s Sens. Tim Kaine and Mark Warner have a critical role to play in convincing their colleagues to support solar. So far neither is rising to the task.

On the state level, Northam did the right thing in signing this year’s energy legislation, allowing utilities and industry members to start planning for the future. But the Clean Economy Act gets wind and solar off to a very slow start; Dominion doesn’t have to build Virginia solar for five years yet. And though the new laws remove many policy constraints on customer-sited solar, they offer next to nothing in the way of financial incentives.

Governor Northam should make it clear he intends to make rooftop solar a priority for next year, along with projects on closed landfills, former coal mine areas, and other brownfields, with a special focus on areas hardest-hit economically. He can also encourage corporations that do business in Virginia to meet their sustainability goals with Virginia wind and solar, starting right now.

The governor should also prioritize building efficiency. Virginia will be adopting a new residential building code this year, and if past years are any indication, its energy efficiency provisions will fall short of the most recent model code standard. It’s up to the governor to make sure Virginia adopts the full code.

Local governments are already taking advantage of suddenly-empty buildings to accelerate maintenance and repairs. But it’s a good time to think bigger, with new financing tools available that make energy efficiency retrofits and solar facilities cash-positive right from the start.

Energy performance contracting allows the energy savings to pay for retrofits. The Department of Mines, Minerals and Energy keeps a list of pre-qualified energy service companies and offers expertise to help local government employees navigate the process.

This year’s legislation also greatly expanded local governments’ ability to finance on-site solar through third-party power purchase agreements, effective July 1. The PPAs are structured so that a school district, municipality or any commercial or non-profit customer can have a solar array installed at no cost, paying just for the energy produced.

In December, Fairfax County awarded contracts for PPAs to install solar on more than a hundred sites, including schools and other government buildings. The county’s contract is “rideable,” which allows other counties and cities to piggyback, getting the same terms without the need for new contract negotiations.

Unfortunately, local governments in southwest Virginia are prevented from pursuing PPAs — not by state legislation, which allows it starting July 1, but by a contract with Appalachian Power that governs their electricity purchases from the utility. The contract is up for renewal this year; disgracefully, APCo is refusing to agree to new terms allowing the localities to use solar PPAs. APCo should back off, and let local governments in economically depressed southwest Virginia start saving money and supporting solar jobs this year.

Arlington County has gone beyond on-site solar, contracting for a share of a large solar farm in southern Virginia that will provide more than 80 percent of the electricity for county government operations. It’s a model any locality can adopt.

Virginia residents and businesses also have good reasons to focus on clean energy. The enforced down-time many people are experiencing means more time to research options, and companies are motivated to offer low prices on energy efficiency upgrades and rooftop solar.

The federal government offers more generous tax credits this year than next. Credits for residential energy efficiency equipment and a deduction for energy efficient commercial buildings expire at the end of this year.

The investment tax credit for solar (as well as for geothermal heat pumps, fuel cells and small wind turbines) stands at 26% for projects placed in operation this year, but it will drop to 22% in 2021. It falls to 10% for commercial customers and disappears altogether for residential customers in 2022. If Congress acts to raise the credit to 30%, buyers will get an even bigger boost. If it doesn’t, there will be a rush this year to get projects done by the end of the year, so customers should secure their place in line now.

Virginia nonprofits have helped hundreds of residents and businesses save money on solar and EV chargers through bulk purchasing programs. Virginia Solar United Neighbors just announced a series of virtual information sessions to promote the Arlington Solar EV Co-op. And LEAP, which closed operations temporarily due to the virus, reports it has restarted two programs, Solarize NOVA and Solarize Piedmont.

In an ideal world, the U.S. would already be well along in executing a comprehensive plan for a clean energy transition, one that includes job retraining for workers, and that resists counterproductive efforts to save the fossil fuel industry. But we can do the next best thing, and use the tools of government, the market and consumer choice to speed us in the right direction.

COVID-19 has handed all of us a big, fat lemon. Let’s make some lemonade.

 

A version of this article appeared originally in the Virginia Mercury on April 30, 2020.

 

With a framework for Virginia’s energy transition in place, here’s what happens next

workers installing solar panels on a roof

One expected effect of the Clean Economy Act will be a boom in solar jobs across Virginia. Photo courtesy of NREL.

With Democrats in charge, Virginia passed a suite of bills that establish a sturdy framework for a transition to renewable energy in the electric sector.

At the center of this transformation are the Clean Economy Act, HB1526/SB851, and the Clean Energy and Community Flood Preparedness Act, HB981/SB1027. Other new laws direct further planning, make it easier for customers to install solar, improve the process for siting wind and solar farms, and expand financing options for energy efficiency and renewable energy.

Gov. Ralph Northam has signed some bills already, and has until April 11 to sign the others or send them back to the General Assembly with proposed amendments. Once signed, legislation takes effect on July 1.

I assume the Governor has other things on his mind right now than asking the General Assembly to tinker further with a bill like the Clean Economy Act, though bill opponents may be using the virus pandemic to argue for delay. That would be a self-defeating move; as the economy restarts, Virginia is going to need the infusion of jobs and investment that come with the build-out of clean energy. And one of the strongest arguments in support of our energy transition, after all, is that it will save money for consumers.

So what happens after July 1? How does this all work? Let’s look at the way these major pieces of legislation will change the energy landscape in Virginia.

Virginia joins RGGI, and CO2 emissions start to fall. 

Virginia’s Department of Environmental Quality has already written the regulations that call for Virginia power plants to reduce emissions by 30 percent by 2030. The mechanism for achieving this involves Virginia trading with the Regional Greenhouse Gas Initiative, a regional carbon cap and trade market.

The regulations have been on hold as the result of a budget amendment passed last year, when Republicans still ruled the General Assembly. After July 1, DEQ will be able to implement the regulations, with the commonwealth participating in carbon allowance auctions as early as the last quarter of this year or the first quarter of 2021.

In addition to joining RGGI, the Clean Energy and Community Flood Preparedness Act also allows the commonwealth to earn money from the allowance auctions. The Department of Housing and Community Development will spend 50 percent of auction proceeds on “low-income efficiency programs, including programs for eligible housing developments.”

The Department of Conservation and Recreation will get 45 percent of the auction proceeds to fund flood preparedness and climate change planning and mitigation through the Virginia Community Flood Preparedness Fund. The last 5 percent of proceeds will cover administrative costs, including those for administering the auctions.

Energy efficiency savings become mandatory, not just something to throw money at.

Two years ago, the Grid Transformation and Security Act required Dominion and Appalachian Power to propose more than a billion dollars in energy efficiency spending over 10 years, but the law didn’t say the programs had to actually be effective in lowering electricity demand.

This year that changed. For the first time, Virginia will have an energy efficiency resource standard (EERS) requiring Dominion to achieve a total of 5 percent electricity savings by 2025 (using 2019 as the baseline); APCo must achieve a total of 2 percent savings. The SCC is charged with setting new targets after 2025. At least 15 percent of the costs must go to programs benefiting low-income, elderly or disabled individuals, or veterans.

The EERS comes on top of the low-income energy efficiency spending funded by RGGI auctions.

Dominion and Appalachian Power ramp up renewables and energy storage. 

The Clean Economy Act requires Dominion to build 16,100 megawatts of onshore wind and solar energy, and APCo to build 600 megawatts. The law also contains one of the strongest energy storage mandates in the country: 2,700 MW for Dominion, 400 MW for Appalachian Power.

Beginning in 2020, Dominion and Appalachian must submit annual plans to the SCC for new wind, solar and storage resources. We’ll have a first look at Dominion’s plans just a month from now: the SCC has told the company to take account of the Clean Economy Act and other new laws when it files its 2020 Integrated Resource Plan on May 1.

The legislation provides a strangely long lead time before the utilities must request approval of specific projects: by the end of 2023 for APCo (the first 200 MW) or 2024 for Dominion (the first 3,000 MW). But the build-out then becomes rapid, and the utilities must issue requests for proposals on at least an annual basis.

In addition to the solar and land-based wind, Dominion now has the green light for up to 3,000 MW of offshore wind from the project it is developing off Virginia Beach, and which it plans to bring online beginning in 2024. All told, the Clean Economy Act proclaims up to 5,200 MW of offshore wind by 2034 to be in the public interest.

Dominion’s plans for new gas plants come to a screeching halt.

Before the 2020 legislative session, Dominion’s Integrated Resource Plan included plans for as many as 14 new gas combustion turbines to be built in pairs beginning in 2022. In December, the company announced plans to build four gas peaking units totaling nearly 1,000 MW, to come online in 2023 and 2024.

But that was then, and this is now. The Clean Economy Act prohibits the SCC from issuing a certificate of convenience and necessity for any carbon-emitting generating plant until at least January 1, 2022, when the secretaries of natural resources and commerce and trade submit a report to the General Assembly “on how to achieve 100 percent carbon-free electric energy generation by 2045 at least cost to ratepayers.”

Even with no further moratorium, Dominion will find it hard to sell the SCC on the need for new gas plants on top of all the renewable energy and energy storage mandated in the Clean Economy Act. Solar and battery storage together do the same job that a gas peaker would have done — but they are required, and the gas peaker is not. Meanwhile, the energy efficiency provisions of the act mean demand should start going down, not up.

Dominion has already signaled that it recognizes the days of new gas plants are largely over. On March 24, Dominion filed a request with the SCC to be excused from considering new fossil fuel and nuclear resources in its upcoming Integrated Resource Plan filing, arguing that “significant build-out of natural gas generation facilities is not currently viable” in light of the new legislation.

Fossil fuel and biomass plants start closing.

By 2024, the Clean Economy Act requires the closure of all Dominion or APCo-owned oil-fueled generating plants in Virginia over 500 MW and all coal units other than Dominion’s Virginia City Hybrid plant in Wise County and the Clover Station that Dominion co-owns with Old Dominion Electric Cooperative.

This mandate is less draconian than it sounds; it forces the closure of just two coal units, both at Dominion’s Chesterfield plant. Other Dominion coal plants in Virginia have already been retired or switched to using gas or biomass, and one additional coal plant in West Virginia lies beyond the reach of the legislation. Oil-fired peaking units at Yorktown and Possum Point were already slated for retirement in 2021 and 2022. APCo owns no coal or biomass plants in Virginia.

Although the exceptions might appear to swallow the rule, the truth is that coal plants are too expensive to survive much longer anyway. One indication of this is a March 24 report Dominion filed with the SCC showing its fuel generation sources for 2019: coal has now fallen to below 8 percent of generation.

By 2028, Dominion’s biomass plants must shut down, another victory for consumers. All other carbon-emitting generating units in Virginia owned by Dominion and APCo must close by 2045, including the Virginia City plant and all the gas plants.

As of 2050, no carbon allowances can be awarded to any generating units that emit carbon dioxide, including those owned by the coops and merchant generators, with an exception for units under 25 MW as well as units bigger than 25 MW (if they are owned by politically well-connected multinational paper companies with highly-paid lobbyists).

Solar on schools and other buildings becomes the new normal.

In December, Fairfax County awarded contracts for the installation of solar on up to 130 county-owned schools and other sites, one of the largest such awards in the nation. Using a financing approach called a third-party power purchase agreement (PPA), the county would get the benefits of solar without having to spend money upfront. The contracts were written to be rideable, meaning other Virginia jurisdictions could piggyback on them to achieve cost savings and lower greenhouse gas emissions.

Fairfax County’s projects, along with others across the state, hit a wall when, on Jan. 7, the SCC announced that the 50 MW program cap for PPAs in Dominion territory had been reached. But with the passage of the Clean Economy Act and Solar Freedom legislation, customers will be able to install up to 1,000 MW worth of solar PPAs in Dominion territory and 40 MW in APCo territory.

Fairfax County schools will soon join their counterparts in at least 10 other jurisdictions across the state that have already installed solar. With the PPA cap no longer a barrier, and several other barriers also removed, local governments will increasingly turn to solar to save money and shrink their carbon footprints.

Virginia agencies start working on decarbonizing the rest of the economy. 

In spite of its name, the Clean Economy Act really only tackles the electric sector, with a little spillover into home weatherization. That still leaves three-quarters of the state’s greenhouse gas emissions to be addressed in transportation, buildings, agriculture and industry. Ridding these sectors of greenhouse gas emissions requires different tools and policies.

Other legislation passed this session starts that planning process. SB94(Favola) and HB714 (Reid) establish a policy for the commonwealth to achieve net-zero emissions economy-wide by 2045 (2040 for the electric sector) and require the next Virginia Energy Plan, due in 2022, to identify actions towards achieving the goal. Depending on who the next governor is, we may see little or nothing in the way of new proposals, or we may see proposals for transportation and home electrification, deep building retrofits, net-zero homes and office buildings, carbon sequestration on farm and forest land and innovative solutions for replacing fossil fuels in industrial use.

Collateral effects will drive greenhouse gas emissions even lower.

Proposed new merchant gas plants are likely to go away. With Virginia joining RGGI and all fossil fuel generating plants required to pay for the right to spew carbon pollution, the developers of two huge new merchant gas plants proposed for Charles City County will likely take their projects to some other state, if they pursue them at all.

Neither the 1,600 MW Chickahominy Power Station and the 1,050 C4GT plant a mile away planned to sell power to Virginia utilities; their target is the regional wholesale market, which currently rewards over-building of gas plant capacity even in the absence of demand. The Chickahominy and C4GT developers sought an exemption from RGGI through legislation; the bill passed the Senate but got shot down in the House.

If the C4GT plant goes away, so too should Virginia Natural Gas’ plans for a gas pipeline and compressor stations to supply the plant, the so-called Header Improvement Project.

Other coal plants will close. Although the CEA only requires Dominion to retire two coal units at its Chesterfield Power Station, other coal plants in the state will close by the end of this decade, too. That’s because the economics are so heavily against coal these days that it was just a matter of time before their owners moved to close them.

Adding the cost of carbon allowances under RGGI will speed the process along. That includes the Clover Station, which Dominion owns in partnership with Old Dominion Electric Cooperative (ODEC), and the Virginia City Hybrid Electric plant in Wise County, Dominion’s most expensive coal plant, which should never have been built. 

The Atlantic Coast and Mountain Valley Pipelines find themselves in more trouble than ever. If I had a dollar for every time a Dominion or Mountain Valley spokesperson said, “Our customers desperately need this pipeline,” I would not be worried about the stock market right now.

The fact is that no one was ever sure who those customers might be, other than affiliates of the pipeline owners themselves—and that doesn’t exactly answer the question. With Virginia now on a path away from all fossil fuels, neither pipeline has a path to profitability inside Virginia any longer, if they ever had one.

 

A version of this article originally appeared in the Virginia Mercury on March 31. 

New laws clear away barriers to small solar projects

Edward Hicks’ “Peaceable Kingdom,” Metropolitan Museum of Art. Not shown: the 50 guys with muskets making darn sure the lions don’t try anything.

Virginia General Assembly members have an expression for when opposing interests agree on a bill: they call it “peace in the valley.”

The phrase comes from a gospel song by Thomas A. Dorsey, written for Mahalia Jackson and then later sung by a bunch of white guys including Red Foley and Elvis Presley. The lyrics, written on the eve of World War II, speak of a longing for the peace of the afterlife, where “the bear will be gentle, the wolf will be tame, and the lion will lay down by the lamb.”

I’m not sure the General Assembly has ever inspired anything quite so wonderful as the song describes. More typically, a legislator uses the expression to indicate that a bunch of special interests, having duked it out amongst themselves, have now each gotten everything they thought they could get out of negotiations and so are offering up a compromise that legislators can adopt without having to trouble themselves too much with the details.

So, not exactly the peace of God, but still a pretty good state of affairs from the point of view of committee members who have thirty or forty other bills to deal with that day.

Peace rarely used to characterize bills supporting distributed solar generation. The lion had no reason to lie down by the lamb. Indeed, more typically the lamb was lunch.

But the November election shifted the balance of power in the General Assembly. At first it wasn’t clear how much power the lion and bear were going to have to cede. In fact, no one is quite sure even now where the balance of power lies, even after weeks of intense skirmishing finally produced the flawed but-still-transformational Clean Economy Act. The bill passed, and the parties all claimed victory, but anyone who thinks there might be peace in the energy valley is advised to stick around for next year.

The skirmishing over distributed solar was decidedly less intense. Advocates and utilities achieved peace on a number of provisions removing barriers to rooftop solar, dramatically increasing program caps for third-party power purchase agreements (PPAs), raising the net metering cap, establishing shared solar programs, and making it easier for customers in homeowner’s associations to install solar.

Much work remains. Removing barriers is a necessary first step, but now the challenge is to make small-scale solar a priority for Virginia. The Clean Economy Act focused on cheap utility-scale projects, but an economy that runs primarily on renewables needs solar on places other than farmland. Getting to 100 percent carbon-free energy means putting solar on as many sunny homes and businesses as possible—not to mention government buildings, warehouses, data centers, parking lots, highway rest areas, closed landfills, brownfields, former mining sites and vacant land around airports.

Solar Freedom and the Clean Economy Act

The final version of the Solar Freedom bill, HB572 (Keam) and SB710(McClellan), made eight changes affecting customers of investor-owned utilities. Customers of electric cooperatives are excluded; a law passed last year addressed many of these issues.

• It raises the cap on the total amount of net metered solar allowed from 1 percent currently to 6 percent (broken out as 1 percent for low and moderate income customers and 5 percent for everyone else). This means customers installing rooftop solar will continue getting credit for surplus energy at the retail rate. When net-metered projects reach 3 percent, or in 2024 for APCo or 2025 for Dominion, the State Corporation Commission will conduct a solar study to determine the appropriate rate structure for new net metering customers. Existing net metering customers will not be affected.

• It raises the program cap on third-party power purchase agreements (PPAs). PPAs are the financing mechanism that schools, local governments, universities and other customers have been using to install solar on-site with no money down. The original program cap of 50 MW in Dominion territory was reached this fall, halting projects across the state. In Dominion territory, the limit will now go to 500 MW for jurisdictional customers (that’s most people) and 500 MW for non-jurisdictional customers (including local governments and public schools). The new cap in Appalachian Power territory is 40 MW for all customers, and there will be no limit in Old Dominion Power (Kentucky Utilities) territory. In addition, the legislation broadens who can take advantage of this program to any tax-exempt customer, and all other customers with projects over 50 kW.

• It increases the allowable size of net-metered commercial projects from 1 MW today to 3 MW.

• It increases the allowable size of residential net-metered projects to 25 kW, from 20 kW today.

• It removes standby charges for residential customers with solar facilities of less than 15 kW in Dominion territory, and removes them entirely for customers of Appalachian Power and Old Dominion Power.

• It allows residents of apartment buildings and condominiums in Dominion Energy and Old Dominion Power territories to share the output of on-site solar facilities.

• In Dominion territory, it allows customers to install enough solar to meet 150 percent of their previous year’s demand, recognizing the needs of growing families and EV owners. In APCo territory the limit remains at 100 percent of previous demand.

• Finally, it allows Fairfax County to move forward on a 5 MW solar project on a closed landfill, with the electricity serving government facilities. This will be the first such project in the state.

Solar Freedom overlaps with the Clean Economy Act, HB1526 (Sullivan) and SB851 (McClellan), on several of these provisions, including the net metering cap and PPAs. The Clean Economy Act also creates a Renewable Portfolio Standard (RPS) focused on utility-scale projects, but with a small carve-out for distributed “wind, solar and anaerobic digestion resources of one megawatt or less located in the Commonwealth.” The carve-out is limited to 1 percent of Dominion’s RPS targets. This level is so modest it probably won’t act as a market stimulus, especially for projects not owned by Dominion itself, and the addition of anaerobic digestion should give anyone pause. Also, there is no carve-out in APCo territory.

The failure of the Clean Economy Act to drive small-scale solar growth is a missed opportunity that will need to be addressed in the future if the General Assembly truly wants to achieve a clean energy economy. I recommend taking away the appalling subsidies for paper companies and letting those millions fund distributed solar.

Community solar

The provision in Solar Freedom that allows residents of multifamily buildings to share onsite solar arrays looks favorable to customers but requires an SCC proceeding this year to determine the bill credit rate for subscribers. The rate “shall be set such that the shared solar program results in robust project development and shared solar program access for all customer classes.” Further, “the Commission shall annually calculate the applicable bill credit rate as the effective retail rate of the customer’s rate class, which shall be inclusive of all supply charges, delivery charges, demand charges, fixed charge, and any applicable riders or other charges to the customer.”

While the Solar Freedom provision is restricted to multifamily residential buildings, the General Assembly also passed legislation more generally allowing for third-party owned community solar, rebranded as “shared solar.”

SB629 (Surovell) and HB1634 (Jones) instruct the SCC to set up a shared solar program for customers of Dominion and Old Dominion Power by Jan. 1, 2021. Shared solar projects must be no larger than 5 MW, can be owned by any for profit or nonprofit entity, and require at least three subscribers. The program is capped at a total of 150 MW, with an additional 50 MW possible if the utility demonstrates that 45 MW of shared solar has gone to low-income consumers.

The success of a shared solar program ultimately depends on whether project owners can make money and customers can save money. It remains to be seen whether that will happen. The provisions in these bills are less favorable to customers than the multifamily solar provisions of Solar Freedom. Customers will have to pay a minimum bill amount (waived for low-income customers), and there is no requirement that the bill credit rate be set at a rate than results in “robust project development.”

Finally, HB573 (Keam) requires that community solar projects owned by investor-owned utilities must include higher-cost facilities located in low-income areas.

Homeowner associations

Another successful piece of legislation is HB414 (Delaney) and SB504(Petersen), clarifying the respective rights of homeowners and HOAs when it comes to solar panels.

Since 2014, Virginia law has prohibited HOAs from banning solar panels unless the ban appears in the association’s recorded declaration. However, the law respects the right of HOAs to place “reasonable restrictions” on the size, place, and manner of placement of solar facilities on members’ property.

The fact that the law did not define “reasonable” turned out to be a problem. Some HOAs decided it was “reasonable” to insist solar panels be confined to the rear of a roof, whether there was sunshine back there or not. The result has been acrimony, added expense and blocked projects.

Aaron Sutch of Solar United Neighbors of Virginia estimates that since the 2014 legislation, HOAs have blocked over 300 Virginia installations with a value of over $6 million. Sutch negotiated with lobbyists for homeowners associations to achieve peace in this particular valley.

The new legislation provides that a restriction is not reasonable if it increases the cost of installation of the solar panels by 5 percent over the projected cost of the initially proposed installation, or reduces the energy production by 10 percent below the projected production. The owner must provide documentation prepared by an independent solar panel design specialist to show that the restriction is not reasonable by these criteria.

Other legislation

A few other bills should help customers finance solar panels.

B654 (Guy) authorizes DMME to sponsor a statewide financing program for commercial solar, energy efficiency and stormwater investments. The effect will be to boost the availability of low-interest financing through Commercial Property Assessed Clean Energy (C-PACE) in areas of the state where the locality has not developed a program of its own.

B754 (Marsden) authorizes (though it does not require) electric cooperatives to establish on-bill financing of energy efficiency and renewable energy. The program allows for the costs to be paid for out of the savings these improvements deliver. The coops asked for this authority, so presumably at least one plans to follow through.

Finally, B542 (Edwards) repeals the sunset date on crowdfunding provisions and provides fixes for obstacles to a financing approach that, to my knowledge, has been used only once for solar projects in Virginia.

This article appeared first in the Virginia Mercury on March 18,2020. 

It was a messy, chaotic General Assembly Session. It also worked out pretty well.

Solar arrays on Richmond Public Schools were some of the last projects to go forward before a statutory limit on PPAs halted similar projects across the state. Legislation this year raises the cap on PPAs. Photo credit Secure Futures.

This time last year, I didn’t have much good to say about the General Assembly session that had just concluded. This year, try as I might to be cynical and gloomy (and I do make a good effort), I see mostly blue skies. Or at worst, light gray. What follows is a brief run-down of the bills that passed.

Bills that were still alive at the time of my halftime report but that don’t appear in today’s roundup are dead for the year.

Most of these bills don’t yet have the Governor’s signature. Virginia allows the Governor to propose amendments, so what you see here may not be the final word. Bills that do get signed take effect July 1.

Energy Transition

HB1526/SB851, the Clean Economy Act, is an omnibus energy bill that contains a two-year moratorium on new fossil fuel plants, mandatory carbon reductions, mandatory energy efficiency savings, mandatory construction of wind, solar and offshore wind, mandatory energy storage acquisition targets, mandatory closures of some coal and biomass plants, and a mandatory renewable portfolio standard, along with cost recovery provisions, a new program to limit utility bills of low-income earners, and some loosening of restrictions on net metering and third-party power purchase agreements.

The bill is not perfect, and the clean energy transformation it strives for is incomplete. Its provisions mostly don’t apply to electric cooperatives, and while it forces the eventual closure of Dominion’s biomass plants, it actually requires utility customers to subsidize biomass use by paper companies. Dominion is given too free a rein on spending, the energy efficiency targets are weak, and the bill focuses on utility-scale projects to the almost total exclusion of customer-sited projects.

For all that, the legislation is groundbreaking and transformational. Advocates will be back next year with refinements to the bill and proposals to fill the gaps, but putting this necessary framework in place is a huge achievement for Virginia.

SB94 (Favola) and HB714 (Reid) rewrites the Commonwealth Energy Policy to bring it in line with Virginia’s commitment to dealing with climate change, and even to challenge leaders to do more. The bill sets a target for net-zero greenhouse gas emissions economy wide by 2045, and in the electric sector by 2040. These targets are more ambitious than what is in the Clean Economy Act; not only is the electric sector decarbonization deadline earlier (and inclusive of the coops), this is the first legislation to set a target for the economy as a whole. The Commonwealth Energy Policy is advisory and tends to be ignored in practice; however, the bill also requires that the Virginia Energy Plan, developed every four years in the first year of a new governor’s term, include actions to achieve a net-zero economy by 2045 for all sectors.

HB672 (Willett) establishes a policy “to prevent and minimize actions that contribute to the detrimental effects of anthropogenic climate change in the Commonwealth.” State agencies are directed to consider climate change in any actions involving state regulation or spending. Local and regional planning commissions are required to consider impacts from and causes of climate change in adapting comprehensive plans.

RGGI

The Democratic takeover of the General Assembly means Virginia will finally join the Regional Greenhouse Gas Initiative (RGGI). HB981 (Herring) and SB1027 (Lewis), the Clean Energy and Community Flood Preparedness Act, directs DEQ to enter the RGGI auction market. Auction allowances are directed to funds for flood preparedness, energy efficiency and climate change planning and mitigation. As with the Clean Economy Act, votes for the RGGI fell along partisan lines but for one Republican senator, Jill Vogel, who voted for both.

RPS

The Clean Economy Act contains a mandatory renewable portfolio standard (RPS) requiring utilities to include in their electricity mix a percentage of renewable energy that ratchets up over time. It’s weak, especially for distributed solar, and it allows paper company biomass to qualify—an inexcusable corporate welfare provision for politically powerful WestRock and International Paper.

Customer-sited solar/net metering

Watch this space for a post dedicated to net metering, PPAs and community solar bills. Meanwhile, here’s the short version:

Solar Freedom SB710 (McClellan), HB572 (Keam) and HB1184 (Lopez) lift barriers to customer-sited renewable energy such as rooftop solar. HB1647 (Jones) contains some of the elements of Solar Freedom, but a few provisions are in conflict. Advocates have asked the Governor to sign the first three bills but not the fourth. Some Solar Freedom provisions are also in the Clean Economy Act. The new provisions lift the net metering cap to 6% for IOUs; raise the PPA cap to 1,000 MW in Dominion territory and 40 MW in APCo territory; remove standby charges below 15 kW in Dominion territory and completely for APCo; raise the residential size cap to 25 kW and the commercial project size cap to 3 MW; allow Dominion customers to install enough solar to meet 150% of the previous year’s demand (APCo stays at 100%); allow shared solar on multifamily buildings; and enable a 5 MW landfill solar project in Fairfax County to move forward. The provisions do not apply to electric cooperatives.

HOAs HB414 (Delaney) and SB504 (Petersen) clarifies the respective rights of homeowners associations (HOAs) and residents who want to install solar. The law allows HOAs to impose “reasonable restrictions,” a term some HOAs have used to restrict solar to rear-facing roofs regardless of whether these get sunshine. The bill clarifies that HOA restrictions may not increase the cost of the solar facility by more than 5%, or decrease the expected output by more than 10%.

Community solar

SB629 (Surovell) and HB1634 (Jones) creates a program for shared-solar that allows customers to purchase subscriptions in a solar facility no greater than 5 MW.

HB573 (Keam) requires that an investor-owned utility that offers a so-called “community solar” program as authorized by 2017 legislation must include facilities in low-income communities “of which the pilot program costs equal or exceed the pilot program costs of the eligible generating facility that is located outside a low-income community.”

Offshore wind

The Clean Economy Act contains detailed provisions for the buildout and acquisition of offshore wind. SB998 (Lucas), SB860 (Mason) and HB1664 (Hayes) puts the construction or purchase of at least 5,200 MW of offshore wind in the public interest and governs cost recovery for the wind farms under development by Dominion. The bills appear to have the same language that is in the Clean Economy Act.

HB234 (Mugler) establishes a Division of Offshore Wind within the Department of Mines, Minerals and Energy. Its role is to help facilitate the Hampton Roads region as a wind industry hub, coordinate the word of state agencies, develop a stakeholder engagement strategy, and basically make sure this industry gets underway.

Nuclear

SB828 (Lewis) defines “clean” and “carbon-free” energy to include nuclear energy for purposes of the Code. SB817 (Lewis) declares that nuclear energy is considered a clean energy source for purposes of the Commonwealth Energy Policy.

HB1303 (Hurst) and SB549 (Newman) direct DMME to develop a strategic plan for the role of nuclear energy in moving toward renewable and carbon-free energy.

Energy Efficiency

HB1526/SB851, the Clean Economy Act, contains a mandatory energy efficiency resource standard (EERS) and other provisions for spending on low-income EE programs. HB1450 (Sullivan) appears to be the same as the efficiency provisions of the Clean Economy Act. A sentence added late in the process provides that the bill won’t take effect until passed again in 2021. Presumably the passage of the Clean Economy Act makes this bill moot.

HB981 (the RGGI bill) specifies that a portion of the funds raised by auctioning carbon allowances will fund efficiency programs.

HB1576 (Kilgore) makes it harder for large customers to avoid paying for utility efficiency programs. In the past, customers with over 500 kW of demand were exempt; this bill allows only customers with more than 1 MW of demand to opt out, and only if the customer demonstrates that it has implemented its own energy efficiency measures.

HB575 (Keam) beefs up the stakeholder process that Dominion and APCo engage in for the development of energy efficiency programs.

SB963 (Surovell) establishes the Commonwealth Efficient and Resilient Buildings Board to advise the Governor and state agencies about ways to reduce greenhouse gas emissions and increase resiliency. Every agency is required to designate and energy manager responsible for improving energy efficiency and reducing greenhouse gas emissions.

SB628 (Surovell) requires the residential property disclosure statement provided by the Real Estate Board on its website to include advice that purchasers should obtain a residential building energy analysis as well as a home inspection prior to settlement.

Energy storage

The Clean Economy Act requires that by 2035, Appalachian Power will construct 400 MW of energy storage and Dominion 2,700 MW. None of the projects can exceed 500 MW, except for one project of up to 800 MW for Dominion (a possible reference to the pumped storage project Dominion is reportedly considering). Projects must meet competitive procurement requirements, and at least 35% of projects must be developed by third-party developers.

SB632 (Surovell) has a fair amount of overlap with the Clean Economy Act, but the details are different, and it will be interesting to see what the Governor does about that. SB632 makes it in the public interest to develop 2,700 MW of energy storage located in Virginia by 2030. At least 65% must take the form of a “purchase by a public utility of energy storage facilities owned by persons other than a public utility or the capacity from such facilities.” Up to 25% of facilities do not have to satisfy price competitiveness criteria “if the selection of the energy storage facilities materially advances non-price criteria, including favoring geographic distribution of generating facilities, areas of higher employment, or regional economic development.” Utility Integrated Resource Plans must include the use of energy storage and must include “a long-term plan to integrate new energy storage facilities into existing generation and distribution assets to assist with grid transformation.”

SB632 also fixes a problem introduced a couple of years ago, when the ownership or operation of storage facilities was added to the definition of a utility in one chapter of the Code (§56.265.1), though not in others. With the fix, a public utility may own or operate storage, but so can third parties without them thereby becoming utilities.

HB1183 (Lopez) requires the SCC to establish a task force on bulk energy storage resources.

Siting, permitting, and other issues with utility-scale renewable energy 

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

HB656 (Heretick) and SB875 (Marsden) allow (but do not require) local governments to incorporate into their zoning ordinances national best practices standards for solar PV and batteries.

HB1131 (Jones) and SB762 (Barker) authorize localities to assess a revenue share of up to $1,400 per megawatt on solar PV projects, in exchange for which an existing tax exemption is expanded.

HB657 (Heretick) exempts solar facilities of 150 MW or less from the requirement that they be reviewed for substantial accord with local comprehensive plans, if the locality waives the requirement.

HB1434 (Jones) and SB763 (Barker) provides a step-down of the existing 80% machinery and tools tax exemption for large solar projects, and eliminates it after 2030 for projects over 5 MW.

SB870 (Marsden) authorizes local planning commissions to grant special exceptions for solar PV projects in their zoning ordinances and include certain regulations and provisions for conditional zoning for solar projects.

HB1675 (Hodges) requires anyone wanting to locate a renewable energy or storage facility in an opportunity zone to execute a siting agreement with the locality.

Grants, tax deductions, tax credits and other financing

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

SB754 (Marsden) authorizes electric cooperatives to establish on-bill financing programs for energy efficiency and renewable energy.

HB1656 (O’Quinn) authorizes Dominion and APCo to design incentives for low-income people, the elderly, and disable persons to install energy efficiency and renewable energy, to be paid for by a rate adjustment clause.

HB1707 (Aird) makes changes to the Clean Energy Advisory Board, which is (already) authorized to administer public grant funding.

SB1039 (Vogel) allows a real property tax exemption for solar energy equipment to be applied retroactively if the taxpayer gets DEQ certification within a year.

SB542 (Edwards) repeals the sunset date on crowdfunding provisions and provides fixes for certain existing obstacles to this financing approach.

Customer rights to shop for renewable energy

HB868 (Bourne) allows customers to buy 100% renewable energy from any licensed supplier, regardless of whether their own utility has its own approved tariff. The Senate killed a companion bill, and Commerce and Labor passed HB868 only with an amendment that requires the bill to be reenacted in 2021. (Credit Edwards, Deeds, Ebbin and Bell for not going along with the amendment.) After Senate passage the bill went to conference, and the House conferees caved. So technically the bill passed, but it has no effect. Interesting note: 41 House Republicans still voted against it in the end.

HB 889 (Mullin) was originally broader than HB868, but after the Senate got through with it, the bill is now a pilot program for the benefit of just those large corporations that, as of February 25, 2019, had filed applications seeking to aggregate their load in order to leave Dominion and buy renewable energy elsewhere. The pilot program is capped at 200 MW, and the SCC will review it in 2022.

Other utility regulation

HB528 (Subramanyam) requires the SCC to determine the amortization period for recovery of costs due to the early retirement of generating facilities owned or operated by investor-owned utilities. In the absence of this legislation, Dominion would have been allowed to use excess earnings for immediate payoffs of the costs of early fossil fuel plant closures; this puts the SCC back in charge of the schedule. The fact that this bill passed is nothing short of miraculous. House Republicans voted against it en masse, and it made it through Senate Commerce and Labor over the objections of Dominion’s best friends from both parties (though most came around for the floor vote when it was clear it would pass).

SB731 (McClellan) affects a utility’s rate of return. The SCC determines this rate by looking first at the average returns of peer group utilities, and then often going higher. The bill lowers the maximum level that the SCC can set above the peer group average. Note that although this bill is recorded as having passed both chambers, it looks like there were amendments that do not appear on the Legislative Information Service website.

HB167 (Ware) requires an electric utility that wants to charge customers for the cost of using a new gas pipeline to prove it can’t meet its needs otherwise, and that the new pipeline provides the lowest-cost option available to it. (Note that this cost recovery review typically happens after the fact, i.e., once a pipeline has been built and placed into service.) Ware acceded to some amendments that Dominion wanted, and eventually Dominion told legislators the company was not opposed to the bill. Hence it passed both chambers unanimously. Notwithstanding Dominion’s happy talk, this bill makes cost recovery for the Atlantic Coast Pipeline much, much more difficult, one more indication that Dominion may be preparing to fold up shop on this project.

[Updated March 17 to correct an error–I had included a bill as having passed that in fact died in the House. Bummer.]

It’s halftime at the GA, and do we ever have a show!

battle scene

Tense negotiations over the Clean Economy Act. (Aniello Falcone, Metropolitan Museum of Art)

Welcome to “Crossover,” the day on which the Virginia House and Senate have to finish the work on their bills and send them over to the other chamber. This is sudden death time; if a bill didn’t get across the finish line in time, it is dead for the year.

In past years, henceforth to be known as “the bad old days,” almost nothing good even got out of committee, much less reached Crossover. Clean energy advocates could pretty much plan vacations for the second half of February.

This year the Democrats are on a tear, especially in the House. Yes, a lot of good bills have been heavily watered down. This is still the Old Dominion, with the emphasis on Dominion. And it is definitely too early to break out the champagne, because the action isn’t over for the bills still in play. But overall, 2020 is shaping up to be a watershed year for clean energy.

BILLS STILL ALIVE

Energy Transition

HB1526/SB851, the Clean Economy Act, has been the subject of intense and continuous negotiation. First there were a bunch of amendments that weakened it; then there were a bunch that strengthened it. It’s been a wild ride, and we may still see more changes during the second half of Session. But it’s alive! (HB1526 passed the House 52-47; Democrats Rasoul and Carter voted no. SB851 passed the Senate on a party-line vote of 21-19.)

SB94 (Favola) rewrites the Commonwealth Energy Policy to bring it in line with Virginia’s commitment to dealing with climate change. The bill sets a target for net-zero greenhouse gas emissions economy wide by 2045, and in the electric sector by 2040. This section of the Code is for the most part merely advisory; nonetheless, it is interesting that Dominion Energy supported the bill. (Passed the Senate 21-18, on party lines.)

Delegate Reid’s HB714 is similar to SB94 but contains added details, some of which have now been incorporated into SB94. (Passed the House 55-45 with a substitute.)

HB672 (Willett) establishes a policy “to prevent and minimize actions that contribute to the detrimental effects of anthropogenic climate change in the Commonwealth.” State agencies are directed to consider climate change in any actions involving state regulation or spending. Local and regional planning commissions are required to consider impacts from and causes of climate change in adapting comprehensive plans. (Passed the House 55-44 with a substitute.)

HB547 (Delaney) establishes the Virginia Energy and Economy Transition Council to develop plans to assist the Commonwealth in transitioning from the use of fossil fuel energy to renewable energy by 2050. The Council is to include members from labor and environmental groups. (Passed the House 54-45.)

RGGI bills, good and bad

The Democratic takeover of the General Assembly means Virginia will finally join the Regional Greenhouse Gas Initiative (RGGI), either according to the regulations written by DEQ or with a system in place that raises money from auctioning carbon allowances.

HB981 (Herring) and SB1027 (Lewis) is called the Clean Energy and Community Flood Preparedness Act. It implements the DEQ carbon regulations and directs DEQ to enter the RGGI auction market. Auction allowances are directed to funds for flood preparedness, energy efficiency and climate change planning and mitigation. We are told this is the Administration’s bill. A similar bill, HB20 (Lindsey), was incorporated into HB981. (HB981 passed the House 53-46. SB1027 passed the Senate 22-18.)

SB992 (Spruill) requires the Air Board to give free allowances for three years to any new power plant that was permitted before June 26, 2019, the effective date of the carbon trading regulations. Essentially it gives special treatment to two planned gas generation plants that aren’t needed and therefore have sketchy economics unless they get this giveaway. Clean energy advocates will be looking to kill this one in the House. (Passed the Senate 27-13. A number of Democrats who should know better voted for the bill.)

RPS

The Clean Economy Act contains a renewable portfolio standard (RPS) requiring utilities to include in their electricity mix a percentage of renewable energy that ratchets up over time. In addition, HB1451 (Sullivan) is a stand-alone RPS bill that also includes an energy storage mandate. It appears to be identical to the RPS and storage provisions of the CEA (of which Sullivan is also the patron). (Passed the House 52-47.)

Customer-sited solar/net metering

Solar Freedom SB710 (McClellan) and HB572 (Keam) lifts barriers to customer-sited renewable energy such as rooftop solar. The changes include lifting the caps on PPAs and net metering, and eliminating standby charges. Nearly identical versions were filed by Delegates Lopez (HB1184) (rolled into HB572) and Simon (HB912) (ditto). SB532 (Edwards), a stand-alone bill to make PPAs legal, was rolled into SB710. (SB710 passed the Senate 22-18 with a substitute that is much more limited than the original bill. HB572 passed the House with just a minor substitute 67-31. HB1647 (Jones) is a Solar Freedom bill that also includes community solar. (Passed the House 55-45.) Several provisions of Solar Freedom also appear in the Clean Economy Act.

HOAs HB414 (Delaney) and SB504 (Petersen) clarifies the respective rights of homeowners associations (HOAs) and residents who want to install solar. The law allows HOAs to impose “reasonable restrictions,” a term some HOAs have used to restrict solar to rear-facing roofs regardless of whether these get sunshine. The bill clarifies that HOA restrictions may not increase the cost of the solar facility by more than 5%, or decrease the expected output by more than 10%. (HB414 passed the House 95-4. SB504 passed the Senate 40-0.)

Community solar

HB1647 (Jones) (see above) includes community solar in a bill that otherwise looks like Solar Freedom.

SB629 (Surovell) creates a program for “solar gardens.” (Substitute passed the Senate 39-0.)

HB1634 (Jones) requires utilities to establish shared-solar programs that allows customers to purchase subscriptions in a solar facility no greater than 5 MW. (Amended with a substitute; it now looks a lot like SB629. Passed the House 99-0.)

HB573 (Keam) affects the utility-controlled and operated “community solar” programs required by 2017 legislation. The bill requires that “an investor-owned utility shall not select an eligible generating facility that is located outside a low-income community for dedication to its pilot program unless the investor-owned utility contemporaneously selects for dedication to its pilot program one or more eligible generating facilities that are located within a low-income community and of which the pilot program costs equal or exceed the pilot program costs of the eligible generating facility that is located outside a low-income community.” (Passed the House 90-8.)

Offshore wind

The CEA contains detailed provisions for the buildout and acquisition of offshore wind. HB234 (Mugler) directs the Secretary of Commerce and Trade to develop an offshore wind master plan. (Passed House unanimously with substitute.)

SB860 (Mason) and HB1664 (Hayes) puts the construction or purchase of at least 5,200 MW of offshore wind in the public interest. (SB860 passed the Senate 22-18. HB1664 amended to incorporate HB1607, but with less gold-plating than the other bill. HB1664 passed the House 65-34.)

HB1607 (Lindsey) and SB998 (Lucas) allows Dominion to recover the costs of building offshore wind farms as long as it has a plan for the facilities to be in place before January 1, 2028 and that it has used reasonable efforts to competitively source the majority of services and equipment. All utility customers in Virginia, regardless of which utility serves them, will participate in paying for this through a non-bypassable charge. Surely this bill came straight from Dominion. (HB1607 amended to incorporate HB1664; only 1664 moves forward. SB998 passed the Senate 40-0.)

Nuclear and biomass

SB828 and SB817 declare that any time the Code or the Energy Policy refers to “clean” or “carbon-free” energy, it must be read to include nuclear energy. In subcommittee, Senator Lewis suddenly announced he was amending the bills to add “sustainable biomass” as well. After an uproar and a crash course on biomass, both bills eventually went back to being only about nuclear. (Both bills passed the Senate unanimously.) Unfortunately, some biomass from paper companies did creep into the Clean Economy Act in spite of the best efforts of clean energy advocates.

Energy Efficiency

HB1526/SB851, the Clean Economy Act, contains a mandatory energy efficiency resource standard (EERS) and contains other provisions for spending on low-income EE programs. HB981 (the RGGI bill) specifies that a portion of the funds raised by auctioning carbon allowances will fund efficiency programs.

There are also a few standalone efficiency bills. HB1450 (Sullivan) and SB354 (Bell) appear to be the same as the efficiency provisions of the CEA, though the standalone applies only to Dominion and APCo. (HB1450 passed House 75-24,picking up a respectable number of Republicans. SB354 stricken at request of patron in C&L.)

HB1576 (Kilgore) doesn’t set new efficiency targets, but it makes it harder for large customers to avoid paying for utility efficiency programs. In the past, customers with over 500 kW of demand were exempt; this bill allows only customers with more than 1 MW of demand to opt out, and only if the customer demonstrates that it has implemented its own energy efficiency measures. (Passed the House, 99-0.)

HB575 (Keam) beefs up the stakeholder process that Dominion and APCo engage in for the development of energy efficiency programs. (Passed the House 99-0 and referred to Senate C&L.)

SB963 (Surovell) establishes the Commonwealth Efficient and Resilient Buildings Board to advise the Governor and state agencies about ways to reduce greenhouse gas emissions and increase resiliency. Every agency is required to designate and energy manager responsible for improving energy efficiency and reducing greenhouse gas emissions. (Passed the Senate 40-0.)

SB628 (Surovell) requires the residential property disclosure statement provided by the Real Estate Board to include advice that purchasers should obtain a residential building energy analysis as well as a home inspection prior to settlement. (Passed the Senate 26-14.)

Energy storage

HB1183 (Lopez) requires the SCC to establish a task force on bulk energy storage resources. (Passed the House 91-9 with a substitute.)

SB 632 (Surovell) creates a storage target of 1,000 MW and states that this is in the public interest.  Senator Surovell says this bill originated with the Governor’s office. (Passed the Senate 20-19 with a substitute.)

Siting, permitting, and other issues with utility-scale renewable energy

HB1327 (Austin) allows localities to impose property taxes on generating equipment of electric suppliers utilizing wind turbines at a rate that exceeds the locality’s real estate tax rate by up to $0.20 per $100 of assessed value. Under current law, the tax may exceed the real estate rate but cannot exceed the general personal property tax rate in the locality. Wind developer Apex Clean Energy helped develop the bill and supports it. (Passed the House 81-12, now goes to Senate Finance.)

HB656 (Heretick) and SB875 (Marsden) allow local governments to incorporate into their zoning ordinances national best practices standards for solar PV and batteries. (Both bills passed their chambers unanimously with substitute language.)

HB1131 (Jones) and SB762 (Barker) authorize localities to assess a revenue share of up to $0.55 per megawatt-hour on solar PV projects, in exchange for which an existing tax exemption is expanded. (HB1131 Passed the House 54-42 with a substitute. SB762 passed Senate 40-0.)

HB657 (Heretick) and SB893 (Marsden) exempt solar facilities of 150 MW or less from the requirement that they be reviewed for substantial accord with local comprehensive plans. (HB657 passed the House with a substitute, 59-41. SB893 was passed by indefinitely—killed—in Local Government.)

HB1434 (Jones) and SB763 (Barker) reduces the existing 80% machinery and tools tax exemption for large solar projects. (HB1434 passed the House 57-41. SB763 passed the Senate 40-0.) 

SB870 (Marsden) authorizes local planning commissions to include certain regulations and provisions for conditional zoning for solar projects over 5 MW. (Passed Senate 40-0 with a substitute.)

HB1675 (Hodges) requires anyone wanting to locate a renewable energy or storage facility in an opportunity zone to execute a siting agreement with the locality. (Passed House 89-7.)

Grants, tax deductions, tax credits and other financing

HB654 (Guy) authorizes DMME to sponsor a statewide financing program for commercial solar, energy efficiency and stormwater investments. The effect would be to boost the availability of Commercial Property Assessed Clean Energy (C-PACE) in areas of the state where the locality has not developed a program of its own. (Passed House 75-23. Assigned to Senate Committee on Local Government.)

SB754 (Marsden) authorizes utilities to establish on-bill financing of energy efficiency, electrification, renewable energy, EV charging, energy storage and backup generators. (Passed Senate 40-0 with a substitute.)

HB1656 (O’Quinn) authorizes Dominion and APCo to design incentives for low-income people, the elderly, and disable persons to install energy efficiency and renewable energy, to be paid for by a rate adjustment clause. (Passed the House 95-4.)

HB1707 (Aird) makes changes to the Clean Energy Advisory Board, which is (already) authorized to administer public grant funding. (Passed the House 65-33 with a substitute. Referred to Senate Ag.)

SB634 (Surovell) establishes the Energy Efficiency Subsidy Program to fund grants to subsidize residential “efficiency” measures, interestingly defined as solar PV, solar thermal or geothermal heat pumps. It also creates a subsidy program for electric vehicles. (Passed the Senate 32-7. Senator Surovell has requested a budget amendment of $1 million for the fund. )

SB1039 (Vogel) allows a real property tax exemption for solar energy equipment to be applied retroactively if the taxpayer gets DEQ certification within a year. (Passed the Senate 40-0.)

SB542 (Edwards) repeals the sunset date on crowdfunding provisions and provides fixes for certain existing obstacles to this financing approach. (Passed the Senate 40-0.)

Customer rights to shop for renewable energy

HB868 (Bourne) and SB376 (Suetterlein and Bell) allows customers to buy 100% renewable energy from any licensed supplier, regardless of whether their own utility has its own approved tariff. (HB868 passd the House 55-44. But note that its Senate companion SB376 was passed by indefinitely in C&L.)

HB 889 (Mullin) and SB 379 (McPike), the Clean Energy Choice Act, is broader than HB868. The legislation allows all customers to buy 100% renewable energy from any licensed supplier regardless of whether their utility has its own approved tariff. In addition, large customers (over 5 MW of demand) of IOUs also gain the ability to aggregate their demand from various sites in order to switch to a competitive supplier that offers a greater percentage of renewable energy than the utility is required to supply under any RPS, even if it is not 100% renewable. Large customers in IOU territory who buy from competing suppliers must give three years’ notice before returning to their utility, down from the current five years. The SCC is directed to update its consumer protection regulations. (HB889 passed the House 56-44. But its Senate companion SB379 passed by indefinitely in C&L.)

Other utility regulation

HB528 (Subramanyam) requires the SCC to decide when utilities should retire fossil fuel generation. (Passed the House 55-44.)

HB1132 (Jones, Ware) put the SCC back in control of regulating utility rates. (Passed the House 77-23.)

SB731 (McClellan) also affects rates, in this case by addressing a utility’s rate of return. The SCC determines this rate by looking first at the average returns of peer group utilities, and then often going higher. The bill lowers the maximum level that the SCC can set above the peer group average. (Passed the Senate 38-1.)

HB167 (Ware) requires an electric utility that wants to charge customers for the cost of using a new gas pipeline to prove it can’t meet its needs otherwise, and that the new pipeline provides the lowest-cost option available to it. (Note that this cost recovery review typically happens after the fact, i.e., once a pipeline has been built and placed into service.) Last year Ware carried a similar bill that passed the House in the face of frantic opposition from Dominion Energy, before being killed in Senate Commerce and Labor. (Passed the House unanimously with a substitute. It will now go to Senate C&L, where it may still have trouble from a Dominion-friendly committee.)

DEAD FOR THE YEAR

Green New Deal HB77 (Rasoul) sets out an ambitious energy transition plan and includes a fossil fuel moratorium. (Sent from Labor and Commerce to Appropriations, where it was not brought up. This is a polite way of killing a bill without anyone having to vote on it).

Undercutting RGGI HB110 (Ware) says that if Virginia joins RGGI, DEQ must give free carbon allowances to any facility with a long-term contract predating May 17, 2017 that doesn’t allow recovery of compliance costs. Rumor has it the bill was written to benefit one particular company. (Left in Labor and Commerce.)

Clean energy standard Instead of an RPS, SB876 (Marsden) proposed a “clean energy standard” that made room for some coal and gas with carbon capture. (Recognizing a number of problems with this approach, Senator Marsden rolled his bill into SB851; that’s GA-speak for killing a bill while still giving the patron points for trying).

Greenhouse gas inventory HB525 (Subrmanyam and Reid) require a statewide greenhouse gas inventory covering all sectors of the economy. (Laid on the table in a subcommittee, which also means it was killed.)

Brownfields HB1306 (Kory) directs the Department of Mines, Minerals and Energy to adopt regulations allowing appropriate brownfields and lands reclaimed after mining to be developed as sites for renewable energy storage projects. (Stricken from docket in House Ag.) HB1133 (Jones) makes it in the public interest for utilities to build or purchase, or buy the output of, wind or solar facilities located on previously developed sites. (Continued to 2021, yet another polite way of killing a bill, though it leaves them not technically dead. So should we call them the undead? Let’s hope the concept is resurrected next year, anyway.)

Local action HB413 (Delaney) authorizes a locality to include in its subdivision ordinance rules establishing minimum standards of energy efficiency and “maintaining access” to renewable energy. (Left in Cities, Counties and Towns.)

Retail choice SB842 (Petersen) provides for all retail customers of electricity to be able to choose their supplier, and instructs the SCC to promulgate regulations for a transition to a competitive market for electricity. Existing utilities will continue to provide the distribution service. The bill also requires suppliers of electricity to obtain at least 25% of sales from renewable energy by 2025, 50% by 2030, and 100% by 2050. Renewable energy is defined to include “sustainable biomass” but not waste incineration or landfill gas. (Continued to 2021.)

Resilience hubs HB959 (Bourne) directs DMME to establish a pilot program for resilience hubs. These are defined as a simple combination of solar panels and battery storage capable of powering a publicly-accessible building in emergency situations or severe weather events, primarily to serve vulnerable communities. (Continued to 2021.)

Net metering HB1067 (Kory) deals with a specific situation where a customer has solar on one side of property divided by a public right-of-way, with the electric meter to be served by the solar array on the other side. The legislation declares the solar array to be located on the customer’s premises. (Item 4 of Solar Freedom would also solve the problem.) (Continued to 2021.)

Utility restructuring

HB1677 (Keam) replaces Virginia’s current vertically-integrated monopoly structure with one based on competition and consumer choice. Existing monopoly utilities would be required to choose between becoming sellers of energy in competition with other retail sellers, or divesting themselves of their generation portfolios and retaining ownership and operation of just the distribution system. Other features: a nonprofit independent entity to coordinate operation of the distribution system; performance-based regulation to reward distribution companies for reliable service; consumer choices of suppliers, including renewable energy suppliers; an energy efficiency standard; a low-income bill assistance program; and consumer protections and education on energy choices. (This was politely continued to 2021 in Labor and Commerce with no debate. The patrons were complimented for “starting a conversation.”)

HB206 (Ware) was, I’m told, the beta version of Delegate Keam’s HB1677. (Incorporated into HB1677, which was continued to 2021.)

SB842 (Petersen) seeks to achieve the same end as HB1677 and HB206, but it puts the SCC in charge of writing the plan. The bill provides for all retail customers of electricity to be able to choose their supplier, and instructs the SCC to promulgate regulations for a transition to a competitive market for electricity. Existing utilities will continue to provide the distribution service. The bill also requires suppliers of electricity to obtain at least 25% of sales from renewable energy by 2025, 50% by 2030, and 100% by 2050. Renewable energy is defined to include “sustainable biomass” but not waste incineration or landfill gas. (Continued to 2021.)

Anti-renewable energy bills

HB205 (Campbell) adds unnecessary burdens to the siting of wind farms and eliminates the ability of wind and solar developers to use the DEQ permit-by-rule process for projects above 100 megawatts. (Laid on the table in subcommittee.)  HB1171 (Poindexter) is a make-work bill requiring an annual report of the acreage of utility scale solar development, as well as the acreage of public or private conservation easements. (Continued to 2021.) HB1636 (Campbell) prohibits the construction of any building or “structure” taller than 50 feet on a “vulnerable mountain ridge.” You can tell the bill is aimed at wind turbines because it exempts radio, TV, and telephone towers and equipment for transmission of communications and electricity. (Laid on the table in subcommittee. FWIW, we’re told it was aimed at hotels, not wind. Yeah, sure . . .) HB1628 (Poindexter) prohibits the state from joining RGGI or adopting any carbon dioxide cap-and-trade program without approval from the General Assembly. (Passed by indefinitely in subcommittee. Yep, another way to kill a bill.)

Financing

HB461 (Sullivan) establishes a tax credit of 35%, up to $15,000, for purchases of renewable energy property. It is available only to the end-user (e.g., a resident or business who installs solar or a geothermal heat pump). Unfortunately, loose drafting would have also made the credit available for wood-burning stoves and other non-clean energy applications. (Died in a Finance subcommittee on a 5-5 vote.)

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

HB947 (Webert) expands the authority of localities to grant tax incentives to businesses located in green development zones that invest in “green technologies,” even if they are not themselves “green development businesses.” Green technologies are defined as “any materials, components, equipment, or practices that are used by a business to reduce negative impacts on the environment, including enhancing the energy efficiency of a building, using harvested rainwater or recycled water, or installing solar energy systems.” (Continued to 2021.)

SB1061 (Petersen) allows residential customers to qualify for local government Property Assessed Clean Energy (PACE) financing programs for renewable energy and energy efficiency improvements; currently the availability of this financing tool is restricted to commercial customers. (Continued to 2021.)

HB754 (Kilgore) establishes the Virginia Brownfield and Coal Mine Renewable Energy Grant Fund, which will support wind, solar or geothermal projects sited on formerly mined lands or brownfields. (Left in Appropriations.)

[Updated February 12 to include late votes and fix a random meaningless line, and later to correct various other screw-ups that people have kindly brought to my attention.]

Appalachian Power gets approval to sell 100 percent renewable energy to customers. Hold the champagne.

Photo credit Andy Beecroft via Wikimedia.

Last week the State Corporation Commission (SCC) approved a request from Appalachian Power Company (APCo) to offer its customers the option of buying electricity entirely from renewable sources. The sources will be primarily wind and hydro, with some solar to be added as it gets built. Participants will pay a premium of less than 4% over ordinary “brown” power, resulting in bill increases of $4.25 per month for a customer who uses 1,000 kW per month.

The approval gives APCo more than a new way to meet customers’ desire for renewable energy. It also triggers a provision in Virginia law that blocks competitive service providers from selling renewable energy to all but the largest of a utility’s customers once the utility itself has an approved offering. Both APCo and Dominion Energy Virginia have long sought to close off competition, but this marks the first time either has succeeded.

The SCC order goes against the recommendation of hearing examiner D. Matthias Roussy, Jr., who had advised against approval of APCo’s tariff.

The SCC had previously rejected a similar program APCo proposed in 2016, primarily due to its high cost. That program, too, would have repackaged the utility’s existing wind and hydro projects that all ratepayers currently pay for, and passed on the cost of those contracts to participants in the renewable energy program. The result was a price premium for the program of about 18%, which the SCC deemed unreasonable.

But APCo didn’t go back to the drawing board and redesign its program; it just changed the pricing. The cost to participants will now be based on the market value of renewable energy certificates (RECs) generated by facilities like the ones APCo owns.

REC prices are set by supply and demand, and an oversupply of wind RECs in the market has pushed prices way down over the past few years. Using REC prices allowed APCo to slash the cost of its renewable energy program by more than 75%.

On the one hand, this is a false calculation, since the value of RECs has little to do with the actual cost of developing and operating a project. On the other hand, the SCC liked the result: a lower cost to participants.

Some customers agreed. A number of APCo’s customers offered support for the program at the SCC. For them, this marks the first opportunity they will have to buy energy from specific wind and solar projects (okay, and a lot of decades-old hydro, too). Currently their only option is buying RECs to offset the dirty power they use, so they are willing to accept a price premium based on REC values.

Other customers were less impressed. Wal-Mart Stores opposed the program because the company prefers to save money by buying renewable energy, not spend more on it. As summarized by the Hearing Examiner, Wal-Mart felt the APCo tariff would be okay as a REC offering, but a real renewable energy tariff ought to “permit the customer to realize the benefits and risks of taking service from renewable energy sources”—i.e., offer at least the potential of saving money for the customer.

Wal-Mart has a point. Given the plunging costs of building and operating new renewable energy projects in recent years, a utility could, in theory, offer a renewable energy tariff at below the cost of brown power. Wind and solar increasingly outcompete even existing coal plants, and APCo is still heavily reliant on coal.

But APCo isn’t going to do any such thing. If its customers can buy renewable energy at a discount, who would want to buy power from fossil fuels?

So APCo had to make sure its program costs more. Tying it to REC prices means it always will, because RECs are always an additional cost.

Just as importantly, APCo has to make sure no other seller of electricity can be allowed to compete with a better or cheaper product. That’s where section § 56-577 A 5 of the Virginia Code comes to the aid of our monopoly utilities. Now that APCo has an approved tariff for a 100% renewable energy tariff, no competitive supplier can come on to its turf with a product that’s better, or simply different. (The Code contains an exception for very large customers.)

Concern about this squelching of competition drove most of the opposition to APCo’s tariff at the SCC, from both competitive suppliers like Collegiate Clean Energy and environmental advocates like the Southern Environmental Law Center, as well as a number of customers. For them, the SCC Order approving APCo’s program represents a loss for consumer choice that will inevitably lead to less renewable energy development.

Separately, Dominion Energy Virginia filed for approval of its own renewable energy tariff, following the Commission’s rejection of the company’s initial proposal last year (correctly in my view). Last month a hearing examiner recommended Dominion’s new tariff be approved, though with changes that would make it significantly cheaper than what Dominion wants. Dominion’s proposal as filed would have cost the average customer an extra $20 per month.

But on January 9, two days after the SCC approved APCo’s tariff, Dominion filed a request to withdraw its application. The request states that the company intends to file a new application “consistent with the principles outlined” in the APCo order.

Although Dominion’s request doesn’t specify which principles it has in mind, they likely include the SCC’s determination that a renewable energy tariff need only match demand on a monthly basis, not the hourly basis Dominion used. According to the hearing examiner’s report, Dominion’s insistence on hourly matching was a significant factor in the program’s high cost.

Dominion’s withdrawal of its renewable energy tariff grants a temporary reprieve to competitive service providers like Direct Energy, which wants to offer renewable energy to Dominion customers. But if Dominion re-files with a program that meets SCC approval, the window of opportunity for competition in the electric sector in Virginia will close permanently in both major utility territories, absent a change in the law.

Anticipating this, Direct Energy sought legislation in the 2018 session that would have ensured the ability of competitors to offer renewable energy even after the SCC approved a utility’s own tariff. Neither the House bill (from Delegate Michael Mullin, D-Newport News) nor the Senate bill (from Senator David Sutterlein, R-Roanoke) made it out of the Commerce and Labor committee. Delegate Mullin is trying again this year; his bill is HB 2117.

Cliona Robb, a lawyer with the law firm of Christian & Barton who represents Direct Energy, says her client hopes for a better outcome in the General Assembly this year.

With the SCC’s order approving APCo’s program, harm to competition is no longer hypothetical. If legislators are serious about renewable energy development in Virginia, keeping the door open to competition has to be a key priority.


This article first appeared in the Virginia Mercury on January 10, 2019.

Update: Senator Sutterlein has also filed a bill this year that would continue to allow competition even once a utility has an approved green tariff. The Senate bill is SB 1584.

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.

2017 guide to Virginia wind and solar policy

You can tell this picture wasn’t taken in Virginia because it has wind turbines in it. But at least the solar farm will look familiar to many Virginians these days. Photo credit Dennis Schroeder, NREL.

[This is an awesome guide, isn’t it? But you don’t want to bother with it, because the 2018 update is now available here.]

After several years of writing this annual update and often finding little to cheer about, I can finally share some good news. The nationwide boom in utility-scale solar has hit Virginia full force, juiced by low panel prices, corporate and state government demand, favorable tax policy and an abundance of good sites near transmission lines. We are a long way from unleashing our full potential; a lack of incentives, utility-inspired barriers, and a legislature still in thrall to fossil fuel interests continue to hold us back. In spite of this, Virginia is now attracting hundreds of millions of dollars in solar energy investments, and today the solar industry employs more of our residents than the coal industry.

The same cannot be said for wind energy; we are alone among all neighboring states in having no operating wind farms. Distributed generation like rooftop solar also remains a weak spot, even as customer interest continues to grow.

This survey of current policy is intended to help decision-makers, industry, advocates and consumers understand where we are today, who the players are, and where we could be going in the coming year. 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 still lags, but we’ve now got some mo’

Even last summer it was clear utility-scale solar was on a roll in the commonwealth, leading me to predict Virginia would hit 200 megawatts (MW) by the end of 2016, up from 22 MW at the end of 2015. According to the Solar Energy Industries Association, we beat that number and then some.

Maryland North Carolina W. Virginia Tennessee Virginia
Solar* 637.8 3,015.8 3.4 171.1 238.3
Wind** 191 208 686 29 0
Total 828.8 3,223.8 689.4 200.1 238.3

Installed capacity measured in megawatts (MW) at the end of 2016. One megawatt is equal to 1,000 kilowatts (kW). Note that SEIA does not provide 2016 numbers for W. Virginia; shown are 2015.

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

The big numbers, however, still lie ahead. At the May event where Governor McAuliffe announced his directive to the Department of Environmental Quality (DEQ) to develop a carbon limit for Virginia, he also reported that Virginia has a total of more than 1,800 MW of solar installed or under development.

Several developments are driving these numbers:

  • Once the federal investment tax credit is factored in, the levelized cost of energy from solar is now below that of coal, nuclear, and natural gas.
  • Dominion committed to 400 MW of solar as part of 2015 legislation, and now indicates in its IRP an intent to build 240 MW per year through at least 2032.
  • Governor McAuliffe committed the state to getting 8% of its electricity from solar, a total of 110 MW.
  • Corporations, led by Amazon, are using new approaches to procure renewable energy on favorable terms, including indirect and virtual PPAs; this forces utilities to cooperate or be cut out of the action.
  • Other customers have stepped up pressure on their utilities to provide renewable energy.

You can find the list of projects that have submitted permit applications on the DEQ website. The list currently does not include regulated utility-owned projects, which until this year received permits from the State Corporation Commission (SCC). Under legislation passed in 2017, however, these projects will also be governed by the DEQ permit-by-rule process.

Industry experts caution that not all of these solar projects will get built; we may even be seeing a speculative bubble of sorts, reflecting a scramble to lock up the good sites now and worry about customers later.

You will find only one wind project on the DEQ list: Apex Clean Energy’s 75 MW Rocky Forge wind farm, which received its permit earlier this year but has not yet begun construction.

And in spite of Dominion Virginia Power having won the right to develop an estimated 2,000 MW of wind power offshore of Virginia Beach, there is still no timeline for offshore wind in Virginia. Dominion continues to include its two-turbine, 12 MW pilot project in its 2017 Integrated Resource Plan, with a projected in-service date of 2021. It does not include the larger resource as an option.

  1. Most customers still can’t buy renewable energy from Virginia utilities

Currently, the average Virginia resident can’t pick up the phone and call their utility to buy electricity generated by wind and solar farms (unless they are members of some rural electric cooperatives—see below). Worse, they can’t buy renewable energy elsewhere, either.

Virginia law is not the problem. Section 56-577(A)(6) of the Virginia code allows utilities to offer “green power” tariffs, and if they don’t, customers are supposed to be able to go elsewhere for it. Ideally, a utility would use money from voluntary green power programs to build or buy renewable energy for these customers. However, our two big investor-owned utilities, Dominion Energy Virginia (formerly Dominion Virginia Power) and Appalachian Power Company (APCo), have not done this. Instead, the utilities pay brokers to buy renewable energy certificates (RECs) on behalf of the participants. Participation by consumers is voluntary. 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.

In Dominion’s case, these RECs meet a recognized national standard, and some of them originate with wind turbines, but they primarily represent power produced and consumed out of state, and thus don’t displace any fossil fuel burning in Virginia. For a fuller discussion of the Dominion Green Power Program, see What’s wrong with Dominion’s Green Power Program.

Since RECs are not energy, Dominion customers are free to buy RECs from other providers, such as Arcadia. 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.

Appalachian Power’s “green pricing” program is worse than Dominion’s, consisting only of RECs from an 80 MW hydroelectric dam in West Virginia. In April of 2016 APCo filed a proposal with the SCC for a true renewable energy tariff under of §56-577(A)(6) that would combine wind, solar and hydro. None of the power would come from new projects; partly as a result, the tariff will cost more. That led a hearing examiner to recommend that the SCC reject the tariff as not in the public interest. A ruling by the SCC is expected this summer or fall.

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. 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 go elsewhere.

In August of 2016, a hearing examiner for the SCC rejected this reading in favor of the plain language of the statute. Unfortunately, the case was terminated without the commissioners themselves ruling on the issue.

In spite of the roadblocks, an independent power seller called Direct Energy announced plans last year 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.) This spring the SCC confirmed Direct Energy’s right to enter the Virginia market, but also ruled that Direct Energy will have to stop signing up customers once Dominion has its own approved renewable energy tariff. As of this writing, Direct Energy has not decided whether to proceed.

Within a few weeks of the ruling, Dominion filed plans for several new 100% renewable energy tariffs for large commercial customers, and indicated it expected to offer a residential renewable energy tariff as well. Until we see the details, it is hard to know whether this should be viewed as a genuinely positive step for customers or is merely intended to scare off competitors like Direct Energy. Because Dominion’s tariff is designed to meet the company’s “100% of the time” interpretation of the statute, it will include sources like forest biomass, which counts as renewable under the Virginia code but is highly polluting and doesn’t meet many national standards for sustainability. That makes it questionable whether anyone will want to pay extra for its product. If the SCC confirms its hearing examiner’s report rejecting the similar APCo tariff, Dominion may be forced back to the drawing board. (Note to Dominion CEO Robert Blue: Bob, you have the nation’s largest pumped storage facility. Wind, solar and pumped hydro would combine beautifully. You do not need to foist biomass on customers to meet your notion of 100% renewable.)

A new solar option is in the works. For both APCo and Dominion customers, another option is on the way. Under legislation passed this year under the misleading banner of “community solar,” both utilities will contract for power from solar farms to sell to consumers. Details—including price—still have to be worked out in a rulemaking proceeding at the State Corporation Commission. The new 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 consumers.

Some coop members do have wind and solar options. Recently I learned that there are good green power programs in place in Virginia, available to members of some rural electric cooperatives. Old Dominion Electric Cooperative (ODEC), which supplies power to member cooperatives, buys the output of three wind farms in Maryland and Pennsylvania, and has contracted for two solar farms in Virginia that are slated to come online this year. Not all coops participate; ODEC has the list of those that do on its website.

  1. Community solar

Dominion loves the name “community solar.” The reality, not so much. The solar tariff discussed in section 2 uses that name but keeps the utility in control and gives customers no ownership interest. Dominion opposed true community solar legislation this year (as in past years) that would have put consumers in the driver’s seat.

This is not the first time Dominion has used the name “community solar” for a program that isn’t. In 2015 Dominion received SCC approval for a program it billed as an offer to sell electricity from solar panels. Unfortunately it turned out the “Dominion Community Solar” program would have involved customers paying extra so Dominion could sell solar energy to other people. Reading the details, it seemed clear it would attract customers only to the extent they didn’t understand it. Fortunately the company still hasn’t launched the program, but I’ve seen no formal withdrawal.

As for true community solar, only one Virginia utility offers it: a member-owned rural electric cooperative in southwestern Virginia called BARC.

  1. The miserable sham that is Virginia’s Renewable Portfolio Standard (RPS)

Many renewable energy advocates focus on an RPS as a vehicle for inducing demand. In Virginia, that’s a non-starter. Virginia has only a voluntary RPS, which means utilities have the option of participating but don’t have to. And unfortunately, the statute takes a kitchen-sink approach to what counts as renewable energy, so meeting it requires no new investment and no wind or solar. The SCC also insists that utilities take a least-cost approach to meeting the RPS, which means they use RECs from trash incinerators, wood burning, and old out-of-state hydro projects built prior to World War II. If utilities build wind and solar, they are required to sell the high-value RECs from these projects and buy low-cost junky ones instead. Thus, no matter how much solar Dominion builds, the RPS operates to ensure customers will never see solar as part of their energy mix.

The targets are also modest to a fault. Although nominally promising 15% renewables by 2025, the statute sets a 2007 baseline and contains a sleight-of-hand in the definitions section by which the target is applied only to the amount of energy not produced by nuclear plants. The combined result is an effective 2025 target of about 7%.

There appears to be no appetite in the General Assembly for making the RPS mandatory, and efforts to improve the voluntary goals 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.

  1. Customer-owned generation 

Given the lack of wind or solar options from utilities, people who want renewable energy generally have to build it themselves. Low panel prices and the federal 30% tax credit make it cost-effective for most customers. The emergence of bulk purchasing coops, sometimes also called “solarize” programs, such as those offered through nonprofits VA-SUN and LEAP, makes the process easy for homeowners and businesses and further reduces costs.

Virginia allows net energy metering at the retail rate, though with limits (see section 6). Large commercial customers should also consider the advantages of solar in reducing high demand charges.

In 2016 the GA 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 received a federal grant to develop a PACE program that is expected to launch this year and be a model for other jurisdictions. A bill to extend PACE authorization to residential customers did not get out of committee last year.

Virginia offers no cash incentives or tax credits for wind or solar. The lack of a true RPS in Virginia means Virginia utilities generally will not buy solar renewable energy certificates (SRECs) from customers. SRECs generated here can sometimes be sold to utilities in other states or to brokers who sell to voluntary purchasers.

  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. That offsets the grid power they draw on when their systems are producing less than they need. Their monthly bills reflect only the net 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 (see section 8). 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 by entering a power purchase agreement with the utility. This will likely be for a price that represents the utility’s “avoided cost” of about 4.5 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 the customers demand, based on the previous 12 months of billing history. The SCC wrote implementing regulations (see 20VAC5-315-10 et seq.) but failed to address what happens with new construction.

The limitation presents a new barrier to current customers who want to expand their solar arrays because their business is expanding or they plan to buy an electric car. Why should they have to wait twelve months? But the limitation is also stupid. If customers want to install more clean, renewable energy than they need and are willing to sell the surplus electricity for avoided cost, why would you stop them from performing this service to society?

  1. Progress on meter aggregation derailed by agricultural solar bill

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. Beginning this year, farmers can 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.

The change would seem to give farmers no rights they did not already have under federal law, but industry sources I trust say some farmers will indeed be able to make money this way. However, taking away the agricultural net metering option is a backward step for farmers who want to use the solar they produce and aggregate meters.

  1. Standby charges on larger home systems

The current system capacity limit for net-metered residential solar installations is 20 kW. However, for residential systems between 10 kW and 20 kW, a utility is allowed to apply to the State Corporation Commission to impose a “standby” charge on those customers. Both Dominion and APCo have approval from the SCC to impose standby charges so high that solar installers say the larger systems often don’t make economic sense.

Utilities argue that customers with solar panels 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 the grid and to 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.

Standby charges and other net metering issues will be a major focus of attention this year as a topic in the “Rubin Group” discussion. See section 19.

  1. Homeowner associations cannot ban solar

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.

  1. Third-party ownership

One of the primary drivers of solar installations in other states has been third-party ownership of the systems, including third-party power purchase agreements (PPAs), under which the customer pays only for the power produced by the system. For customers that pay no taxes, including non-profit entities like churches and colleges, this is especially important 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. Secure Futures and the university thought that even if what was really just a financing arrangement somehow fell afoul of Dominion’s monopoly, surely they were covered by the exception in §56-577(A)(6) available to customers whose own utilities do not offer 100% renewable energy. (See Section 2, above.)

Yet the threat of prolonged and costly litigation was too much. 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 negotiated a compromise 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.

Appalachian Power and the electric cooperatives declined to participate in the PPA deal-making, so the legal uncertainty about PPAs continues in their territories. In June of 2015, Appalachian Power proposed an alternative to PPAs. An evidentiary hearing was held September 29, 2015. A veritable parade of witnesses testified that APCo”s program was expensive, unworkable and unnecessary, given the plain language of the statute allowing PPAs.

Almost a year later, on August 31, 2016, the hearing examiner finally issued her report, recommending that APCo’s application be rejected, both because it was a lousy program and because she, too, read the Code to allow PPAs currently, making a utility alternative unnecessary. Before the commission itself could confirm the ruling, APCo withdrew its application.

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.

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 to be installed at Carilion New River Valley Medical Center in Southwest Virginia, 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.

  1. Tax exemption for third-party owned solar

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.” 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.

The 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 will now be 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.

  1. Dominion-owned distributed solar

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 new Dominion Energy web page still mentions it, but currently the link does not lead to more information.

  1. Dominion Solar Purchase Program

The same 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 is 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; the links on the new Dominion Energy website don’t lead anywhere helpful.

I ripped this program from the perspective of the Green Power Program buyers, but many installers also feel it is a bad deal for customers, given the costs involved and the likelihood that the payments represent taxable income. Finally, selling the electricity may make new system owners ineligible for the 30% federal tax credit on the purchase of the system.

  1. Utility renewable energy tariffs for large customers

In May of this year, Dominion applied to the SCC for permission to offer six new voluntary schedules for customers with a peak demand of at least 1,000 kW (1 MW). The tariff would use a mix of sources that count as renewable under the Virginia Code but still pollute, including biomass—making it only sort-of green.

For large customers that want wind and solar, the options are more limited. In 2013, Dominion Power introduced a Renewable Generation Tariff to allow customers to buy renewable power from providers, with the utility 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 (the merchant affiliate of Dominion Virginia Power) then bought the project, and Dominion Virginia Power negotiated a special rate with Amazon for the power. This contract became the basis for an “experimental” tariff that Dominion now offers 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 model 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 will buy the output of the project, while Microsoft buys the RECs.

Dominion has also entered into a contract to sell the output of a 17 MW solar facility to the University of Virginia and the Darden School of Business.

Dominion has a strong incentive to make deals with large institutions that want a lot of renewable energy: if they don’t like what Dominion is offering, they can do an end run around the utility. Amazon has shown other companies how to use PJM rules that let anyone develop projects for the wholesale market regardless of utility monopolies, and then “attribute” the solar or wind energy to their operations in any state. With the tax exemption discussed in section 11, Virginia projects apparently now pencil out pretty well.

Some observers caution that the process is still not easy. One of the tasks the Rubin Group says it plans to take on this year is considering further changes to help large customers.

  1. Dominion continues to add utility-scale solar for its own portfolio

Even before Amazon and Microsoft showed an interest in large-scale solar projects here, Dominion had announced it wanted to develop 400 MW of solar in Virginia. In 2015, two bills promoted the construction of utility-scale solar by declaring it in the public interest for utilities to build solar energy projects of at least 1 MW, and up to an aggregate of 500 MW. The bill was amended at the solar industry’s behest to allow utilities the alternative of entering into PPAs for solar power prior to purchasing the generation facilities at a later date, an option with significant tax advantages.

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 latest Integrated Resource Plan (IRP) calls for it to engage in a continuous build-out at a rate of 240 MW per year, all for the benefit of its regular ratepayers.

Although Dominion will be able to charge ratepayers for these projects, 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 initiates program to purchase 110 MW of solar

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, with 75% of that built by Dominion and 25% by private developers.

The first deal that will count towards this goal is 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.) A 17 MW solar farm supplying the University of Virginia will also count towards the 8%, according to Deputy Secretary of Commerce and Trade Hayes Framme.

  1. Still waiting for wind

No Virginia utility is actively moving forward with a wind farm on land. Dominion Power’s website used to list 248 MW of land-based wind in Virginia as “under development,” without any noticeable progress. The current web page omits mention of these projects.

On the other hand, Appalachian Power’s most recent IRP suggests an interest in wind as a low-cost renewable resource. The bad news is that it isn’t proposing to build any new wind in Virginia.

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. No customer has been announced, but the company believes the project can produce electricity at a competitive price, given its good location and improved turbine technology. Construction, once planned for this year, is now slated for 2018.

As for Virginia’s great offshore wind resource, little progress has been made towards harnessing it, even as the nation’s first offshore wind project began generating electricity in the waters off Rhode Island last year. Dominion won the federal auction for the right to develop about 2,000 MW of wind power off Virginia Beach in 2013, and the company has completed a Site Assessment Plan (SAP) that is awaiting approval.

We had originally been told the federal government’s timeline would lead to wind turbines being built off Virginia Beach around 2020. Now, however, the Bureau of Ocean Energy Management says 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. So the whole process would be quite slow even if Dominion were committed to moving forward expeditiously.

But in fact, it seems increasingly clear that Dominion is just going through the motions and has little interest in seeing the project through. Its 2017 Integrated Resource Plan (IRP) does not even include offshore wind in any of its scenarios for the next 15 years, except for the 12 MW that would be produced by the two test turbines of its VOWTAP project.

Yes, so what about VOWTAP? Dominion had been part of a Department of Energy-funded team to try out new technology, with two pilot turbines due to be installed in 2017. After a second round of bids to build the project still came in higher than expected, Dominion told DOE last spring it could not commit to construction even by 2020, upon which DOE pulled funding. Dominion executives have not declared the project dead, however, and while there has been no public discussion of reviving it, the 2017 IRP suggests an in-service date of 2021.

[Update: on July 10, 2017, Dominion announced it had signed a memorandum of understanding with Denmark-based DONG Energy, one of the largest offshore wind developers in Europe, to complete the two pilot turbines. According to a Dominion press release, the MOU also gives DONG “the exclusive rights to discuss a strategic partnership with Dominion Energy about developing the commercial site based on successful deployment of the initial test turbines.”]

  1. The EPA Clean Power Plan is (probably) dead; long live the McAuliffe clean energy plan!

The Trump administration’s pullback on the Paris accord and the Clean Power Plan are depressing evidence that the Koch brothers have more influence on government than the American people do. Yet the practical effect in Virginia is small. The Clean Power Plan’s targets for Virginia were modest to a fault, and the state could have written an implementation plan that complied with the federal law while still allowing construction of an unlimited number of new gas-burning plants, sending total carbon emissions soaring.

Governor McAuliffe’s recent Executive Directive 11, on the other hand, ties emissions reductions from Virginia power plants to those in other states that have committed to reducing carbon emissions, leaving somewhat less room for mischief in implementation. There are still plenty of pitfalls ahead, and some Republican leaders have vowed to prevent it from ever taking effect. But any constraints on greenhouse gas emissions would serve to increase the value of emissions-free sources like wind and solar. The DEQ web page will show public participation opportunities.

  1. Solar initiatives underway ahead of the 2018 Session

The legislative initiatives that passed in 2017 dealt primarily with utility-scale solar. Since then, the solar industry has announced plans to focus more on removing barriers to distributed generation, a decided challenge given the utilities’ determination to curtail net metering.

The utilities and the solar industry have reconvened solar policy discussions via the Rubin Group, named for its moderator, Mark Rubin. Steering committee members this year include the electric cooperatives, Dominion, APCo, the solar industry trade group MDV-SEIA, the farm advocate Powered by Facts, the environmental group Southern Environmental Law Center, and the Virginia Manufacturer’s Association. The Rubin Group held a meeting on June 19 to get input from other stakeholders, and a follow-up email announced plans for the following subgroups:

  • Large Customer  (Convener: Katharine Bond, Dominion Energy, with Advanced Energy Economy, Ceres, and World Wildlife Fund as Key Participants)
  • Large Developer/Utility-Scale Solar (Convener: Francis Hodsoll, SolUnesco & MDV-SEIA Board Member)
  • Net Metering (Co-Conveners: Sam Brumberg, Virginia’s Electric Cooperatives & Scott Thomasson, Vote Solar & MDV-SEIA Board Member)
  • Land Use (Convener: Karen Schaufeld, Powered by Facts)
  • Community Solar Implementation for Dominion Energy (Conveners: Katharine Bond & Nate Frost, Dominion Energy)

The Rubin Group will accept comments at RubinGroup2017@gmail.com. [Update: Although this was the email address given out at the public meeting, we have learned it goes to Sam Brumberg, attorney for the electric cooperatives, who says he checks it only a few times per month. He recommends contacting Mark Rubin directly at rubin.mark3@gmail.com.]

A separate initiative is the Virginia Distributed Solar Alliance, which includes solar companies, environmental groups, consumers and solar advocates, but not utilities. As its name suggests, it focuses on removing barriers to smaller-scale, customer-sited projects, defending net metering and educating the public about the added benefits distributed solar bring to the grid and the community. The VA-DSA recently launched its website and is welcoming members.

 

 

Hearing examiner rules Appalachian Power’s renewable energy tariff isn’t good enough

Appalachian Power’s plan to repackage power from existing renewable energy projects in its portfolio into a new, higher-priced green option hit a bump this week when a hearing examiner for the Virginia State Corporation Commission recommended rejection of the tariff, saying it wasn’t a good deal for consumers.

Approval of the tariff would have allowed APCo to block competition from other renewable energy suppliers. Virginia law provides that if a customer’s own utility doesn’t offer a tariff for 100% renewable energy, the customer has the right to buy from any other provider.

APCo had argued its tariff met the letter of the law, and that should be the end of the SCC’s inquiry. Since it was a voluntary tariff, customers could take it or leave it. Hearing Examiner A. Ann Berkobile disagreed. Because approval of the tariff would adversely affect competition and restrict the rights of customers, she found, the tariff could only be approved if APCo proved it was “in the public interest and its rate is just, reasonable and unlikely to prejudice customers.”

In this case, she concluded, APCo failed to do so, having “made no effort to establish the reasonableness of its proposed Rider REO rate.”

She went on: “Stated somewhat differently, Rider REO has the potential to suppress or even curtail customer access to 100 percent renewable energy by precluding sales by [Competitive Service Providers] while at the same time offering an incumbent utility alternative that is simply too costly for customers to bear. The overall price of Rider REO (and associated rate) should, therefore, be considered when deciding whether to grant approval.”

Testimony in the case had established that the existing wind farms APCo proposed to use were providing power at a higher price than could be obtained from new sources, which the Hearing Examiner suggested made the proposed tariff rate unreasonable. In addition, using old sources rather than new ones would not “promote the development of renewable energy in accordance with the objectives of the Commonwealth Energy Policy set forth in §§ 67-101 and 67-102 of the Code.”

The Hearing Examiner’s report is only a recommendation to the SCC, which will have the final say. The case is PUE-2016-00051.

Ruling could affect Dominion tariff

If the SCC adopts the Hearing Examiner’s recommendation, that could also affect the SCC’s evaluation of Dominion’s proposed 100% renewable commercial tariff. Dominion’s tariff will likely use biomass as a source because of Dominion’s insistence that a 100% renewable product must use sources that together produce renewable energy 100% of the time. But while Virginia’s overbroad definition of renewable energy includes “biomass, sustainable or otherwise,” biomass often doesn’t satisfy corporate sustainability goals. As the Hearing Examiner’s opinion suggests, it’s not enough for a tariff to meet the requirement of providing 100% renewable energy if it isn’t also good enough to attract customers.

The Hearing Examiner’s emphasis on the cost to consumers is also a relevant consideration. If the SCC affirms the APCo decision, Dominion would have to justify using higher-cost biomass over much cheaper wind and solar.


Update: On September 13, 2017, the SCC rejected APCo’s proposed tariff, focusing especially on its high cost.

Does Dominion buy votes? Sure, but not the way you think.

By Djembayz – Own work, CC BY-SA 3.0, https://commons.wikimedia.org/w/index.php?curid=26128831

Observers, critics, and even legislators agree that utility giant Dominion Resources is the single most powerful force in the Virginia General Assembly. It gets the legislation passed that it wants, and it almost always succeeds in killing bills it doesn’t like. Media stories point out one reason for this huge influence: the company gives more money to political campaigns than does any other individual or corporation.

But it’s more complicated than that. Dominion distributes its largesse among Republicans and Democrats alike according to rank and power, not according to party affiliation, and not according to how they vote. Legislators stay on the gravy train even when they occasionally vote against Dominion’s interests. (No lawmaker consistently votes against Dominion’s interests. That would be weird. It is, after all, a utility.)

In the General Assembly, the most money goes to members of the Senate and House Commerce and Labor Committees, which hear most of the bills affecting energy policy. But Dominion also donates to the campaigns of nearly every incumbent lawmaker, regardless of committee assignment. It does not, however, donate to their challengers. Only to the victors go the spoils.

So today let’s look at some of the lucky recipients of Dominion’s money. This information comes from the Virginia Public Access Project, vpap.org, supplemented by information available on the General Assembly website. 

Legislators whose campaigns have received more than $50,000 from Dominion (lifetime)

Recipient Party District number and region Total $ from Dominion 2014-2015 election cycle
Sen. Saslaw D 35  NoVa (Fairfax/Falls Church) 298,008 57,500
Del. Kilgore R 1    Southwest 162,000 35,000
Sen. Deeds D 25   Piedmont 109,700 1,500
Sen. Norment R 3    Middle Peninsula/Tidewater 107,740 21,500
Del. Cox* R 66   Central 90,799 29,099
Sen. Wagner R 7    Tidewater 79,735 26,885
Del. Plum** D 36   NoVa 78,750 4,000
Del. Hugo R 40  NoVa 54,400 11,000
Sen. Obenshain R 26  Shenandoah Valley 51,000 5,000

Notes:

  • Lifetime totals may include more than one campaign committee. Creigh Deeds collected money for Delegate, Senate, AG and Governor’s races, which explains how he racked up this much in donations; he was also formerly a member of Commerce and Labor, but by 2014 he’d been removed from the committee.
  • I chose 2014-2015 as a single election cycle comparison because both House and Senate seats were up that year.
  • *Cox is not on Commerce and Labor but is House Majority Leader, a position that propelled him into the ranks of top Dominion recipients.
  • **Plum is a former member of House Commerce and Labor and currently a member of the Commission on Electric Utility Regulation. (Other Commission members include Delegates Kilgore, Hugo, Miller, Villanueva and James; and Senators Norment, Lucas, Saslaw and Wagner.)

Saslaw, Kilgore, Norment, Wagner, Hugo and Obenshain all sit on the Commerce and Labor committees that hear most of the bills affecting Dominion’s business dealings. Wagner chairs Senate C&L and runs it as his personal fiefdom; Saslaw did the same when Democrats held the Senate. He will be Chairman again if control switches back. In addition to sitting on Senate C&L, Norment is the Senate Majority Leader.

Kilgore chairs House C&L, and like Wagner, he controls not just the docket but usually the outcome of votes. Hugo is House Majority Caucus Chairman in addition to being a member of C&L.

These powerful men (they are all men, and all white) get the biggest donations, but anyone with a seat on the committee can expect to collect donations from Dominion.

Dominion donations to Commerce and Labor Committee members

Senate

Senator Party District number and region Total $ from Dominion 2014-2015 election cycle
Wagner (Chair) R 7  Tidewater 81,985 26,885
Saslaw (former Chair, Minority Leader) D 35  NoVa (Fairfax/Falls Church) 298,008 57,500
Norment R 3    Middle Peninsula to Tidewater 107,740 21,500
Newman R 23 Roanoke area 20,500 3,000
Obenshain R 26  Shenandoah Valley 51,000 5,000
Stuart R 28  Fredericksburg area 20,750 6,000
Stanley R 20  Southside 19,500 9,000
Cosgrove R 14  Tidewater 7,000 2,000
Chafin R 38  Southwest 10,500 6,500
Dance D 16  Central 25,692 9,000
Lucas D 18  Tidewater 31,950 5,200
McDougle R 4    Central 47,250 10,000
Black R 13  NoVa (outer suburbs) 9,750 1,000
Sturtevant* R 10  Central 4,000
Spruill D 5    Tidewater 35,419 4,200

*Sturtevant joined the Senate in 2016.

House Commerce and Labor Special Subcommittee on Energy

Delegate Party District number, region Total $ from Dominion 2014-2015 cycle
Kilgore (Chair) R 1    Southwest 162,000 (top) 35,000
Byron R 22  Southwest 24,500 4,000
Ware, L. R 65  Central 26,800 4,000
Hugo R 40  NoVa 54,400 11,000
Marshall, D.W. R 14  Southside 20,250 5,000
Cline R 24  West (Lexington area) 13,750 3,000
Miller, J R 50  NoVa (western suburbs) 29,000 7,500
Loupassi R 68  Central 20,000 5,000
Habeeb R 8    Southwest 12,500 5,000
Villanueva R 21  Tidewater 11,000 3,500
Tyler D 75  Southside 17,000 4,000
Keam D 35  NoVa 8,750 2,750
Lindsey D 90  Tidewater 3,300 2,300

Other House Commerce and Labor members (not on energy subcommittee)

Delegate Party District number, region Total $ from Dominion 2014-2015 cycle
Bell, Robert B. R 58  Piedmont 14,500 3,500
Farrell* R 56  Central 0 0
O’Quinn R 5    Southwest 6,500 3,000
Yancey R 94  Tidewater 10,000 3,500
Ransone R 99  Northern Neck 8,500 2,500
Ward, J D 92  Tidewater 23,500 5,000
Filler-Corn D 41  NoVa 10,500 3,000
Kory D 38  NoVa 6,250 1,000
Bagby D 74  Central 2,000 1,000
  • Names appear in the order they are listed on the General Assembly website for each committee. In the Senate, this reflects seniority; in the House, Republicans come first, and then seniority.
  • *Peter Farrell is the son of Thomas Farrell, II, CEO of Dominion Resources. He gets no cash from Dominion and abstains on votes that directly affect the utility. Those who worry that the family relationship might keep him off the gravy train will be relieved to know his dear old dad gives his campaign $10,000 a year, and more than a dozen other top Dominion executives also pitch in hundreds or thousands of dollars apiece annually to make sure he stays on the public payroll.

Compared to whom?

One problem with singling out Dominion is that it is only the biggest and most conspicuous player of the influence game. It has plenty of company. Appalachian Power Company (APCo) also donates generously to legislators in leadership positions and those on C&L. And our utilities are not exceptions. Richmond is awash in corporate cash.

So let’s look at Appalachian Power Company’s top dozen Senate and House recipients in 2014-2015. We can compare these amounts to what these guys (all men again) received from Dominion and Altria, another large Virginia company that isn’t in the utility business. And just for fun, I’ve added columns showing donations from the solar industry trade group MDV-SEIA and the environmental group Sierra Club.

Recipient Party APCo Dominion Altria MDV-SEIA** Sierra Club***
Sen. Saslaw D 20,000 57,500 27,500 1,000 0
Sen. McDougle R 15,000 10,000 26,500 0 0
Sen. Wagner R 12,500 26,885 10,500 2,500 0
Sen. Norment R 12,500 21,500 35,000 2,500 0
Del. Hugo R 10,000 11,000 2,500 500 0
Del. Cox R 10,000 29,099 0 0 0
Del. Kilgore R 7,500 35,000 2,000 0 0
Del. Miller R 6,500 7,500 2,000 0 0
Sen. Alexander* D 4,500 5,000 1,500 0 0
Del. Habeeb R 4,000 5,000 500 0 0
Sen. Obenshain R 2,500 5,000 1,000 0 0
Sen. Stanley R 3,600 9,000 6,000 0 0
  • *Kenny Alexander was a member of Senate Commerce and Labor in 2014 and 2015.
  • **MDV-SEIA donated to only five candidates in the 2014-2015 election cycle. In addition to the contributions shown, the association gave $2,500 to Delegate Villanueva.
  • ***Sierra Club-Va. Chapter made a total of $33,410 in campaign contributions during the 2014-2015 election cycle, but very few of its recipients sit on Commerce & Labor. Of those who do, Delegate Villanueva received the largest donation, $200. Sierra Club Legislative Director Corrina Beall notes that “most of Sierra Club’s donations are in-kind donations rather than cash donations. Our contributions are made in staff time spent communicating with our members and supporters about candidates who we have endorsed.”

What do you get if you’re not a big shot or on C&L?

Dominion gives to almost everyone; after all, bills that pass committee still have to go to the floor. I chose half a dozen lesser-known delegates at random to compare to the Commerce and Labor committee members. All have been in the General Assembly for at least six years.

Here’s what they got for the 2014-2015 legislative cycle. I threw in APCo and Altria for comparison.

$ From Dominion $ From APCo $ from Altria
Anderson, R (R) 2,000 275 1,000
Edmunds, J   (R) 1,500 0 1,000
Knight, B (R) 3,500 1,275 1,000
McQuinn, D (D) 3,750 1,500 500
Watts, V (D) 2,000 500 1,000
Helsel, G (R)* 0 0 1,000
  • *Helsel received $2,500 from Dominion in 2011-2012 but nothing since, and has never received money from APCo.

So the little people did about as well as the C&L members who aren’t on the energy subcommittee, but less well than the subcommittee members.

What does the money buy?

Legislators swear they don’t allow the money to influence their votes. And yet it seems obvious that donors expect that very thing. There’s a clear gap between what the donors think their money buys, and what legislators think they give in return. You might call this the “credibility gap.” And yet as I’ve observed before, if a few thousand bucks is enough to buy a vote, then the real scandal isn’t that legislators can be bought, but that they can be bought so cheaply. Obviously, there is more to it.

Defenders of unlimited campaign contributions like to think donors give money to candidates whose views they share, or to lawmakers who have done a good job in office and need the money to win election and continue doing a fabulous job. That seems to describe Sierra Club’s approach, but it certainly doesn’t describe Dominion’s. Dominion gives money to everyone, and almost none of the recipients need the money to stay in office.

According to VPAP, more than 50% of Virginia legislators ran unopposed during the last election. Only 10% of members had races that could be described as anything close to competitive (defined as a margin of less than 10%). Even if you totally approve of the job these legislators are doing, you don’t need to give them money to make sure they keep their seats. The only purpose of contributions to these members is to buy influence by helping them build power.

House Commerce and Labor Chairman Terry Kilgore, for example, has not had an opponent since 2007, when he took 72% of the vote. Yet since 2008, he has collected $135,500 from Dominion, among almost $2 million in contributions from all sources.

What does he do with all that money? VPAP shows that during the 2014-2015 season he spent some $80,000 on staff and political consultants, $50,000 on legal and accounting, $35,000 on fundraising (hello?), $23,000 on something called “Community Goodwill,” $22,000 on mail, printing and postage, $12,000 on “Legislative Session,” $11,000 on travel and meals, $28,000 on advertising, signage, and phone calls, and another $15,000 or so on other campaign-related things. All this for a part-time legislator running unopposed.

But the biggest expense Kilgore reported was not for his campaign, but for the campaigns of fellow Republicans. Donations to other candidates and party committees in 2014 and 2015 added up to about $174,000. Dominion’s money indirectly helps candidates who might have competitive campaigns; directly, it helps Kilgore build power and influence for himself.

We could do a similar analysis on the Democratic side with Senator Saslaw, who draws at least token opposition in every election but has never won by less than a 17-point margin. He still collected over a million dollars in campaign contributions in 2014-2015, and spent all but a fraction of it on donations to party committees and other candidates.

In both cases, and for all the other top recipients of Dominion’s cash, the campaign donations have nothing to do with candidates getting elected, and everything to do with securing the loyalty of legislative power brokers who, by doling out money themselves, can deliver the votes on Dominion-backed bills when needed. Rank-and-file legislators don’t vote for a Dominion bill because they got a $1,000 donation. They vote for a bill when their party leader tells them to, especially when that leader can remind them he’s helped direct tens of thousands of dollars to their campaigns.

And then there’s this troubling aspect . . .

I’d be remiss not to mention one other peculiarity of Virginia election law, which is that candidates are not prohibited from using campaign money for personal expenses. The Washington Post ran a series of outraged editorials about this a few years ago that is worth looking up (I wrote about it here). This same practice cost now-Vice President Mike Pence an election way back in 1990, when records showed Pence used campaign donations to pay his mortgage and other personal expenses. But here in Virginia, the Post’s revelations about Delegate Hugo paying his cell phone bills with campaign money produced neither repercussions nor changes in the law.

Some legislators introduce legislation every year to ban the use of campaign cash for private gain; every year it fails in an unrecorded subcommittee vote. See, e.g., Delegate Marcus Simon’s HB 1446 this year.

Why doesn’t anyone turn down the money?

It’s pretty hard to find legislators who don’t take Dominion’s money. The vast majority who do includes Senator Chap Petersen, who made news this year first by calling for a repeal of the 2015 boondoggle that will net Dominion a billion-dollar windfall at customer expense, and when that bill failed (in Senate Commerce & Labor, ahem), by calling for a ban on campaign contributions from public service corporations like Dominion. Petersen received $2,500 from Dominion in the 2014-2015 cycle, and another $1,000 in 2016. Of course, that was before the 2017 session brouhaha.

One legislator who has sworn off Dominion’s money is Delegate Rip Sullivan, an Arlington Democrat known for his bills to improve Virginia’s dismal achievements on energy efficiency—bills that Dominion opposes when they come before Commerce and Labor. (The only efficiency bill that passed this year is one from Senator Dance that merely requires tracking of energy efficiency progress. Sullivan’s identical House bill was killed in the House energy subcommittee.)

I asked Sullivan why he doesn’t take Dominion’s money. I liked his answer so much that I’ll give him the last word:

“I have very publicly made clear from the day I announced for the HOD that I would not take any money from Dominion. I have been equally clear that a major part of my agenda in RVA relates to climate and renewable energy–as you know, I’ve introduced numerous bills on renewable energy tax credits, community solar, energy efficiency, etc. . . .

“I have also made clear that I understand the reality that to make progress on these issues in the GA I will need to interact and hopefully work with Dominion. And I have tried to establish and maintain relationships there to hopefully facilitate dialogue, understanding and hopefully progress on environmental issues. But I never want there to be any question about where–or with whom–I stand on these issues, and I don’t want anyone questioning my motives or actions with any suggestion about getting money from Dominion. And, of course, I want Dominion to understand that I am not beholden to them in any way. Frankly, it’s just cleaner (pardon the pun) to not take Dominion money, and shame on me if I can’t find somewhere else anyway to raise the thousand bucks they’d give me.”