Контрольная работа по английскому языку на тему «Solar And Wind Power Could Ignite A Hydrogen Energy Comeback»

Hydrogen is flowing in pipes under the streets in Cappelle-la-Grande, helping to energize 100 homes in this northern France village. On a short side road adjacent to the town center, a new electrolyzer machine inside a small metal shed zaps water with electricity from wind and solar farms to create “renewable” hydrogen that is fed into the natural gas stream already flowing in the pipes. By displacing some of that fossil fuel, the hydrogen trims carbon emissions from the community’s furnaces, hot-water heaters and stove tops by up to 7 percent. Cappelle-la-Grande’s system is a living laboratory created by Paris-based energy firm Engie. The company foresees a big scale-up of hydrogen energy as the cost of electrolyzers, as well as of renewable electricity, continues to fall. If Engie is right, blending hydrogen into local gas grids could accelerate a transition from fossil to clean energy. The company is not alone. Renewable hydrogen is central to the European Commission’s vision for achieving net-zero carbon emissions by 2050. It is also a growing focus for the continent’s industrial giants. As of next year, all new turbines for power plants made in the European Union are supposed to ship ready to burn a hydrogen–natural gas blend, and the E.U.’s manufacturers claim the turbines will be certified for 100 percent hydrogen by 2030. European steelmakers, meanwhile, are experimenting with renewable hydrogen as a substitute fuel for coal in their furnaces. If powering economies with renewable hydrogen sounds familiar, it is. Nearly a century ago celebrated British geneticist and mathematician J.B.S. Haldane predicted a post-fossil-fuel era driven by “great power stations” pumping out hydrogen. The vision became a fascination at the dawn of this century. In 2002 futurist Jeremy Rifkin’s book The Hydrogen Economy prophesied that the gas would catalyze a new industrial revolution. Solar and wind energy would split a limitless resource—water—to create hydrogen for electricity, heating and industrial power, with benign oxygen as the by-product. President George W. Bush, in his 2003 State of the Union address, launched a $1.2-billion research juggernaut to make fuel-cell vehicles running on hydrogen commonplace within a generation. Fuel cells in garages could be used as backup sources to power homes, too. A few months later Wired magazine published an article entitled “How Hydrogen Can Save America” by breaking dependence on dirty imported petroleum. Immediate progress did not live up to the hype. Less expensive and rapidly improving battery-powered vehicles stole the “green car” spotlight. In 2009 the Obama administration put hydrogen work on the back burner. Obama’s first secretary of energy, physicist and Nobel laureate Steven Chu, explained that hydrogen technology simply was not ready, and fuel cells and electrolyzers might never be cost-effective. Research did not stop, however, and even Chu now acknowledges that some hurdles are gradually being cleared. The Cappelle-la-Grande demonstration is one small project, but dozens of increasingly large, ambitious installations are getting started worldwide, especially in Europe. As the International Energy Agency noted in a recent report, “hydrogen is currently enjoying unprecedented political and business momentum, with the number of policies and projects around the world expanding rapidly.” This time around it is the push to decarbonize the electric grid and heavy industry—not transportation—that is driving interest in hydrogen. “Everyone in the energy-modeling community is thinking very seriously about deep decarbonization,” says Tom Brown, who leads an energy-system modeling group at Germany’s Karlsruhe Institute of Technology. Cities, states and nations are charting paths to reach nearly net-zero carbon emissions by 2050 or sooner, in large part by adopting low-carbon wind and solar electricity. But there are two, often unspoken problems with that strategy. First, existing electric grids do not have enough capacity to handle the large amounts of renewable energy needed to put fossil-fueled power plants out of business. Second, backup power plants would still be needed for long stretches of dark or windless weather. Today that backup comes from natural gas, coal and nuclear power plants that grid operators can readily turn up and down to balance sagging and surging renewable supply. Hydrogen can play the same role, its promoters say. When wind and solar are abundant, electrolyzers can use some of that energy to create hydrogen, which is stored for the literal rainy day. Fuel cells or turbines would then convert the stored hydrogen back into electricity to shore up the grid. Cutting carbon deeply also means finding replacement fuels for segments of the economy that cannot simply plug into a big electrical outlet, such as heavy transport, as well as replacement feedstocks for chemicals and materials that are now based on petroleum, coal and natural gas. “Far too many people have been misled into believing that electrification is the entire [carbon] solution” that is needed, says Jack Brouwer, an energy expert at the University of California, Irvine, who has been engineering solutions to his region’s dirty air for more than two decades. “And many of our state agencies and legislators have bought in,” without considering how to solve energy storage or to fuel industry, he says. Can renewable hydrogen make a clean-energy grid workable? And could it be a viable option for industry? Some interesting bets are being made, even without knowing whether hydrogen can scale up quickly and affordably. The few nations that have bet big on replacing coal and natural gas with solar and wind are already showing signs of strain. Renewable energy provided about 40 percent of Germany’s electricity in 2018, though with huge fluctuation. During certain days, wind and solar generated more than 75 percent of the country’s power; on other days, the share dropped to 15 percent. Grid operators manage such peaks and valleys by adjusting the output from fossil-fuel and nuclear power plants, hydropower reservoirs and big batteries. Wind and solar also increasingly surge beyond what Germany’s congested transmission lines can take, forcing grid operators to turn off some renewable generators, losing out on 1.4 billion euros ($1.5 billion) of energy in 2017 alone. The bigger issue going forward is how nations will cope after the planned phaseout of fossil-fueled power plants (and, in Germany, also their nuclear plants). How will grid operators keep the lights on during dark and windless periods? Energy modelers in Germany invented a term for such renewable energy droughts: dunkelflauten, or “dark doldrums.” Weather studies indicate that power grids in the U.S. and Germany would have to compensate for dunkelflauten lasting as long as two weeks. Beefier transmission grids could help combat dunkelflauten by moving electricity across large regions or even continents, sending gobs of power from areas with high winds or bright sun on a given day to distant places that are calm or cloudy. But grid expansion is a slog. Across Germany, adding power lines is years behind schedule, beset by community protests. In the U.S., similar opposition prevents new lines from gaining approval. To some experts, therefore, dunkelflauten make wind and solar energy look risky. For example, grid simulations done in 2018 by energy modelers at the Massachusetts Institute of Technology project an exponential rise in costs as grids move toward 100 percent renewable energy. That is because they assumed big, expensive batteries would have to be installed and kept charged at all times, even though they might be used only for a few scarce days or even hours a year. A California-based team of academics reached a similar conclusion in 2018, finding that even with big transmission lines and batteries, solar and wind power could feasibly supply only about 80 percent of U.S. electricity needs. Other power sources will definitely be needed, said team member Ken Caldeira, a climate scientist at the Carnegie Institution for Science, when the study was released. Certain European experts say the M.I.T. and California studies are too myopic. For several decades European researchers have been zooming out from the power grid to a larger view, considering the full spectrum of energy used in modern society. Pioneered by Roskilde University physicist Bent Sørensen and several Danish protégés, such “integrated energy systems” studies combine simulations for electric grids, natural gas and hydrogen distribution networks, transportation systems, heavy industries and central heating supply. The models show that coupling those sectors provides operational flexibility, and hydrogen is a powerful way to do that. In this view, a 100 percent renewable electric grid could succeed if hydrogen is used to store energy to cover the dunkelflauten and without the price jump seen in M.I.T.’s projections. Some U.S. grid studies ruled out hydrogen energy storage because it is costly today. But other modelers say that thinking is flawed. For example, many grid studies being published about a decade ago downplayed solar energy because it was expensive at the time—this was a mistaken assumption, given solar’s dramatic cost decreases ever since. European simulations such as Brown’s take into account anticipated cost reductions when they compute the cheapest ways to eliminate carbon emissions. What emerges is a buildout of electrolyzers that cuts the cost of renewable hydrogen. In the models, electrolyzers scale up first to replace hydrogen that is manufactured from natural gas, used by chemical plants and oil refineries in various processing steps. Manufacturing “gray” hydrogen (as energy experts call it) releases more than 800 million metric tons of carbon dioxide a year worldwide—as much as the U.K. and Indonesia’s total emissions combined, according to the International Energy Agency. Replacing gray hydrogen with renewable hydrogen shrinks the carbon footprint of hydrogen used by industry. Some hydrogen could also replace natural gas and diesel fuel consumed by heavy trucks, buses and trains. Although fuel cells struggle to compete with batteries for cars, they may be more practical for heavier vehicles; truck developer Nikola Motor Company says the tractor-trailer rigs it is commercializing will travel about 800 to 1,200 kilometers (500 to 750 miles) on a full fuel cell, depending on the various equipment and hauling factors. If industry and heavy transport embrace renewable hydrogen, regional hydrogen networks could emerge to distribute it, and they could also supply the carbon-free gas to power plants that back up electricity grids. That is what happens in integrated energy simulations: as more renewable hydrogen is created and consumed, mass-distribution networks develop that store months’ worth of the gas in large tanks or underground caverns, much as natural gas is stored today, at a cost that is cheaper than storing electricity in batteries. “Once you acknowledge that hydrogen is important for the other sectors, you get the long-term storage for the power sector as a sort of by-product,” Brown says. That perspective comes alive in simulations by Christian Breyer of Finland’s LUT University. In his team’s latest 100 percent renewable energy scenarios, published in 2019 with the Energy Watch Group, an international group of scientists and parliamentarians, power plants burning stored hydrogen fire up to fill the grid’s void during the deepest dunkelflauten. “They are a final resort,” Breyer says. “Without these large turbines, we would not have a stable energy system during certain hours of the year.” In Breyer’s model, less than half of the wind and solar energy required to make and store hydrogen gets converted back into electricity, a big loss, and the hydrogen turbine generators sit idle for all but a few weeks every year. But the poor efficiency of the hydrogen-to-electricity conversion does not break the bank, because this pathway is used infrequently. Breyer says the scheme is the most economical solution for the energy system writ large, and it is not that different from how many grids use natural gas–fired plants today.

Effort to Trade Gas for Hydropower in Northeast Meets Resistance

Some residents are concerned about environmental impacts from proposed transmission lines. Elizabeth Caruso is a town official in Caratunk, Maine, a community of 70 people about an hour’s drive south of the Canadian border. Like many people in this part of rural New England, her livelihood is tied to tourism. That’s why she’s leading the opposition to a 145-mile transmission line that would cut a 150-foot-wide path through the forest around Caratunk. She worries the proposal would splinter the Maine woods and the businesses that rely on it. She and her husband run a guiding business. In the summers, they take clients fishing on the ponds dotting the region and ferry hikers on the Appalachian Trail across the Kennebec River. Fall brings hunters, and snowmobilers make the pilgrimage to Coburn Mountain in the winter. A power line would change that, she said. The so-called New England Clean Energy Connect, or NECEC, would link Hydro-Québec in the north to energy-hungry Massachusetts in the south, supplying nearly a fifth of the Bay State’s annual electricity consumption with low-carbon power. The project stems from a 2016 Massachusetts law aiming to slash the state’s emissions by requiring utilities to purchase large amounts of low-carbon energy. Like many in this part of Maine, Caruso is skeptical of the project’s purported climate benefits. She believes Massachusetts selected Hydro-Québec’s proposal for political reasons and noted the utility has refused to submit to cross-examination during regulatory proceedings underway in Massachusetts and Maine. In her mind, the region would be better served by supporting local solar projects. “No one is saying we don’t want clean energy, and no one is saying we just don’t want this in our backyard,” Caruso said. She is hardly alone. Massachusetts’ attempt to import more Canadian hydropower has been blocked by environmental groups, energy companies and communities opposed to the transmission lines linking the state to Quebec. The New England Clean Energy Connect is only now under consideration because a project through New Hampshire was rejected by regulators there. The debate around transmission lines often revolves around the impact on scenic landscapes, wildlife concerns and the potential disruption to the wholesale electricity market that unites the six New England states. But it also hints at the larger question of whether imports of Canadian hydropower are needed to decarbonize the region’s electric grid. Massachusetts Gov. Charlie Baker has argued the hydropower will help supplant the natural gas generation that today accounts for 50% of New England’s electricity generation, building the foundation for a low-carbon electric grid and easing concerns over wintertime grid reliability, when the region’s limited natural gas pipelines must serve power plants and heating demand. But Baker has felt pushback from Attorney General Maura Healey, who argues that the proposed contracts between Hydro-Québec and the state’s three electric distribution utilities lack the guarantees to ensure the Canadian utility increases its imports, effectively forcing Massachusetts consumers to pay for electricity that does not decrease emissions. It is a similar story farther north in Maine, where the proposed transmission project has produced a fissure between Gov. Janet Mills and Democratic lawmakers who control the Legislature. Mills maintains that the new line will cut emissions, lower electricity bills and create jobs. Democratic lawmakers worry the project will exact a heavy environmental toll and hamper renewable development, all while failing to deliver the promised carbon reductions. They have been joined by environmental groups like the Sierra Club and Natural Resources Council of Maine, which warn that Hydro-Québec could backfill its domestic consumption with imported fossil fuel generation while selling more exports to New England. That could prompt overall emissions to rise. “We’re talking about investing billions of dollars in infrastructure that can cause significant environmental damage without the climate benefit,” said Sue Ely, an attorney at the Natural Resources Council of Maine. Of the utility’s promised carbon reductions, she said, “We should be skeptical, and we should ask for proof.” Others dismiss those arguments, saying the possibility of an emissions spike is greatly exaggerated. Imported fossil fuels accounted for 0.04% of Hydro-Québec’s power supply in 2017, and any increase of fossil fuels from neighboring markets would be subject to a financial penalty given Quebec’s participation in California’s cap-and-trade system, they say. Hydro-Québec also has significant financial incentives to sell as much electricity as it can to the Northeast, which pays some of the highest electricity rates in the United States. Before they approved the transmission line last month, Maine utility regulators wrote that the Canadian utility, “as a rational economic actor, will seek to maximize profits, and therefore will use whatever water it has available to generate energy for the NECEC rather than using the NECEC to divert energy from existing markets in New England.” New transmission lines were built to carry electricity away from four dams on the Romaine River in northeast Quebec. The outlines of a similar debate are forming in New York City. Mayor Bill de Blasio announced last month the city was entering negotiations with Hydro-Québec to supply 1,000 megawatts of electricity to a 330-mile transmission line linking Queens with Quebec. City officials frame the move as part of a wider attempt to quickly decarbonize America’s largest metropolis, displacing the fossil fuel generation that now provides 70% of the city’s power. That figure could grow after Indian Point Energy Center, a 2,144-MW nuclear plant outside the city, closes in 2021. “Hydropower, we believe, can be delivered into the city in the next five years,” said Mark Chambers, who leads the mayor’s Office of Sustainability. “Offshore wind is eight years out. We’re going to need that power, too. The faster we reduce our emissions, the better the outcomes are.” Yet the proposal is starting to garner pushback from New York energy producers. Upstate New York has large potential for wind and existing hydro and nuclear generation. But transmission constraints around the city means there is little prospect for getting it there. A new transmission line filled with hydropower imports from Quebec only exacerbates the problem, said Gavin Donohue, president and CEO of the Independent Power Producers of New York Inc., a trade group representing power plant owners. “You’re further inhibiting the in-state renewable developers and hindering their ability to compete,” Donohue said. The tension over Canadian hydropower highlights the difficult decisions facing the Northeast as states look to decarbonize, climate analysts say. There is little prospect of replacing Indian Point or the retiring 690-MW Pilgrim Nuclear Power Station south of Boston with new nuclear facilities. Carbon capture and sequestration at gas plants isn’t even a possibility in New England, which lacks the geologic formations needed to store carbon underground. And utility-scale renewable generation faces a series of constraints, including a lack of transmission, scarce open space and, in the case of solar, the region’s northern climate. The Northeast is pinning much of its hope on offshore wind. The industry shows significant promise, but there are limits to what it can provide. Current state targets for offshore wind construction in New England and New York represent roughly 16% and 20% of installed power plant capacity in each region, respectively. At the same time, more low-carbon electricity is likely required. Transportation and buildings are the largest and second-largest sources of greenhouse gas emissions in the Northeast today. Most climate experts believe widespread electrification will be needed in both sectors to make meaningful carbon reductions in line with the region’s climate targets. The National Renewable Energy Laboratory estimates electricity demand in New York and New England could increase by as much as 71% and 67%, respectively, in 2050 if widespread electrification takes hold. That projection does not account for energy efficiency measures and assumes only moderate technological advancements, but it does underline the challenge facing Northeastern climate hawks as they search for more low-carbon electrons. “From where I sit it’s hard to see a reason to take Canadian hydro off the table, given the relatively small set of options available,” said John Larsen, a former Obama administration official who leads power sector research at the Rhodium Group, an economic consulting firm. “It doesn’t mean hydro is a silver bullet or an answer to everyone’s prayers. That said, it has unique attributes that make it useful in a low-carbon bulk power system.” Hydro-Québec has long been a major energy supplier to the Northeast. In 2018, it exported almost 17 terawatt-hours of electricity to New England, about 14% of the region’s annual power consumption, and 8.6 TWh to New York. Northeastern states have increasingly looked north in recent years, as they contemplated ways to green their power sectors. In many respects, the current push can be traced back to Massachusetts, where lawmakers passed a bill in 2016 requiring the state’s three electric distribution utilities to buy 1,200 MW of low-carbon power, which could come from some combination of hydro, wind and solar. State regulators received 46 bid packages to supply the contract. They ultimately selected Hydro-Québec—twice. After New Hampshire regulators rejected a proposal to build a transmission line through the state, Massachusetts officials selected the Canadian power company’s second bid: a $950 million power line to be built through Maine with a subsidiary of Avangrid Inc., Central Maine Power. The contracts call on Hydro-Québec to deliver 9.45 TWh annually for 20 years. In theory, that should represent a substantial boost in hydropower imports to New England. But critics say a closer look at the proposed contracts between Hydro-Québec and Eversource Energy, National Grid PLC and Unitil Corp.—the three Massachusetts utilities—shows that the opposite is possible. Hydro-Québec would pay penalties if its imports fell below a historic baseline. The problem is the baseline was set so low that the utility could sell less energy to New England and still satisfy its contractual obligations to Massachusetts, said Dean Murphy, an analyst at the Brattle Group who testified as an expert witness on behalf of the Massachusetts attorney general in regulatory proceedings before the state’s Department of Public Utilities. That would contradict the purpose of Massachusetts’ 2016 legislation, which sought to foster clean energy development, Murphy said. He argued for increasing the baselines to ensure the state gets what it pays for. “The proposed contracts,” he said in testimony to the DPU, “would allow most (and potentially all) of the contract energy delivered to substitute for historical deliveries.” The DPU is expected to rule on Hydro-Québec’s contracts later this year. Officials at the Canadian power company dismiss those arguments, arguing it has a significant financial investment to boost its exports to the Northeast. In recent years, it added 5,000 MW of new power generation in an attempt to enhance its export capacity. And the utility is attempting to free up more electricity for export through a series of energy efficiency initiatives. It estimates energy efficiency measures have already saved 9 TWh in recent years, or roughly the amount it has proposed selling to Massachusetts. It argues the main constraint to additional exports to the Northeast is new transmission lines. “We want to sell more energy into one of our best markets, and which one is that? It’s New England,” said Gary Sutherland, a company spokesman. “Today New England is already about half of our sales.” But in a series of interviews with E&E News, Hydro-Québec officials declined to answer questions about how much power the utility expects to export to the United States if the new transmission lines are built, ultimately saying its projections are confidential. Such answers have provoked unease, even among those who believe more Canadian hydro is needed to help meet the region’s climate goals. The Acadia Center is one of several environmental groups that have advocated for injecting more electricity from Hydro-Québec’s existing dams into the Northeast’s power grid. In Maine, the group even offered qualified support of the New England Clean Energy Connect. At the same time, the Acadia Center has argued that Massachusetts regulators should amend Hydro-Québec’s contracts with the state’s power companies, echoing the concerns of the attorney general and arguing for better tracking that would enable Massachusetts to verify that the energy is coming from the utility’s dams. “The combination of this sort of lax contract language around the baseline in combination with lack of actual tracking that every other eligible bidder to this contract would have had to undergo, it’s just not a level playing field,” said Deborah Donovan, Massachusetts director at the Acadia Center. She added: “We don’t have 20 years to miss the boat here. We literally do not.”

New technologies and cheaper costs are needed to reach the 100 percent goal for Hawaii and California California Democratic leaders want their state to commit to a future of 100 percent renewable electricity, a goal approved so far by only one U.S. state—Hawaii. Top officials in both places hope their policies will serve as a model for others as the Trump administration rejects actions on climate change. California and Hawaii offer very different models for committing their power sectors to clean electricity. They differ on everything from mandate deadlines to what’s considered renewable. «For the country as a whole it shows the laboratory effect of having states take the lead on this issue,» said Ethan Elkind, director of the climate program at the University of California, Berkeley, Center for Law, Energy & the Environment. «As Hawaii and California take the lead, it will provide examples of how it can be done for other states, both good and bad.» Hawaii passed its 100 percent renewable electricity mandate with a 2045 target two years ago. The Aloha State at the time had no blueprint for how to make it happen. Much of it remains in the planning stage, though leaders argue it’s achievable. «We are ahead of schedule on our path to 100 percent renewable energy goal,» Hawaii Gov. David Ige said at a clean energy summit this summer. «We are making significant progress toward getting off of fossil fuel and into clean energy, more aggressively than any other community in the United States.» In California, legislation offered by state Senate President Pro Tempore Kevin de León provides a two-tiered approach to hitting the 100 percent mark. S.B. 100 mandates that utilities make 60 percent of their energy from renewables by 2030. The remaining 40 percent of power falls under a «zero-carbon» requirement, with a deadline in 2045. Electricity sellers could meet the mandate with large-scale hydroelectric power, which isn’t allowed under the renewable portfolio standard rule. It also allows room for future technologies, supporters said. «We do 100 percent clean energy, we do it right, we quantify positive results,» de León said in a recent call with reporters. «This is a very wonderful opportunity that we have, to send a very clear message to Washington that with or without their help, California will continue to lead on this critical issue. «It’s an ambitious goal; there’s no doubt about that,» he added. «I want to be very clear, it’s also achievable. It’s within reach.» De León recently traveled to Hawaii, where he met with Ige and others. Hawaii and California define renewable power differently. California under S.B. 100 for its RPS allows solar; wind; geothermal; biomass; small hydropower; renewable gas such as biomethane; and wave, ocean current and waste conversion technologies, though none is commercially available. Retail electricity sellers can buy a small number of renewable energy credits tied to rooftop solar systems. That number is limited to 10 percent of their compliance obligation. Electricity generated by rooftop solar helps utilities indirectly by reducing the amount of electricity—potentially fossil-fuel-generated—that those companies have to make. Hawaii allows a slew of technologies to count as renewable: solar, wind, hydroelectric, biofuels and geothermal. It also includes biomass crops, agricultural and animal residues and wastes, and municipal solid waste; biogas, including landfill and sewage-based digester gas; ocean water, currents and waves; and hydrogen produced from renewable energy sources. Additionally, it allows part of a sector known as combined heat and power. A commercial business can use a generator—powered by a mixture of liquefied natural gas and synthetic natural gas—to make electricity, for example. The affiliated utility can count the on-site heat the system produces as renewable, said Henry Curtis, executive director and vice president at Life of the Land, an environmental and social justice activist group. Residential rooftop photovoltaic output also is counted in the RPS. The energy is added to the amount of green power utilities say they generate, and the generation amount gets subtracted from the total electricity sales utilities report. That means the RPS isn’t actually 100 percent, Curtis said, as a utility theoretically could claim more than 100 percent. «It’s absolutely inaccurate to say that Hawaii has a 100 percent RPS law,» Curtis said. «It’s simply a statement that you can throw out to say in the international press.» There are bills in the Hawaii Legislature «to close that loophole,» Moriwake said. Curtis, however, said that so far, there hasn’t been any push to pass one of the measures. Hawaii’s PUC in approving energy systems has said it doesn’t need to look at greenhouse gas emissions, Curtis said. He said there is a proposal on the Big Island to create biomass that would burn eucalyptus trees. Life of the Land is looking for a lawmaker to carry a measure that would require state agencies to track and seek reductions in greenhouse gas emissions. Hawaii’s Legislature will return to session in January. California, in contrast, must meet its strict greenhouse gas emissions goals at the same time as it’s seeking to ramp up green power production. Under S.B. 100, zero-carbon electricity sources cannot increase carbon emissions anywhere on the Western grid. Robert Harris, spokesman for the Alliance for Solar Choice, an advocacy group with Sunrun Inc. and others, said market forces eventually will push all states toward 100 percent renewables «or close to it.» «Solar and wind are the cheapest sources today,» Harris said. He noted that Texas, a politically conservative state, gets a large share of its electricity from wind because it’s less expensive. On one day last November, wind served more than 46 percent of the load and averaged 41 percent throughout the day in Texas. However, natural gas made up 48 percent and coal 28 percent of the Lone Star State’s electricity production in 2015, according to the Electric Reliability Council of Texas, which operates the electric grid for most of the state. Currently, 1 in 3 single-family homes in Hawaii has solar power, and «you can expect that to increase as the price drops,» Harris said. Energy storage prices also are falling. Sunrun has offered solar, plus storage leases, on the Big Island starting at 19 cents per kilowatt-hour, versus utility rates of 32 cents per kWh, Harris said. «The energy future everyone has talked about is going to be happening in Hawaii in real time, and hopefully is going to become an example for the rest of the world, what can happen if you allow it to happen,» Harris said. Right now, there’s a push to get as much utility-scale solar and wind online as possible while federal tax credits remain in place. Hawaiian Electric Co. has requested proposals for projects from renewable companies and landowners. Meanwhile, Hawaiian Electric has submitted a grid modernization plan to the state PUC. It proposes adding the cost of upgrading the grid to electricity rates. California’s Legislature is expected to shortly take up S.B. 100. The Senate Appropriations Committee recently passed the measure and sent it to the chamber floor. California’s largest utilities already are slated to generate enough renewable power to get close to meeting the state’s current mandate of 50 percent from renewables by 2030. San Diego Gas & Electric Co. has contracts that should hit 45.2 percent from renewables by 2020. In that same year, Pacific Gas & Electric Co. could reach 43 percent green power, and Southern California Edison is expected to hit 41.4 percent. S.B. 100, if passed, would apply to three large investor-owned utilities, municipally owned providers, and community choice aggregation (CCA) programs, groups that receive electricity procured by local governments and delivered by the incumbent utilities. The measure is considered relatively noncontroversial, but that could change easily. The bill is expected to move forward, given that its sponsor, de León, controls the Senate. That means legislators likely will try to add amendments, according to observers, though it’s not clear if de León will allow any on the floor. Some want the measure to open California’s grid to other users, so Western states could take California’s excess solar energy and the Golden State could import wind or other renewables from Wyoming, Iowa or other states. That could help build support for renewables in politically conservative states, Elkind said, while spreading the environmental and economic benefits. There’s some resistance to that idea, since it would invite oversight from the Federal Energy Regulatory Commission. However, Laura Wisland, a senior energy analyst at the Union of Concerned Scientists, said it’s «really an up-or-down decision» for FERC and that the agency would be unlikely to meddle with the marketplace. «We want to make sure that what we’re getting is replacement of existing gas-fired energy by renewables, and efficiency, and demand response, and battery storage,» said Kathryn Phillips, director of Sierra Club California.