2388. Why Home Solar Panels No Longer Pay in Some States

By Diane Cardwell, The New York Times, July 26, 2016

LAFAYETTE, Calif. — It was only two years ago that Elroy Holtmann spent about $20,000 on a home solar array to help cover the costs of charging his new electric car. With the savings on his monthly electric bills, he figured the investment would pay for itself in about a dozen years.

But then the utilities regulators changed the equation.

As a result, Pacific Gas & Electric recently did away with the rate schedule chosen by Mr. Holtmann, a retired electrical engineer, and many other solar customers in this part of California. The new schedule will make them pay much more for the electricity they draw from the grid in the evening, while paying those customers less for the excess power their solar panels send back to the grid on sunny summer days.

As a result, Mr. Holtmann’s solar setup may never pay for itself.

“They’ve taken any possibility for payback away,” he said with resignation, looking up at the roof of his 1970s ranch-style house in this suburb a short drive east of Berkeley.

The paradox is playing out around the country. Even as policy makers at the federal and state levels promote clean energy to fight global warming, the economics of electricity can often be at odds with those goals.

Thrust in the middle are utility regulators. Even if they support greening the grid through technology adopters like Mr. Holtmann, the regulators are also responsible for ensuring that the utilities can afford to supply power to the largest number of customers at the most equitable rates. That includes people without the money or inclination to install solar collectors.

“The grid is no longer just a cheap way to get electrical commodities to people,” said Michael Picker, president of the California Public Utilities Commission. “People want choices, they want customized services,” he said. “And how do you make that fair to everybody, because not everybody is moving as adopters at the same pace?”

Similar dynamics are playing out in some parts of Europe, including Spain and Britain, as public officials push for green energy to justify its costs.

For more than a century in the United States, the public utility rate system assumed a one-way flow of electricity from central power plants to their customers. The role of utility regulators was to adjudicate reasonable rates for the consumer, while allowing an adequate rate of return on the money power companies spent generating and distributing the electricity.

But now, even though rooftop solar energy still accounts for less than half of a percent of the energy generated across the country, its growing popularity is challenging regulators and utilities to rethink their old ways.

Last year, Nevada and Hawaii moved to end retail-rate credits awarded to solar owners for energy sent back into the grid.

In Arizona, a utility won the right to make solar customers pay mandatory monthly fees called demand charges, which have been common among large commercial and industrial customers but unusual for residential consumers. Utilities in several states are now seeking to follow that path.

During the first quarter of this year alone, at least 10 states were weighing or approving rate design measures that could undermine the economic appeal of home solar systems, according to data compiled by the North Carolina Clean Energy Technology Center.

The challenge is to design a new kind of rate system — one that accurately values electricity that can now flow in different directions and at different volumes at different times of day. It can also, depending on the location and level of demand, either increase or relieve strain on the grid.

“This is really about a revolution in the relationship between utilities and customers,” said Adam Browning, executive director of Vote Solar, a policy and advocacy group based in California. “It’s not just going to be about solar, but solar is forcing the regulatory construct to accommodate this.”

Energy experts predict a bumpy transition.

“Rate design done without a bigger-picture context in mind can absolutely have a chilling effect on the growth of clean energy and consumer-driven clean-energy resources,” said Sara Baldwin Auck, regulatory program director at the Interstate Renewable Energy Council, a nonprofit policy group that supports clean energy.

Nowhere has the rate wrangling been more urgent than in California, the nation’s leading solar market and home to more than half of its residential rooftop solar customers.

In 2001, in response to soaring prices, electricity shortages and financial instability among the utilities, California lawmakers approved a multi-tier residential rate structure meant to encourage customers to use less power, with the largest consumers paying the highest rates.

But regulators also froze rates in the two lowest-priced tiers, covering a majority of residential users, to shield those customers from rapidly rising energy costs. That meant the brunt of utility costs were borne by the higher-use groups.

Many high-use residential customers who could afford to install solar did so. That resulted in an even smaller customer base shouldering the heaviest burden. By 2014, customers in the top tier in PG&E’s territory were being charged as much as 36.4 cents a kilowatt-hour — nearly triple the amount paid by those in the lowest tier.

Mr. Holtmann was occasionally among the highest users during the summer, so he was happy to save money, while doing something to reduce harm to the environment.

Not long after moving into his house in 1973, he installed a solar water heater. The first set of solar panels went on the roof around 2008. That slashed his annual electric bill to $78 from about $1,300. But the bill shot up again after he bought the new car, a Chevy Volt electric hybrid, so he bought a second set of panels in 2014.

The rate schedule Mr. Holtmann chose was based on PG&E’s longstanding assumption that the highest demand for the utility’s electricity was occurring between noon and 6 p.m. But now, because there is so much solar energy pouring into the grid from morning through late afternoon, the utility’s peak demand comes closer to the evening, when the solar supply drops sharply as the sun sets.

Thus the new rate schedules. The idea, said Donald C. Cutler, a PG&E spokesman, is to spur the use of electricity “when it’s more efficient and more economical to deliver it.”

So in May, as part of a multiyear rate redesign, regulators retired the schedule that had appealed to Mr. Holtmann and many other solar customers.

The new rate plan shifted the peak times to later in the day — either 3 to 8 p.m., or 4 to 9 p.m. — when solar arrays are much less productive.

That change provoked so many customer complaints that the California Public Utilities Commission directed PG&E to delay it. As a result, customers like Mr. Holtmann can move to a schedule whose peak is nominally more solar-compatible — 1 to 7 p.m. — but only until 2022. After that, they will be required to shift again.

Mr. Holtmann said he was not yet sure how his annual electric bill would change. But even the temporary compromise will not help much, he said, because his neighborhood is nestled below a hill that begins blocking the sun around 4 p.m. The one certainty, he says, is that he will end up spending much more.

Mr. Picker, the utilities commissioner, said that the regulators extended the rollout of the new rate system because the utility had not given customers sufficient warning. But he defended the new structure, saying it was more in line with the evolving needs of the grid and the overall customer base.

For solar customers, he said, “there was no guarantee that the rates were going to stay the same as the world changed.”

But some ratepayer advocates say that linking solar bill credits to retail rates is the wrong strategy.

“The changes are so significant and unknowable that right now it’s impossible for a solar customer to look at that equation and have any sense of what they’re likely to save on their bill over time,” said Matthew Freedman, a lawyer at the Utility Reform Network, which works on behalf of California residential customers.

Mr. Holtmann said he felt misled.

He installed his panels “with the understanding that the rules were going to be the rules,” he said. “And then they changed the rules.”

2250. Another Large Solar Company, Abengoa, Is in Crisis

By Raphael Minder, The New York Times,  March 17, 2016

Recent Abengoa SA stock price. Chart: CNBC

Announcing government support for clean-energy projects, President Obama hailed a Spanish company, saying its new solar technology would supply tens of thousands of American homes with renewable power, while spurring local employment.

“It’s good news,” Mr. Obama said in 2010, “that we’ve attracted a company to our shores to build a plant and create jobs right here in America.”

Since then, the Spanish company, Abengoa, has built two American plants, in Arizona and California, supplying electricity to more than 160,000 homes. It is the world leader in a technology known as solar thermal, with operations from Algeria to Latin America.

But Abengoa’s global ambitions are now the source of its troubles.

Saddled with debt from its expansion, the company is scrambling to avoid what would be the largest bankruptcy in Spanish corporate history. Creditors and shareholders are taking the company to court as losses mount and crucial financial support disappears.

The company’s changing fortunes, from industry darling to financial invalid, are an extreme example of the challenges facing players in the renewable energy business.

Clean-energy technologies will play a crucial role as countries try to meet the ambitious targets set by the United Nations climate accord last December. But many of the technologies underpinning renewables are proving economically unsustainable in the short term, particularly with oil prices declining and governments reducing incentives.

The financial reality is forcing companies globally to adjust. A big British utility, SSE, is rethinking its wind farms, as the country cuts subsidies. SolarCity and other American renewable companies left Nevada after the state withdrew its support of rooftop systems.

In Abengoa’s case, its signature American projects still have around $2 billion in outstanding loans guaranteed by the United States government, and the company benefited heavily from subsidies in Spain. But its solar thermal projects have been slow to turn a profit and generate little income in the interim, amplifying its cash squeeze.

Its fall from grace, said Valeriano Ruiz Hernández, a retired professor at Seville University who taught many of the company’s engineers, is “a genuine hammer blow” for Spain and its renewable energy sector.

“I always had the intuition that so much corporate ambition would end up bursting at the seams,” he said.

Founded by two engineers in Seville in 1941, Abengoa initially set out to manufacture a type of electricity meter. Though the meter never gained traction, the company began installing auxiliary panels for power stations and electrical systems for buildings.

By the 1960s, it began expanding overseas to Central and South America, with projects like erecting transmission lines in Argentina. It made its first foray into renewables in the 1980s.

In 2007, the company established the world’s first commercial solar thermal power plant in Sanlúcar la Mayor. On the outskirts of Seville, a handful of towers dominate the farming landscape, rising above sunflower and cattle fields like modern obelisks to solar energy.

In a solar thermal power plant, mirrors reflect the sun’s rays toward the top of each tower, concentrating the light and generating high enough temperatures to heat up a transfer fluid. That heat creates steam to power a turbine, generating electricity.

Abengoa now accounts for more than a quarter of the five gigawatts produced worldwide by solar thermal plants. Unlike conventional solar power, the thermal technology allows energy to be stored, meaning the turbines can generate power for hours after the sun sets.

The same year the Sanlúcar plant opened, Abengoa’s stock price hit a record high of 7.39 euros a share. By November, when it began insolvency proceedings, it had fallen below 40 euro cents. It now sits at 71 euro cents.

Since then, Abengoa has been looking for a lifeline to restructure its $10.3 billion of debt.

Spanish law gives the company four months to right the ship. And last week, Abengoa said it had reached an agreement with creditors, a deal that requires final approval.

As part of the restructuring, Abengoa’s global activities — from transmission lines across the Amazon, to water desalination plants in Algeria and Ghana — could all be up for grabs.

“My expectation is that a lot of Spanish know-how will end up in foreign hands,” said Javier García Breva, a renewable energy expert who is president of N2E, a consultancy.

For now, Abengoa says the deal will not affect its operations in the United States, where the company holds a 42 percent stake in Atlantica Yield, which runs two solar thermal plants in Gila Bend, Ariz., and near Barstow, Calif.

The plants, known as Solana and Mojave, have drawn criticism for years over the American government’s backing.

The projects were partly financed by $605 million in federal grants and tax credits, according to Good Jobs First, a research center that tracks public subsidies. Abengoa also received a combined $2.9 billion in loan guarantees from the United States.

“The whole reason Abengoa Solar had to get the guarantee from the government is that no private lender thought the risk was worth it,” the Institute of Energy Research, a prominent renewables critic that has received financing from the oil industry, said in 2011.

Abengoa says that nearly $1 billion of the federally guaranteed loans has been repaid. American taxpayers, it says, will incur no costs for the projects as long as they continue operating normally.

Abengoa’s problems extend from the balance sheet to the courtroom.

It is facing lawsuits in the United States and Spain from shareholders and creditors. The suits make a variety of claims, with one accusing the company of misleading investors about downplaying its capital needs and another accusing individual executives of acting against investor interests.

An Abengoa spokeswoman said the company would not comment on the cases.

At home, crucial revenue supports that Abengoa and other clean-power producers relied on have been removed.

Looking to cut its debt load, Spain slashed subsidies for renewables. In particular, companies that signed long-term deals to sell green power to customers at guaranteed rates saw those prices cut. The move, which applies retroactively to the summer of 2013, has prompted legal action from international investors who say it is a breach of their contracts.

The multitude of problems is amplifying the pain for Abengoa, which lost $1.3 billion last year. In February, its employees were paid late and, as part of the negotiations with creditors, it asked for more time to repay one of its bonds.

The ripple effects are being felt beyond the company.

A short drive away from Sanlúcar, a research and business park was meant to feed off Abengoa’s presence. Regional authorities originally set aside $22.4 million to develop the area as a hub for clean technology and environmentally focused companies. But three years after opening, only $3.6 million has been spent on it, and it has failed to attract other companies.

Abengoa’s problems have also cast a pall on Spain’s renewables sector. Industry groups, fearful of a withdrawal of government support, are on the defense.

“The problem of Abengoa is not the failure of a sector, far from it,” said Luis Crespo, the president of Estela, the European solar thermal electricity association. “We really hope policy makers don’t start mixing up cost and value.”