Tuesday, September 19, 2017

Why Solar Advocates Are Crying Foul Over New York’s Latest REV Order

New York’s Reforming the Energy Vision (REV) initiative just took a wrong turn, according to solar groups. 

Last week, the New York Public Service Commission (PSC) approved an order for setting the Value of Distributed Energy Resources, or VDER -- the complex metric that the state wants to use to replace net metering, for larger-scale community solar projects in the short term, and eventually, for all distributed energy resources (DERs) across the grid. 

But last week’s order is drawing fire from solar groups, including the Natural Resources Defense Council (NRDC), the Solar Energy Industries Association, Vote Solar and the Acadia Center. According the NRDC, the PSC’s order could allow “flawed utility proposals that undercount the value of solar resources” to become part of the record, and “make it impossible for many solar projects to predict part of their revenues from the policy and obtain financing on that basis.” 

That’s frustrating, these groups say, because they jointly filed comments with the PSC in July that laid out the specific flaws within each utility’s proposal in fine detail, and suggested ways to fix the discrepancies. Not only were these suggestions left out of PSC’s final order, but the groups didn’t have a chance to comment on the utilities’ methods for calculating VDER before they were passed. 

We’ll be covering the ins and outs of New York’s REV implementation at next week’s New York REV Future 2017 conference in Brooklyn, where and the PSC’s latest order will likely be a major topic of discussion. 

The reaction this week has been markedly different from the cautious support given by solar groups to the PSC’s first big ruling on valuing DERs back in March -- largely because it allowed most classes of solar to remain grandfathered in under current net metering rules.

But the March order also put community solar -- one of the state’s fastest growing solar segments -- on notice that they should expect to earn money based on an emerging VDER value, and not on net metering. 

The problems with calculating VDER in the PSC's new order are multiple, these groups say, but can generally be separated into two classes: the issue of wildly different utility values for DERs on the grid and the issue of long-term financial certainty. 

On the first, the order has allowed utilities to move forward with plans that have wildly different calculations for Utility Marginal Cost of Service, or MCOS -- the base measure of what it costs for utilities to serve customers at different points on the grid. 

MCOS figures are meant to be used to derive two key values for VDER. The first is demand reduction value (DRV), or the averaged-out value for reduced energy delivery costs that come from DERs on a system-wide basis. The second is locational system relief value (LSRV) -- the value tied to specific locations where DERs could help utilities avoid forecasted distribution system investments. 

But according to a filing from solar groups, “utilities take varying approaches to interpreting their MCOS studies to determine DRV/LSRV. This results in wildly varying estimates of the delivery value provided by DERs,” as evidenced by this chart below, which shows that the state’s utilities have come up with kilowatt-hour values ranging from $226 for Con Edison, to $15 for Central Hudson. 

Not surprisingly, the solar groups are most critical of the utilities whose methodologies have yielded the lowest MCOS rates. Both New York State Electric & Gas Corporation and Rochester Gas & Electric, for example, limit their analysis to “growth-related network investments primarily involving expansion or reinforcement of upstream distribution, distribution substation and trunkline feeders in growth areas," according to solar groups. "This method ignores several other system needs, most notably in areas not undergoing growth, and those below trunkline feeders. This also arbitrarily excludes the ability of DERs to extend equipment life, increase reliability and resiliency, and improve power quality.” 

The second big problem that solar advocates have with the PSC’s order is its lack of long-term certainty for rates that solar projects can receive under the emerging regime. In simple terms, financial backers are looking for proof that solar projects can earn a steady and predictable set of revenues over the long term, for 10 years or more. But the PSC’s order would allow at least some of these calculations to be revisited every three years, leaving open the possibility that future revenues could be drastically changed three times within that 10-year window. 

According to the solar groups’ July filing, “the VDER Order provides that DRV and LSRV rates/values shall be determined every three years. Any project that receives LSRV compensation shall receive the specific compensation rate for a period of 10 years. The DRV rate/value, however, is only fixed for the three year period prior to the time at which it is reset.” 

“We cannot emphasize enough the reality that lenders and other financial parties that are essential to the functioning of the DER market will heavily discount or assign no value to components of the value stack that cannot be forecasted or predicted. Predictability and consistency in calculation methodology must be a touchstone of the VDER DRV and LSRV methodologies. Without it, these portions of the value stack will not be viewed as bankable sources of value and will not meaningfully contribute to the construction of new projects,” the groups wrote. 

With last week’s order set, solar advocates are now turning their attention to Phase 2 of the REV proceeding, in which the PSC will fine-tune its VDER methods as it seeks to extend them to smaller rooftop projects on homes and small businesses, as well as technologies such as stand-alone energy storage and, potentially, combined heat and power systems.

Many of these smaller projects will be cushioned from the most drastic changes through a pre-determined ‘market transition credit’ set out in the March order. But, as NRDC's Miles Farmer wrote, “if the utility methodologies are used as a basis for Phase 2, that would create a bigger problem.” 

***

Building on last year’s sold-out conference, NY REV Future 2017 will bring together key stakeholders, technology providers, utilities and state policymakers to discuss actionable business strategies to operationalize the ongoing initiative for a clean, resilient and affordable system in New York. We're asking the tough questions, recognizing the advances in New York's energy future to date and advancing the conversation into how REV becomes second nature for the business of energy. Join us.



from GTM Solar https://www.greentechmedia.com/articles/read/why-solar-advocates-are-crying-foul-over-new-yorks-latest-rev-order

Improving the Performance of Wide-Bandgap Perovskite Solar Cells via Non-Stoichiometric Solution Chemistry

Perovskite halides (e.g. CH3NH3PbI3 or MAPbI3) are a new class of light absorbers with exceptional and unparalleled progress in solar cell performance. A perovskite is any material with a specific ABX3 crystal structure, wherein an organic based cation is A, a metal cation is B, and a divalent halide anion is X. Work on solar cells using these perovskite materials has advanced rapidly as a result of the material’s excellent light absorption, charge-carrier mobilities, and lifetimes that result in high device efficiency with low-cost, industry-scalable technology. However, this potential for low cost and scalability requires overcoming barriers hindering the commercialization of perovskite devices related to perovskite stability, efficiency, and environmental compatibility. NREL researchers have made significant technical contributions within six areas critical to developing commercialized perovskite devices, which include increases in film efficiency and stability and innovations in perovskite film deposition methods, film chemistry, hole and electron extraction layer engineering, and device architecture.



from Energy Innovation Portal Technology Ticker https://techportal.eere.energy.gov/technology.do/techID=1586

How Deregulation Could Improve Reliability for Cash-Strapped African Utilities

Sub-Saharan African utilities are caught in a complicated interplay between centralized grid-extension costs and the decentralized off-grid generation boom. Liberalizing their electricity markets may be a partial solution.

While high demand growth and the need for investment drove dramatic electricity sector reform in low- and middle-income countries in the 1990s and early 2000s, Power for All and GTM Research find that 71 percent of sub-Saharan African countries currently rely on vertically-integrated utility structures, although the proportion is steadily declining.

Source: Power for All, GTM Research (Key: Light Blue: Privatized, Medium Blue: Mix of Public and Private Ownership, Dark Blue: Public Ownership

Electricity market liberalization means more than unbundling

Pioneering reform programs have generally included corporatization; vertical and horizontal restructuring of generation, transmission, distribution and retail functionalities; unbundling of tariffs; as well as the introduction of independent performance-based regulatory mechanisms.

With the aim of segmenting the cost of generation, transmission, and distribution, empirical evidence shows that such liberalization reforms lead to increased operational efficiency, reduced pricing distortions and increased electricity access for poor consumers.

In sub-Saharan Africa, reforms are slowly being implemented. Unbundled utilities on the continent tend toward segmented -- and to some extent, privatized -- generation, transmission and distribution. In most cases, however, public control is maintained over the grid. Electricity continues to be sold at rates below cost recovery and infrastructure is not well maintained.

While this has led to an investment surge into private generation assets, leaving transmission and distribution infrastructure behind hurts the financial solvency and expansion plans of these utilities.

In fact, from 1995-2015, independent power producer (IPP) capacity in Sub-Saharan Africa doubled every five years, primarily in countries with prepossessing credit ratings and stable investment climates, while investment in transmission and distribution infrastructure lagged significantly in the same period, falling well short of the $435 billion estimated necessary for universal access by 2040.

IPPs operating in Africa have pointed to a looming crisis in generation, as almost all countries are expecting generation surpluses in the not-too-distant future. Increasingly, the trend is to see national governments operate as a majority stakeholder alongside a number of provincial agents and private IPPs, as the requisite policy for full private ownership often does not accompany liberalization.

But reforms are slow going

Developing such effective regulation has proven one of the most challenging aspects of the restructuring process in sub-Saharan Africa.

As such, despite the push towards liberalization, chronically undercapitalized African utilities have historically been unable to recover operational and capital costs.

Last year, the World Bank found that of 39 Sub Saharan countries surveyed, only the Seychelles’ and Uganda’s national utilities were fully recovering both operational and capital costs, and only 19 of the 39 collected enough cash to cover operational expenditures only, hampering their ability to meet demand reliably and keep up with population growth and rising incomes. Financial difficulties in recently reformed electricity markets in Mali and Senegal even caused the power sector to revert to state ownership.

Source: Power for All, GTM Research

So how can liberalization boost reliability and electrification rates?

Unbundling reforms have major implications on the financial health and capacity expansion outlook of struggling public utilities.

As more utilities begin to seriously prioritize universal energy access within their service territories, ensuring their own financial health as a public service provider and as an off-taker for IPPs must be the first course of action. Additionally, regional cooperation in the form of cross-border energy trading could be a powerful incentive for private investment in high-voltage transmission projects.

A 2015 McKinsey study suggests that regional integration could save over $40 billion in capital expenditures and $10 billion annually for the African consumer by 2040, though less than 8 percent of power generated in Africa is currently traded across borders. On the national level, tendering transmission and distribution capacity and leapfrogging the West on advanced metering infrastructure and collection will significantly improve operational efficiency and reduce technical and non-technical losses.

Liberalization can have major implications for new technologies and distributed renewable energy (DRE) solutions. Unbundling opens up markets for behind-the-meter generation across the various tiers of energy solutions that DRE solutions provide, from solar home systems to grid-integrated mini-grids. Separating the cost of service and the cost of infrastructure also allows the opportunity for exercising tariffs that truly reflect the cost of electricity generation, particularly critical as part of an enabling environment for mini- and micro- grid developers.

Also important for mini-grids, regulation and the establishment of integration standards often means more efficient access to transmission networks. Furthermore, electricity policy reform and a competitive grid also bring increased transparency around grid extension plans, a huge risk for mini-grid developers, and the opportunity to develop a conducive regulatory environment for decentralized renewable energy applications and coordinate with off-grid developers and installers.

For instance, the 2013 unbundling of the Ethiopia Electric Power Corporation (EEPCO) into the Ethiopian Electric Services (EES) and Ethiopian Electric Power (EEP) in response to the country’s energy shortage in the 2000s allowed private investment into generation, transmission, and distribution assets as well as allowed for the import and export of IPP-generated power.

In order to meet a huge gap in capital investment, the Ethiopian central government also created the Ethiopian Energy Agency to foster both wholesale and retail price competition between IPPs and EEP, improving the operational efficiency of EEP, but raising tariffs for end-use consumers. As a result, a slew of financing vehicles for DRE solutions were mobilized, making Ethiopia one of the top three markets for SHS and pico solar adoption in sub-Saharan Africa.

While U.S. and European utilities hold their own regulatory debates about cost-of-service ratemaking and why volumetric tariffs no longer capture the emerging value proposition offered by the grid, steps toward competition and increased efficiency on the grid taken in Sub-Saharan Africa suggest that African utilities are moving in the right direction.

Indeed, a recent PwC survey of African utility executives finds that 70 percent agree that the opening up of markets, in the form of unbundling and liberalization, would have a high or very high impact on electrification and supply reliability.

However, survey participants also agree that modernization of regulation to keep up with and encourage the potential of off-grid and mini-grid solutions is critical. This includes fast and low-cost licensing and permitting for mini-grids, technical regulation and quality standards, tariff and VAT exemptions for DRE components, and transparent protocols for distribution companies on mini-grid operator rights if the grid arrives.

If universal energy access is to be achieved by 2030 across the continent, sub-Saharan Africa’s moves toward liberalization will need to be faster, with greater attention to regulatory reform that encourages the inclusion of off-grid solutions while simultaneously creating effective regional power markets to improve cross-border trade.

African electricity sector leaders recognize the critical role that off-grid solutions have to play, and are beginning to engage with last-mile and under-the-grid consumers in creative ways to fill those gaps served most reliably and at least cost by centralized infrastructure.

--

This is the first installment in a joint series between GTM Research and Power for All exploring the dynamics of energy access issues in emerging markets. Power for All is a global coalition of 200 private and public organizations campaigning to deliver universal energy access before 2030 through the power of decentralized, renewable electricity.

As a pillar of Wood Mackenzies redefined focus on studying global trends in the transformation of power, GTM Research is studying the energy transformation occurring Beyond the Grid Edge in the off-grid rural energy access space.



from GTM Solar https://www.greentechmedia.com/articles/read/how-deregulation-could-improve-reliability-for-african-utilities

Monday, September 18, 2017

A Top CEO Brings Us Inside India’s Fast-Changing Renewables Market

India has blossomed into one of the most important renewable energy markets in the world.

It currently has the fourth-most cumulative wind capacity installed, and will become the third-biggest solar market globally by 2022. The country also has plans to sell only electric vehicles by 2030.

With immense growth comes new businesses and economic opportunity -- but also political and economic risk.

This week, we'll talk with the CEO of India's top independent renewable energy developers about navigating that risk.

Sumant Sinha is the founder and CEO of ReNew Power. He's overseen 2 gigawatts of completed wind and solar projects, and has plans to build 10 gigawatts more in the coming years.

In this show, we interview Sinha about the many forces that are changing India’s energy markets. We address:

  • The solar boom: Can India meet its 100 gigawatt solar target?
  • Grid planning: Can central and state governments better coordinate market expansion?
  • Quality: The importance of maintaining quality standards for projects
  • The rise of auctions: Are record-low prices sustainable?
  • India's EV target: Will it tangentially help 
  • ReNew Power's expansion: What will it take to hit 10 gigawatts of projects?

This podcast is sponsored by Mission Solar Energy, a solar module manufacturer based in San Antonio, Texas. You can find out more about Mission’s American-made, high-power modules at missionsolar.com.

Recommended reading:

  • Quartz: A Former Wall Street Banker Is Building India's Largest Clean Energy Company
  • GTM: India Already Has a Problem With Wasting Renewable Energy on the Grid
  • GTM: The Overlooked Solar Opportunity in India


from GTM Solar https://www.greentechmedia.com/articles/read/inside-indias-energy-market

What’s Holding Back Community Solar Investment Decisions Among Consumers?

Potential solar customers are certainly window shopping. But in today’s market, interest doesn’t always equate to sales.

The latest Solar Marketplace Intel report from EnergySage shows increasing interest in solar from consumers. But the current array of options aren’t always enough for shoppers to buy -- especially for community solar,

In all of the six utility service areas EnergySage analyzed in its latest report, the levelized cost of energy (LCOE) for solar bested this year’s rates from residential electricity providers. And based on an analysis of traffic to its Solar Marketplace site, EnergySage found that solar interest surged in every state in the nation, with the most marked gains in “emerging markets” where the baseline is lower.

The gross costs of solar per watt also continued to steadily drop in the 35 states analyzed, from $3.36 in the second half of 2016 to $3.17 in the first half of 2017, with a standard deviation of $0.47. 

So what’s keeping community solar customers from making the jump? EnergySage cites two top reasons for the hesitation: Customers feel there are a lack of options where they live and the financial benefits aren’t drastic enough to be persuasive. 

The top reason community solar customers did invest was an inability to install rooftop panels. The potential for electric bill reductions came in second. Of the 80 percent of potential customers EnergySage surveyed, many cited the need for stronger financial incentives. The 12 percent of customers who decided not to invest in community solar projects said cost was a factor, or they simply installed their own panels.

While prices are falling to levels competitive with traditional energy sources, monetary hurdles to solar -- perceived or real -- certainly persist. 

EnergySage’s analysis also assesses individual customers. And those customers don't mind paying a bit more for premium products.

Customers who were quoted through EnergySage's platform were 19.6 percent more likely to choose premium panels over the baseline type, and 59 percent were more likely to choose the even more expensive Premium+ panels. Homeowners with a direct financial stake in the performance of the system want better-quality products.

Consistent with past trends, residential solar customers also continue to heavily prefer ownership of their own system, with over 98 percent choosing to buy a system outright or using a loan over third-party financing such as leasing.

Although most installers only offer loans from a couple providers, there are now more regional lenders available on the market offering greater selection among loan providers. More installers are also offering a bevy of panel brands. Just 6 percent offered five or more options in 2014. Today, 19 percent offer five or more options.

So will community solar break through? According to GTM Research, community solar projects should account for up to a quarter of non-residential installs starting this year, with over 600 megawatts of installations projected by the end of 2021. 



from GTM Solar https://www.greentechmedia.com/articles/read/whats-holding-back-community-solar-investment-decisions

PURPA: A Quiet Death or Longer Life After 40 Years of Wholesale Electricity Competition?

In the first week of September, a U.S. House Energy and Commerce subcommittee held hearings questioning a 40-year-old law that forms the bedrock of competition in the electricity market.

Before the law took effect, electric utilities had a complete monopoly over electricity generation. In 1978, after some spectacular cost overruns by incumbent utilities, the passage of Public Utility Regulatory Policies Act (PURPA) introduced competition. 

Is a law passed in the era of shag carpeting and sideburns just as unfashionable in 2017?

If the list of testifiers was representative of utility customer interests, you might think so. But electricity markets are no less in need of competition in 2017 than they were in 1978. In fact, customers may pay a big price without it.

A bit of background

There’s much more in ILSR’s recent overview of PURPA, but the law’s basic concept is that utilities must buy power from renewable energy sources or “co-generation” facilities (that produce both electricity and heat for sale) if it’s competitive with their own supplies. Think of it as the utility planning to buy a burger and fries for $5.00 (this is their “avoided cost”). If someone else can offer the utility the same lunch for less, then PURPA requires they buy it, because it saves everyone money. 

PURPA was designed to avoid utility cost overruns, particularly at nuclear power plants, if they built too much at too big a scale. It targeted market opportunities for medium-scale power generation -- projects 80 megawatts or smaller (most full-scale power plants are 500 megawatts or more).  

PURPA still serves a purpose

In the 1990s, Congress passed additional legislation to open the transmission system, allowing non-utilities to build power plants and sell that power elsewhere. Further changes created regional “balancing” markets run by independent system operators that allow for even more robust competition. A map of existing operators is shown below.

In these more competitive regions, PURPA only applies to projects 20 megawatts and smaller, under the theory that larger developers have market access. Smaller projects still need PURPA because the overhead costs of entering the market are prohibitive for the smallest power generators. In either event, the competitive market or the limitations of PURPA (to buy only cost-competitive power) protects customers.

Addressing critiques of PURPA

There’s no question that 40-year-old laws should be measured against changing market conditions. But to hear utilities talk, competition itself has gone out of vogue. Of the several critiques levied at PURPA during the hearings, none undermined the fundamental advantage of the law: it requires utilities to procure cost-effective resources. 

One issue worth addressing is the habit of developers taking very large renewable energy projects and subdividing them to be eligible for PURPA contracts. For a 2016 wind project proposal in Idaho, for example, a “developer attempted to site 11 solar and eight wind facilities under the law, separating them so the combined 1,520 MW of capacity was portioned into chunks of 80 MW or less.”

Currently, a one-mile separation between projects is required for them to be distinct, according to the federal law. An Idaho state regulator asked the Congressional subcommittee for the ability to review “whether adjacent facilities truly constitute separate projects, looking at factors such as common ownership, interconnection points, operations, [and] financing.” 

This is important, because diversity of market participants is a key element of distributing the economic rewards of renewable energy development. It’s also important because the size limitations of PURPA (80 megawatts in states with vertically-integrated monopolies and 20 megawatts in states with competitive markets) is sufficient to capture most of the economies of scale in wind and solar production, as ILSR reported in 2016.

The following chart shows the economies of scale in solar energy generation, with projects near 20 megawatts hitting a sweet spot between the cost of project construction and the cost of transmission access (the latter is key for the largest projects).

In wind power, economies of scale don’t reverse at large size, but they certainly shrink, with the largest projects only 10-15 percent cheaper per kilowatt-hour. 

In other words, ensuring that “qualifying facilities” under PURPA stay within size limits seems entirely reasonable.

An overlooked opportunity to improve PURPA

Testifiers in the subcommittee hearing also noted that splitting up projects could allow them to interconnect on the lower-voltage distribution lines serving communities, rather than the high-powered ones used for long-distance transmission. Instead of treating this as a problem, Congress, the Federal Energy Regulatory Commission, and state regulators should look at the opportunity. 

First, when projects interconnect on the distribution system, they may be able to avoid the cost of new transmission infrastructure as well as utilize existing capacity on the distribution system to provide local power for local loads. With its focus on wholesale power, PURPA -- as implemented today -- has sidestepped the opportunity to allow for competition closer to the retail level.

This issue has come up recently in Minnesota, where a developer proposed a 5-megawatt “wind-solar hybrid” with two wind turbines and a solar array, which can plug into open capacity near a utility substation (the connection point between the transmission and distribution systems).

The project would struggle to compete on price with a several-hundred-megawatt wind project, but it offers some unique values. One is that it avoids transmission costs, as shown in the graphic below (and in the slideshow version of this post).

A second advantage is that the power provided from a wind-solar hybrid (or even from a solar project versus a wind project) may uniquely benefit utility customers by providing more power during times of peak energy use. In Minnesota, these relative advantages are measured for rooftop solar through a “value of solar” methodology.

Federal lawmakers and regulators, as well as state public utility commissions, should start asking what components of the avoided cost calculation may be missing from the existing calculus, and how they may offer further customer savings by favoring projects with particular characteristics. Storage, for example, could be another valuable element that provides peak power or grid support services.

Fair contract terms

While location and peak capacity are key components of any methodology for calculating avoided cost (the lunch price, if you will), the other central element is contract term. A PURPA rule re-write in Michigan recently concluded that contract terms less than 15 years are inadequate, because projects simply cannot secure financing and come to market with short contracts.

The Idaho commissioner testifying at the House hearing knows this full well, since that state responded to an upswell in developer interest not by addressing the issue of project splitting, but instead by shortening PURPA contracts to just two years (from 20). The move choked off development. If the only tool state commissions have is a hammer (contract length), then all the problems (fair pricing, project size, project interconnection point) will look like nails.

Wrap: Improve PURPA, don’t kill competition

The House hearing echoed complaints from utilities in several states that share one common feature: lots of recent renewable energy development due to high utility avoided costs.

North Carolina, for example, saw over 2,000 megawatts of solar development when Duke Energy had high-cost power and the state enforced a long-term purchase contract. But the explosion of solar meant a better priced “meal” for the state’s electricity customers, much like Xcel Energy CEO keeps saying how wind power is the cheapest electricity resource in many parts of the country.

It’s crucial to understand that utilities are not disinterested parties to this discussion. Particularly in regulated markets -- like Idaho and North Carolina -- the dominant investor-owned utilities make money for their shareholders by building power plants, paid for by captive customers. PURPA is one of the few tools state regulators have to ensure that monopoly incumbents provide the best deal for their state’s residents and businesses.

Congress should certainly look for ways to ensure diversity among market participants and that PURPA isn’t an end-around for savvy developers who should be participating in competitive markets. But states already have the power to protect fairness in PURPA contract terms and avoided costs. There’s no reason to roll back competition when clean energy can provide utility customers a better deal.

***

John Farrell directs the Energy Democracy Initiative at the Institute for Local Self-Reliance.



from GTM Solar https://www.greentechmedia.com/articles/read/a-quiet-death-or-longer-life-after-40-years-of-wholesale-electricity-compet

Friday, September 15, 2017

California’s Plan for 100% Renewables Falls Flat in the 11th Hour

California’s pitch for 100 percent renewable energy is dead -- for now.

In the last week of its legislative session, California bills that laid out plans for a 100 percent renewable grid by 2045 and a remake of the state’s grid into a regional system floundered.

Legislators’ failure to move the bills through could add fuel to the larger 100 percent renewable energy debate, in which a variety of stakeholders have questioned the speed, pathway, feasibility and, ultimately, the need for converting to 100 percent. The struggle begs the question: if California can’t make 100 percent a reality, can other large economies?

The downfall of California’s 100 percent bill, SB 100, came shortly after unions representing about 120,000 electric and utility workers, who had previously supported the bill, turned their backs on the legislation amid worries over job loss and grid security.  

“There’s a lot in all the bills that we like,” said Tom Dalzell, business manager at the International Brotherhood of Electrical Workers Local 1245, based outside of Sacramento. “Our interest was protecting the distribution system and the jobs of our members that work on the distribution system.”

Before the Brotherhood came out against the bill, California lawmakers had already shifted the initiative from 100 percent renewables to a "100 percent greenhouse-gas-free" energy goal, with a mandate to reach a lower 60 percent renewables target instead. Even with the added flexibility, SB 100 failed to advance and has been tabled until next year. 

Among the bills that slipped through the cracks this session was a proposal from Assembly Member Chris Holden to revamp California’s grid by regionalizing the authority of the California Independent System Operator (CAISO). The proposal, introduced just last week, was meant to allow California to more easily coordinate transfers of renewable energy across state lines in the West when the state has excess supply or not enough.

Groups like Dalzell’s worry that changes to the grid could mean fewer jobs. Many groups, like the Sierra Club and the Utility Reform Network, also joined unions in expressing concern that regionalizing CAISO would loosen California’s grip on its grid. Environmentalists were especially concerned that it may allow other states to send coal and natural-gas fired power to the state. Governor Jerry Brown supported Holden’s plan.

The complications that brought down the 100 percent bill in the eleventh hour are demonstrative of larger questions swirling around the possibility of a fully renewable energy scenario.

Many cities have already committed to all renewables. Hawaii has approved the same goal California was considering -- 100 renewables by 2045 -- and has plans to get there early. But the state consumes much less energy and has a smaller footprint.

In May, questions about how an economy as large as the entire United States can get to 100 percent renewables became the source of an unusually heated academic debate when colleagues called out the research of Mark Jacobson, a Stanford professor who argued that reaching full renewables is entirely feasible with a World War II-style mobilization of mostly wind and solar. 

“Policy makers should treat with caution any visions of a rapid, reliable, and low-cost transition to entire energy systems that relies almost exclusively on wind, solar, and hydroelectric power,” wrote the authors of a paper rebutting Jacobson’s findings.  

The academic debate broke out as state Senate President Pro Tem Kevin de León sought to advance SB 100, making a big splash over California’s renewable ambitions.

For now, the debate over 100 percent renewable energy wages on. And though the delay on the energy bills does look like a setback, environmentalists say they’re not fretting. “We’re going to be back next year,” said Peter Miller, Western Energy Project Director at the Natural Resources Defense Council. 

“I don’t want to underestimate the challenges to moving to a fully zero carbon grid, but we can get there, and we will," he said. "It’s going to take some time.”

Back in California’s capital, it wasn’t all letdowns for greens in the last week of the session. On Thursday, the legislature did pass Assembly Bill 797, an extension on incentives for solar thermal technologies that have offset 31,000 metric tons of carbon dioxide a year. That bill now heads to Governor Brown’s desk.



from GTM Solar https://www.greentechmedia.com/articles/read/california-100-percent-renewables-falls-flat