In a last-ditch effort to stop climate regulations, Virginia Republicans try legislating by budget amendment

Dominion Energy Virginia's Chesterfield Coal Plant

Dominion’s coal-burning power plant in Chesterfield County.

The Northam administration is finalizing regulations to reduce the carbon pollution from Virginia power plants by 30 percent between 2020 and 2030. The Department of Environmental Quality (DEQ) estimates the move will cost consumers only about a dollar per month while accelerating the transition to clean energy.

Instead of celebrating this modest progress on climate action, Virginia Republicans have been fighting it every step of the way. Their latest effort takes the form of two amendments to the state budget that would effectively prevent Virginia from joining the Regional Greenhouse Gas Initiative (RGGI), a nine-state platform for trading carbon emission allowances. It would also stop the Commonwealth from participating in a new compact focused on reducing carbon emissions in transportation.

Virginia law gives the governor a line-item veto in the budget, which requires a two-thirds majority in the legislature to override. But for reasons known only to himself, Governor Northam has instead chosen to remove the amendments by offering his own amendments, which the General Assembly can reject by a simple majority vote.

This cues up the issue for a battle on the House floor on Wednesday, when the legislature returns for the “veto session.” The governor needs the votes of all the Democrats and at least two Republicans to prevail in the House, and those of at least one Republican and the Lieutenant Governor to prevail in the Senate.

Earlier this year, Republicans voted almost unanimously for legislation that, like the budget amendment, would have stopped Virginia from participating in RGGI. Northam vetoed that bill, saying it was bad policy and violated the state constitution. His action probably didn’t persuade any Republicans that he was right and they were wrong.

Still, there are reasons why a Republican who voted for the anti-RGGI bill might support the governor in the budget vote.

One is that using the budget to achieve a policy outcome you couldn’t reach through the legislative process makes a lot of legislators uneasy; it feels like bad governance.

Another is that the anti-RGGI bill was for show; everyone knew the governor would veto it. Moderate Republicans who privately acknowledge the urgency of the climate crisis were able to use their vote to demonstrate party loyalty without actually interfering with the DEQ program.

They bill vote also followed surprise testimony from State Corporation Commission staff members who claimed that trading with RGGI would cost Virginia households much more than DEQ modeling showed. The staff members provided no evidence, but hard-line Republicans saw the threat of rate increases as a gift horse they weren’t going to look in the mouth.

DEQ staff did look it in the mouth, however, and found a number of bad teeth.  DEQ Chief Deputy Chris Bast lambasted the SCC staff for coming into the discussion late, using incorrect assumptions, and failing to show their work.

The SCC staff members followed up after the end of the session with a letter stating their reasoning, though still without showing their math. The late release of the letter prompted Delegate David Toscano to write an editorial in the Washington Post decrying the staff members’ overtly political tactics as well as criticizing their analysis.

In its response to comments on the proposed carbon regulations, DEQ lists several flaws in the SCC staff’s analysis, ranging from significantly overestimating program costs to assuming that Virginia coal plants are immune to the economic stressors affecting coal plants across the U.S.

With time to reflect, many legislators will conclude the evidence supports DEQ. But more to the point, some Republicans may realize that holding Virginia back is bad economics and bad policy.

An analysisreleased this month shows wind and solar could replace 74 percent of coal plants nationwide at an immediate savings to customers; by 2025, that number will be 86 percent. Major utilities like Xcel and MidAmerican have targeted 100% renewable energy, saving money for customers in the process.

Meanwhile, voters across the country—and in Virginia—support renewable energy over fossil fuels by wide margins. Even polling by conservative groups shows strong support for clean energy.

It simply makes no sense for Virginia to opt out of the clean energy future. No doubt a lot of Republicans will vote to do it anyway in hopes of denying a win to a Democratic governor. But if they do, they run the risk of their constituents holding them accountable come November.

This article originally appeared in the Virginia Mercury on April 2. It has been updated to include DEQ’s response to the SCC staff’s letter.

Update April 4: Disappointingly but not surprisingly, the Governor’s amendments were defeated along party lines yesterday. If he wants to keep the carbon regulations moving towards implementation, he will have to exercise his veto authority. There have been questions raised about his authority to do that, so stay tuned. 

As Virginia prepares to join carbon-trading states, arguments erupt over the price of admission

photo courtesy of the Sierra Club

Virginia won’t enter the nine-state carbon emissions trading program known as the Regional Greenhouse Gas Initiative until 2020 under regulations being finalized by the state, but debate about how much it might cost utility ratepayers is already heating up.

Estimates range from little or no cost — or even a cost savings — to as high as $12 per month for the average household, depending on who is doing the calculations and the assumptions they make.

An Associated Press article reports that State Corporation Commission staff testified before a legislative committee that joining RGGI via the Virginia Coastal Protection Act, SB 1666 and HB 2735, would cost Virginia households an added $7-12 per month. The Northam administration disputed the SCC figure, saying the true cost would be about a dollar per month.

Republicans killed the bill in both the Senate and House committees that day.

A few days later, the anti-RGGI bill, HB 2611 (Poindexter), sailed through the House on a party-line vote. It would prevent Virginia from participating in RGGI or any other carbon-reduction regimen. If it also passes the Senate in coming weeks, it faces certain veto by the governor.

So is joining RGGI an inexpensive way to incentivize utilities to save energy and lower carbon emissions, or will it pile costs onto customers?

RGGI, for those of you who need a quick brush-up on your carbon policies, is a cooperative, market-based effort that has been running in New England and the Mid-Atlantic states as far south as Maryland for the past decade.

It works by auctioning carbon pollution allowances to major emitters, gradually ratcheting down the number of allowances made available each year to incentivize conservation and the use of lower-carbon fuels. States use the money they raise to fund energy efficiency, community solar, weatherization and other programs, often focusing especially on low-income residents.

First things first: RGGI works.

According to a 2018 report by Analysis Group, the RGGI region has met its targets, and benefited economically as well:

“Over three years (2015-2017), the RGGI program led to $1.4 billion (net present value) of net positive economic activity in the nine-state region,” the report says. “Each RGGI state’s electricity consumers and local economy also experienced net benefits from the RGGI program. When spread across the region’s population, these economic impacts amount to nearly $34 in net positive value added per capita.”

Virginia’s carbon reduction plan, now in the final stages of drafting at DEQ, will have Virginia participate in the RGGI auctions but not raise money from auctioning allowances.

Beginning in 2020, RGGI will add Virginia carbon emissions (28 million tons, the baseline DEQ has chosen) to the total for the existing members (56 million tons), and our utilities will bid for and trade allowances with the utilities in the other nine states.

But unlike the existing RGGI states, under DEQ’s plan Virginia will distribute its share of carbon allowances to our utilities at no cost, based on their previous year’s electricity sales. Utilities will sell the allowances into the RGGI auction bucket and buy back as many as they need. Initially, at least, the effect on ratepayers should be pretty much a wash.

Chris Bast, chief deputy at the Virginia Department of Environmental Quality said DEQ’s modeling program estimated rates would increase about 1 percent as a result of the new regulations. That’s a much lower figure than the $7 per month the SCC estimated the program would cost even with free allowances.

State Corporation Commission spokesman Ken Schrad said the DEQ “has understated the price of carbon emissions and understated Dominion’s cost of money for future capital investments (borrowed from lenders or invested by shareholders).”

“DEQ modeled Dominion as if it was a deregulated utility in a competitive market,” Schrad said. “Dominion’s fossil fuel generating units must be paid for in rates regardless of whether they are generating electricity under its vertically integrated structure.”

Bast takes issue with this. “I don’t know where the SCC got its numbers,” Bast told me. “Many folks, including the DEQ, have done extensive modeling to determine the environmental and economic impacts of the rule. That modeling is part of the public record and is part of the extensive public process that has gone into crafting this regulation. The SCC’s analysis is an outlier by several orders of magnitude – nearly 600%. The SCC has not provided any comment about ratepayer impact during any of our regulatory proceedings.

“We’re simply asking the SCC to show their work. But, to date, they have refused to provide us with the analysis that supports their conclusions.”

Bast says DEQ has not modeled what the program would cost if utilities had to pay for allowances, as contemplated under the Coastal Protection Act. Paying for allowances, according to the SCC, could drive costs up by an additional $5 per month.

This is a moot point, for now, since the Coastal Protection Act did not pass. But advocates believe that auctioning allowances offers an opportunity to raise funds to invest in energy efficiency and climate programs, so the idea remains on everyone’s radar for next year.

How RGGI works:

Under the Coastal Protection Act, auction proceeds would go into the state’s coffers to fund energy efficiency and resiliency programs that benefit the public. Utilities would be able to recover the costs of buying allowances from their customers, so there would be more impact on rates than there would be if allowances are free.

The Coastal Protection Act takes an extra step and actually requires investor-owned utilities to build wind and solar to achieve at least 50 percent of the required emissions reduction. If that amount were to exceed what they planned to build anyway, it would mean more costs paid for by customers—though maybe not a lot, if it speeds up the retirement of old fossil fuel plants that ought to close anyway.

RGGI reduces carbon emissions over time by gradually decreasing the number of auction allowances available in the region year after year. As the carbon cap tightens, either allowances become more expensive, or utilities reduce emissions, or both.

So far the RGGI states have succeeded in reducing emissions without higher allowance prices. They have done this in large part by closing coal plants and investing in energy efficiency and renewable energy, including programs paid for by auctioning the carbon emissions allowances.

Most RGGI states also have mandates for efficiency and renewable energy, which Virginia lacks. (In spite of the hoopla around it, last year’s “grid mod” bill did not require utilities to achieve any specific efficiency or renewable energy outcomes.) The combined effect of all these actions is that the prices paid for auction allowances in RGGI have stayed low.

According to the Analysis Group, consumers in RGGI states have benefited:

“On the one hand, the inclusion of the cost of CO2 allowances in wholesale prices tends to increase wholesale electricity prices in the RGGI region at the beginning of the 2015-2017 period,” the report says.

“But these near-term impacts are more than offset during these years and beyond, because the states invest a substantial amount of the RGGI auction proceeds on energy efficiency programs that reduce overall electricity consumption and on renewable energy projects that reduce the use of higher-priced power plants. Consumers gain because their overall electricity bills go down.

“Since RGGI’s commencement in 2009, energy and dollar savings resulting from all states’ investments in energy efficiency and renewable energy has more than offset the wholesale market price increases associated with inclusion of allowance costs in market bids.”

Virginia is as well-positioned as any of the RGGI states to meet the carbon-reduction goals.

Utilities can reduce energy demand through energy efficiency, resulting in less need for carbon-emitting fuel to be burned. They can also replace coal-fired generation with power from gas (with about half the CO2 of coal) or renewables (zero C02 for wind, water and solar; biomass has CO2 emissions as high as coal, but decision-makers pretend it’s carbon neutral).

Our nuclear plants, which provide a big chunk of Virginia’s electricity, are already operating at full capacity, and that’s not expected to change.

Intuitively, the solutions wouldn’t be expected to cost very much. Some of Virginia’s coal plants aren’t running very much these days anyway, putting them precariously close to the point where it is cheaper to close them than keep paying to have them available. As for alternatives, Dominion says solar is the cheapest form of new energy.

And energy efficiency is, famously, the lowest-cost energy resource, and vastly underutilized in Virginia.

In fact, projections have Dominion coming in under the RGGI cap for at least several years, putting our utilities in the happy (for them) position of possibly making money in the auctions.

But that doesn’t quite settle the matter.

There is one other consideration that could affect rates: Virginia utilities participate in the regional transmission organization known as PJM, which runs the wholesale power market. Anything that makes Virginia power more expensive makes it less attractive to the market.

That is surely part of the SCC staff’s concern.

To understand this dynamic, I consulted economist Bill Shobe, a professor at the Center for Economic and Policy Studies at the Weldon Cooper Center for Public Service at the University of Virginia, who studies carbon markets.

Shobe said that if Virginia utilities get CO2 allowances for free based on their previous year’s electricity generation, as the DEQ plan calls for, there should be no impact on their power plants’ competitiveness in PJM. The cost to customers would be little or nothing.

But if a coal or gas plant has to add the cost of CO2 allowances to its price of power, as happens in other RGGI states, power plants from non-RGGI states that don’t have to charge for CO2 will have a price advantage.

Shobe said if a Virginia utility adds the cost of CO2 allowances to the price of power from its own fossil fuel plants, those plants won’t run as much. Even the utility itself might buy cheaper wholesale power rather than run its own plants. Worse, the imported power could be higher in CO2 than the Virginia power it displaces, a problem known as “leakage.”

Dominion Energy Virginia’s 2018 Integrated Resource Plan, a document that forecasts how the utility will meet electric demand, predicted that if Virginia joined RGGI, its four big gas plants would run only an average of 64 percent of the time in 2025, compared to 79 percent in a scenario with no carbon constraints.

Dominion also claimed the cheaper imported power would come with such a higher carbon footprint than the power it was replacing that the whole deal would be counterproductive as a CO2 reduction strategy.

Skeptics should note that Dominion didn’t report the assumptions behind the modeling. Even its consultant, ICF, included a disclaimer that it was using the information Dominion gave it but “makes no assurances as to the accuracy of any such information or any conclusions based thereon.”

It’s also not clear that Dominion recognized any difference between getting free allowances and having to pay for them.

Shobe explained that Dominion’s modeling program didn’t account for DEQ’s use of “output-based allocation”— that is, distributing carbon allowances for free based on a utility’s generation in the previous year. This approach, said Shobe, incentivizes the utility to keep generating as much zero- or low-carbon electricity as it can so it will get as many allowances the next year as possible, and it will use its allowances to keep its own power competitive with imports.

The modeling that ICF did for Dominion, say Shobe, “treats all allowances as if they are sold at auction. Period. They don’t even attempt to model free allowances much less output-based allocation.”

With free allowances, customer costs should be minimal.

What if we auction the allowances?

Shobe said auctioning allowances instead of distributing them for free would make the power from Virginia’s fossil fuel plants less competitive in the PJM market. Yet customers will still have to pay for the capital cost of these huge gas plants that the SCC itself foolishly allowed Dominion to build, even if the power they generate is less competitive in PJM.

(“Foolishly” is obviously my term for it. The SCC not only doesn’t admit it did anything wrong, it rejected Dominion’s IRP in part because the company didn’t propose building yet another giant gas plant.)

The SCC’s high-end estimate seems to be based on this concern, but its numbers are much higher than even Dominion’s.

Dominion’s IRP estimated that joining RGGI would “cost Virginia customers about $530 million over the period 2020 to 2030,” or $53 million per year. The IRP says the impact would be about $3.50-$5 per month for residential customers, depending on the approach taken.

Even that estimate has to be taken with a bucket of salt. As the SCC staff noted at the time, Dominion overestimated the costs of joining RGGI by using overly high demand projections and failing to assume any decrease in demand from the hundreds of millions of dollars in efficiency programs the utility is required to design.

Obviously, those programs will also lower carbon emissions, helping Virginia meet the RGGI targets—as will building the solar energy envisioned by the grid mod bill.

So how the SCC staff has now come up with cost estimates even higher than Dominion’s is a head-scratcher. Nothing in the Coastal Protection Act appears to add costs beyond what Dominion knew about for its IRP.

This debate is surely not over.

We hope DEQ and the SCC will come together on a shared set of facts and assumptions, but meanwhile it is worth noting two points.

One is that even Dominion agrees some sort of carbon regulation at the federal level is likely eventually, even if it doesn’t happen under President Donald Trump’s administration.

Starting to shrink our carbon footprint now instead of later is going to save us money, even apart from its climate and health benefits.

The other is that the RGGI approach brings proven economic benefits to customers. As the Analysis Group report showed, customers in RGGI states actually saw lower bills in spite of higher rates because of the investments in energy efficiency.

If that happens in Virginia, joining RGGI will actually put more money in the pockets of customers.

 

A version of this article first appeared in the Virginia Mercury on February 6, 2019. 

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.

SCC cracks open the door on Dominion’s Atlantic Coast Pipeline costs

map showing VA and NC route of Atlantic Coast Pipeline

Costs to build the Atlantic Coast Pipeline are pegged at $7 billion. Partner Dominion Energy plans to charge captive electricity customers for the cost, regardless of whether the pipeline is needed. Image via the Federal Energy Regulatory Commission.

Dominion Energy Virginia employees were briefing a stakeholder group on the company’s Integrated Resource Plan (IRP) last Friday morning when text messages started popping up on phones all over the room: the State Corporation Commission had just rejected the IRP and ordered a do-over.

Awkward.

The SCC has never rejected a Dominion IRP before, mostly because the plan doesn’t have a binding effect. It is simply a way for Dominion to show regulators how it might meet the needs of customers over a 15-year period. If the company actually wants to build new generation or implement new programs, it still has to get permission through a separate proceeding.

But the IRP is important in establishing the context for new generation or programs. The SCC’s order on Friday shows commissioners think the company has presented a picture so distorted as to be unreliable.

The SCC order gives Dominion 90 days to correct a list of items it says the company got wrong, from unrealistically high demand forecasts to overly-optimistic assumptions about solar energy.

The order also instructs Dominion to look at an option the company ruled out: building yet another big combined-cycle gas plant. The SCC says it doesn’t necessarily want Dominion to build such a plant, only that the company ought to construct a true least-cost scenario to compare all other options against, and a least-cost option might include more baseload gas.

Then, buried down in footnote 14, the SCC added this:

The record reflects that the Company did not include fuel transportation costs in the modeled costs of certain natural gas generation facilities. Tr. 610. For purposes of the corrected 2018 IRP, the Company should include a reasonable estimate of fuel transportation costs, including interruptible transportation, if applicable, associated with all natural gas generation facilities in addition to the fuel commodity costs.

Wait a moment. Did the SCC just ask Dominion about the cost to ratepayers of its Atlantic Coast Pipeline?

Or does it just want to see different kinds of natural gas facilities modeled on an apples-to-apples basis, which Dominion failed to do? Even if it is the latter, can the SCC really open the door on transportation costs at all without letting the $7 billion elephant into the room?

If that happens, Dominion will find this the most expensive footnote in company history.

Dominion says the footnote is absolutely not about the ACP, and the company is shocked that anyone might think that. In a statement quoted in Energy News Network, the company lambasted environmental groups for perceiving a link between fuel transportation costs and a pipeline that provides fuel transportation:

“Instead of supporting Dominion Energy and policymaker’s (sic) push for carbon-free generation, [the Sierra Club and SELC] are distorting the SCC’s official order to pander to their donor base without regard for the truth,” the statement said.

This begs the question of how Dominion plans to comply with the order without mentioning its parent company’s pipeline. The company’s hysterical attack on its environmental critics seems designed to beat back expectations for the ACP’s cost to ratepayers becoming an issue in the IRP.

Footnote or no footnote, the SCC really should look at those pipeline costs

Admittedly, dropping a bombshell in a footnote would be only slightly more surprising than the SCC taking up the pipeline question at all right now. Pipeline critics have been trying in vain for two years to get the SCC to examine the contract between various Dominion subsidiaries obligating Virginia customers to pay for 20 percent of the ACP’s capacity. This blatant self-dealing is central to the pipeline’s profitability.

The SCC has previously refused to question the deal, and the Virginia Supreme Court refused to force the Commission to do it. The SCC maintained at the time that it could wait for the pipeline to be built before it decides whether it is fair to charge ratepayers for it. But it doesn’t have to wait; the Supreme Court says the SCC can take up the question any time.

And it should, because the SCC’s very silence encourages Dominion to think it will get away with charging customers for a hefty portion of the $7 billion pipeline. It is long past time for Dominion to present its evidence on the ACP.

As the SCC’s IRP order found, “the load forecasts contained in the Company’s past IRPs have been consistently overstated” and the SCC “has considerable doubt regarding the reasonableness of the Company’s load forecasts.” These questionable load forecasts, of course, underpin Dominion’s case for the ACP.

William Penniman, an energy lawyer who served as an expert witness for the Sierra Club in Dominion’s 2017 IRP case, testified that, based on publicly-available ACP filings, the contract with the ACP could cost utility customers in Virginia over $200 million of fixed charges annuallyfor 20 years—over $4 billion over the 20-year life of the contract, whether or not it ships any gas at all. He also showed that, even if more gas were needed, other pipeline options were much cheaper than Dominion’s affiliate deals.

And, given that Dominion already has contracts with another pipeline company to serve the utility’s existing gas plants, the money paid for capacity in the ACP will be entirely wasted—unless, of course, Dominion builds a bunch of new gas plants or drops lower-priced transportation arrangements in favor of its costly affiliate deals.

The pipeline came up again in the 2018 IRP. Gregory Lander, a witness for the Southern Environmental Law Center pointed out that Dominion’s IRP merely embeds the costs of the ACP into its generation scenarios without quantifying or justifying them.

“In essence,” Lander testified, “the IRP asks the Commission to accept that the Atlantic Coast Pipeline is built and that ratepayers should pay for it without ever explaining to the Commission what those costs are and why they are justified in a least-cost planning exercise.”

Rather than challenging the expert testimony, Dominion sought to exclude it, hoping to keep all mention of the ACP out of the case. In another footnote in its IRP order, however, the SCC specifically admitted Lander’s testimony, without finding facts.

Dominion would prefer the SCC to consider the ACP a “sunk cost.” Dominion’s theory goes like this: Since the contract obligates the utility to pay reservation charges for roughly half of the ACP’s capacity regardless of actual usage, that expense shouldn’t be factored into the cost of building any new gas plant. Instead, it argues, the SCC only needs to consider the cost of paying for the fuel itself.

That’s like buying a Ferrari and then saying the only expense of owning it is the gasoline. (And meanwhile, the trusty station wagon is running just fine.)

If the SCC is finally interested in the ACP’s cost to ratepayers, Dominion’s IRP do-over will have to be just the first step in a more thorough analysis of what Dominion’s self-dealing will cost Virginia consumers. There is plenty of evidence to suggest that will not go well for Dominion.

But what’s up with the SCC and gas?

Footnote 14 is not the only oddity in the SCC’s order. On the one hand, the SCC rightly says a fair accounting of a gas plant’s cost necessarily includes all the cost of transporting the fuel. On the other hand, even before it sees the transportation costs, the SCC seems to assume that a new baseload gas plant would be the economic thing to build, were it not for pesky carbon regulations and the General Assembly’s measures to promote renewable energy.

A major theme of the SCC’s order is the commission’s desire to force lawmakers to confront their own profligacy in passing the giant 2018 energy bill that the SCC opposed. SB 966 allows Dominion to redirect billions of dollars in over-earnings away from ratepayer refunds to massive spending on grid projects like undergrounding wires, with only limited regulatory oversight. The SCC thinks this is going to be bad for customers, and it wants legislators to appreciate just how bad.

That’s understandable, but it doesn’t excuse the SCC’s insistence on regarding gas as a low-cost option. Even Dominion knows better.

Dominion just announced the opening of its latest huge new combined-cycle plant in Virginia. The Greensville station joins a glut of new gas plants fed by Appalachia’s fracking industry. The oversupply is so bad that our regional grid already has almost 30% more power supply than it needs to meet peak demand—and grid operator PJM doesn’t expect this situation to change any time soon.

Most of the other new gas plants in PJM are funded by private equity. If they go bust, utility customers won’t be the ones to suffer. But Virginia’s regulated monopoly system means customers are precisely the ones who suffer when a utility’s bet on gas goes sour.

So Dominion’s IRP instead envisions a steady build-out of smaller gas plants it hopes to justify as complements to new solar farms. The idea is that these combustion turbines, often called “peaker” plants, will provide electricity to fill in around the variable output of solar panels.

Yet peakers are idle most of the time, making them questionable investments as well. Other states achieve the same reliability results at lower cost using demand response and battery storage.

The Rocky Mountain Institute (RMI) issued a report in May of this year comparing new gas generating plants—both combined-cycle and peakers—to well-designed clean energy generation portfolios. In almost every case, renewable energy, storage and demand response already beat gas on cost, even without considering environmental benefits.

And moreover, the trends favor clean energy, as RMI’s press release stresses: “More dramatically, the new-build costs of clean energy portfolios are falling quickly, and likely to beat just the operating costs of efficient gas-fired power plants within the next two decades.”

So in telling Dominion to present a gas-heavy scenario as low-cost, the SCC is asking the impossible. Whether the Commissioners know it or not, Dominion isn’t the only one here presenting a distorted picture.


This post originally appeared as a column in the Virginia Mercury on December 14, 2018.

SCC rips into Dominion’s offshore wind pilot, approves it anyway

Photo credit: Phil Holman

The Virginia State Corporation Commission (SCC) approved Dominion Energy Virginia’s proposed Coastal Virginia Offshore Wind (CVOW) project on Friday, but not happily. A press releasefrom the SCC complains about the project’s “excessive costs” and the way it is structured to make customers, rather than the developer, shoulder risks:

The offshore wind project consists of two wind turbines to be built by Dominion that would begin operating in December 2020. In its factual findings, the Commission determined that the company’s proposal puts “essentially all” of the risk of the project, including cost overruns, production and performance failures, on Dominion’s customers. Currently, the estimated cost of the project is at least $300 million, excluding financing costs.

The Commission found that the offshore wind project was not the result of a competitive bidding process to purchase power from third-party developers of offshore wind. Doing so would likely have put all or some of the risks on developers as has been done with other offshore wind projects along the East Coast of the United States. The Commission also found that any “economic benefits specific to [the project] are speculative, whereas the risks and excessive costs are definite and will be borne by Dominion’s customers.”

In spite of these harsh words, the SCC goes on to conclude that the language of the giant energy bill passed by the General Assembly last winter, SB 966, leaves regulators no choice but to approve CVOW:

The Commission concluded that the offshore wind project “would not be deemed prudent [under this Commission’s] long history of utility regulation or under any common application of the term.” However, the Commission ruled, as a matter of law, that recent amendments to Virginia laws that mandate that such a project be found to be “in the public interest” make it clear that certain factual findings must be subordinated to the clear legislative intent expressed in the laws governing the petition.

Obviously, the SCC has a point about the high cost of CVOW. Even Dominion agreed that if you just want 12 megawatts (MW) of power, you can get it a lot more cheaply than $300 million. The SCC’s Final Orderis even harsher on this topic. Moreover, the SCC doesn’t see any future for offshore wind as a matter of pure economics.

Nor is it all that reassuring that Dominion has said the price tag won’t have any impact on rates. What Dominion means is that we ratepayers have already paid for it, and as we aren’t going to get our money back anyway, we may as well enjoy seeing it put to use in building an offshore wind industry.

That’s where Dominion is (sort of) right, and the SCC (sort of) wrong. CVOW is the first step in the Northam administration’s plan to build an offshore wind industry in Virginia and install at least 2,000 MW of offshore wind turbines in the coming decade, a goal shared by many members of the General Assembly.

Northam says CVOW will lead to the commercial projects. Dominion says maybe, maybe not (“It’s too soon to have that conversation,” in the words of Dominion’s Katharine Bond). At any rate, it sure won’t happen without CVOW first.

Critics have said it’s silly to insist on a pilot project when other states are going forward with full-scale wind farms. That’s not entirely fair. As the first project in federal waters, the first in the Mid-Atlantic, and the first to be located 27 miles out to sea, CVOW’s two turbines will have much to teach the industry about offshore wind installation and performance in this part of the world. The whole U.S. offshore wind industry stands to benefit.

And also, Dominion has us over a barrel. Dominion holds the lease for the 2,000 MW; nobody else can come in and build it. So if Northam wants an offshore wind industry with thousands of new jobs, he has to do it Dominion’s way or not at all.

Clearly the SCC would choose not to do it at all. But then, the SCC has never shown any understanding of the climate crisis and the pressing need for Virginia to respond by developing as much wind and solar as possible, as rapidly as possible.

In the long term, we have to build out much more than 2,000 MW of offshore wind. As we do, and as costs decline in response to increasing economies of scale and technological improvements, the price tag of one pilot project will shrink in proportion to the billions of dollars flowing into the offshore wind industry and decarbonizing our electricity supply.

If it’s Dominion’s way or the highway, we have to do it Dominion’s way—for now—and then make sure it gets done.

No doubt the SCC would disagree. Yet to its credit, on Friday the SCC also approved Dominion’s purchase of power from a proposed 80-megawatt solar facility dubbed the “Water Strider” project. Unlike the offshore wind project, the solar project met the Commission’s prudency test because it involves a purchase from a private developer and followed a competitive bidding process. This resulted in a price to customers that the SCC felt is “in line with market rates.”

Though the Water Strider project looks like a clear winner for ratepayers, its approval wasn’t a foregone conclusion either. After a long history of approving one fossil fuel project after another, the SCC has belatedly begun to question Dominion’s projections about its need for more generation, at precisely the time when the new generation happens to be solar and wind.

For now, the SCC believes it must bow to the will of the General Assembly. For these two projects, that’s a good thing, but ratepayers will be in trouble if the SCC declines to assert its oversight authority in other filings under SB 966. Dominion wants to spend billions of dollars over the coming years on smart meters, software, burying power lines and other grid projects. Customers still need the SCC to make sure we get our money’s worth.

This article originally appeared in the Virginia Mercury

After the grid mod bill, the SCC wants to know how much authority it still has over utility spending

offshore wind turbines

Offshore wind turbines, Copenhagen, Denmark. Dominion Energy has asked the SCC for permission to proceed with building two wind turbines off the Virginia coast as a test project. Photo by Ivy Main.

It’s no secret the State Corporation Commission didn’t like this year’s big energy bill, the Grid Transformation and Security Act. SCC staff testified against SB 966 in committee, and their objections played a major role in amendments removing the “double dip” provision that would have let Dominion Energy Virginia double its earnings on infrastructure projects. Since passage of the bill, the SCC has raised questions about the constitutionality of the law’s provisions favoring in-state renewable energy, and its staff has issued broadsides about the costs of the legislation.

Now the SCC is mulling the question of how much authority it still has to reject Dominion’s proposals for spending under the bill. Dominion has filed for approval of a solar power purchase agreement (case number PUR-2018-00135) and two offshore wind test turbines it plans to erect in federal waters 24 nautical miles out from Virginia Beach (PUR-2018-00121). The utility has also requested permission to spend a billion dollars on grid upgrades and smart meters (PUR-2018-00100).

In an order issued September 12, the SCC asked participants in the solar and offshore wind cases to brief them on legal issues arising from the legislation. The SCC has focused in on two new sections of the Virginia Code. One is the language making it “in the public interest” for a utility to buy, build, or purchase the output of up to 5,000 megawatts (MW) of Virginia-based wind or solar by January 1, 2024. The SCC noted that subsection A of the provision says such a facility “is in the public interest, and the Commission shall so find if required to make a finding regarding whether such construction or purchase is in the public interest.”

The other new Code section gives a utility the right to petition the SCC at any time for a “prudency determination” for construction or purchase of a solar or wind project located in Virginia or off its coast, or for the purchase of the output of such a project if developed by someone else.

Together these sections give Dominion a good deal of latitude, but they don’t actually force the SCC to approve a project it thinks is a bad deal for ratepayers. In other words, wind and solar may be in the public interest, but that doesn’t mean every wind and solar project has to be approved.

The SCC asked for briefs on seven questions:

  • What are the specific elements that the utility must prove for the Commission to determine that the project is prudent under Subsection F?
  • Is the “prudency determination” in Subsection F different from the “public interest” findings mandated by Subsections A or E?
  • Do the public interest findings mandated by either Subsections A or E supersede a determination under Subsection F that a project is not prudent? If not, then what is the legal effect of either of the mandated public interest findings?
  • If the construction (or purchase or leasing) is statutorily deemed in the public interest, is there any basis upon which the Commission could determine that such action is not prudent? If so, identify such basis or bases.
  • In determining whether the project is prudent, can the Commission consider whether the project’s: (a) capacity or energy are needed; and (b) costs to customers are unreasonable or excessive in relation to capacity or energy available from other sources?
  • Do the statutorily-mandated public interest findings under either Subsections A or E override a factual finding that the project’s: (a) capacity or energy are not needed for the utility to serve its customers; and/or (b) costs to customers are unreasonable or excessive in relation to capacity or energy available from other sources, including but not limited to sources of a type similar to the proposed project?
  • Does the utility need a certificate of public convenience and necessity, or any other statutory approval from the Commission, before constructing the proposed projects?

Even if the Commission decides it has latitude in deciding which wind and solar projects to approve, that doesn’t necessarily spell disaster for the two projects at issue. The SCC could still decide they meet the standard for prudency and approve them.

Oral argument on the issues is scheduled for October 4.

Should approval of smart meters depend on how the meters will be used?

The SCC is also mulling over its authority in the grid modernization docket. One day after it asked lawyers in the solar and offshore wind cases to weigh in on the meaning of prudency, it issued a similar order asking for input on what the new law means by “reasonable and prudent” in judging spending under the grid modernization provisions. (Yes, the grid mod section of the law insists that spending be “reasonable” in addition to “prudent,” begging the question of whether spending can be prudent but not reasonable. Perhaps thankfully, the SCC order does not pursue it.)

The SCC’s questions to the lawyers show an interest in one especially important point: Dominion wants to spend hundreds of millions of dollars of customer money on smart meters, without using them smartly. Smart meters enable time-of-use rates and customer control over energy use, and make it easier to incorporate distributed generation like rooftop solar. None of these are in Dominion’s plan. Is it reasonable and prudent for Dominion to install the meters anyway, just because they are one of the categories of spending that the law allows?

Or as the SCC put it:

If the evidence demonstrates that advanced metering infrastructure enables time-of- use (also known as real-time) rates and that such (and potentially other) rate designs advance the stated purposes of the statute, i.e., they accommodate or facilitate the integration of customer-owned renewable electric generation resources and/or promote energy efficiency and conservation, may the Commission consider the inclusion or absence of such rate designs in determining whether a plan and its projected costs are reasonable and prudent?

Reading the tea leaves at the SCC: Staff comments on Dominion’s IRP

The SCC’s question about smart meters surely indicates how the commissioners feel about the matter: they’d like to reject spending on smart meters, at least until Dominion is ready to use them smartly. If the SCC concludes it has the authority to reject this part of Dominion’s proposal as not “reasonable and prudent,” it seems likely to do so.

It is harder to know where the SCC might land on the solar and offshore wind spending. The SCC’s staff, at least, are skeptical of Dominion’s plans to build lots of new solar generation. In response to Dominion’s 2018 Integrated Resource Plan (IRP), Commission staff questioned whether Dominion was going to need any new electric generation at all, given the flattening out of demand. But if it does, according to the testimony of Associate Deputy Director Gregory Abbott, Dominion ought to consider a new combined-cycle (baseload) gas plant, not solar. (Combined-cycle gas was the one generating source Dominion almost completely ruled out.)

Abbott criticized Dominion’s presentation of the case for solar, though he took note of the technology’s dramatic cost declines. Instead of seeing that as a reason to invest, however, he suggested it would be better to wait for further cost declines, or at least leave the construction of solar to third-party developers who can provide solar power more cheaply than the utility can. Remarkably, he also suggested Dominion offer rebates to customers who install solar, urging that Dominion’s spending under the grid transformation law “is designed specifically to handle these [distributed energy resources].”

Abbott also seemed supportive of Dominion’s venture into offshore wind. The only offshore wind energy in the IRP is the 12 MW demonstration project known as CVOW, but as Abbott noted, “the Company indicated that it will pursue a much larger roll-out of utility-scale offshore wind, beginning in 2024, if the demonstration project shows it to be economic.”

This suggests staff are inclined to support Dominion’s spending on the CVOW project, but for Abbott, it was one more reason Dominion should not invest in solar. He concluded, “If the demonstration project proves that utility-scale offshore wind is economic compared to solar, then it may make sense to get the results of the CVOW demonstration project before deploying a large amount of solar.”

This post originally appeared in the Virginia Mercury on September 24.

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.