Planning August/September 2014
Sunny Side Up
Solar power comes into its own.
By Allen Best
The solar industry is kicking butt, to use a nontechnical phrase. Rooftop solar? Rapidly rising. Utility-scale solar installations? More capacity will come on line this year than the total capacity developed through 2012.
Most startling, photovoltaic panels are being erected in some places without state mandates or incentives. And in certain times and places, solar stands on its own two feet in cost.
It's still on the fringe, though. Solar last year was responsible for just 0.23 percent of total electrical production in the U.S. However, in the first three months of this year, solar delivered 74 percent of new power production, more than both wind and natural gas.
Some of this growth occurred in Telluride, Colorado, where many people don't own their own rooftops. One-fifth of all the residents in this mountain town live in the municipality's deed-restricted affordable housing. David Johnson, manager of the 135-unit Shandoka neighborhood, says his third-floor unit gets just 90 minutes of sunshine on winter solstice.
Johnson's problem is not unusual. Structure, shading, or ownership issues leave only 22 to 27 percent of U.S. residential rooftops suitable for PV panels, according to a 2008 study by the U.S. Department of Energy's National Renewable Energy Laboratory.
Yet Johnson, like the tenants of all 215 of the deed-restricted affordable housing units in Telluride, has a solar panel credited to his apartment. It's located 80 miles west in the Paradox Valley where sunshine is ample and land is cheap.
Two years ago, 5,000 panels were installed on a seven-acre plot. Mindful of its vow to ratchet down its carbon footprint, Telluride bought the panels for $187,000. Telluride now has the nation's second-highest per capita ownership of PV solar, behind only Fresno, California.
Sharing
The concept is generically called shared renewable energy. The city of Ellensburg, Washington, claims credit for first implementing the concept in 2006, followed by the Sacramento Municipal Utility District. Now, according to the Solar Energy Industries Association, 17 states have adopted policies and programs to encourage growth of shared renewables, mostly solar arrays in communal locations.
Colorado's 2010 Community Solar Gardens Act requires at least 10 subscribers in an off-site solar array and specifies the mechanism of net metering. Net metering allows owners of solar panels to be credited for electricity they don't actually use. Colorado now has the largest number of the nation's 31 shared renewable projects, all of them solar arrays.
Clean Energy Collective, a private firm founded in 2010 near Aspen, Colorado, developed the 1.1-megawatt array in Paradox Valley. Tim Braun, a spokesman, explains that the company sees community-owned solar "as sort of a sweet spot in the middle" between massive, utility-scale solar projects that require large amounts of land and transmission and, on the other end, roof-top residential solar.
Braun notes that community solar can generate 10 to 20 percent more power than residential rooftop collectors. The facilities are sited for maximum power production and are professionally maintained to achieve maximum efficiency. And, with rooftop solar, the panels have much longer life than the roofs underneath them. These and other factors hasten the payback on investment. The firm has built or is now developing 40 community-owned solar arrays in eight states from Massachusetts to New Mexico.
Solar soars
Solar gardens are just one reason why solar energy finally seems to be coming into its own. To be clear, fossil fuels still pull the electrical cart in the U.S., with coal delivering 39 percent of electricity in 2013, according to the Energy Information Agency, followed by natural gas at 27 percent, and nuclear at 19 percent. Petroleum added another one percent.
Renewables provided 13 percent of generation. Of that, hydro — mostly from big dams built a half-century or more ago — was responsible for 52 percent, and wind 32 percent, with much of that capacity installed during the last decade. Solar came in at two percent of renewables, or 0.23 percent of total generation. It's little more than a rounding error in the bigger story.
But growth in solar has been robust. In its 2013 year-end report, U.S. Solar Market Insight — a publication of the Solar Energy Industries Association — said solar installations in the previous 18 months surpassed those of the previous 30 years. The market, added the report, "showed the first real glimpse of its path toward mainstream status." Industry members expected to install enough capacity to power three million homes in 2014.
California leads the nation in solar, with most sunny Southwestern states high in the rankings. But other states are on board. North Carolina last year was No. 3 in total added capacity, Massachusetts No. 4, New Jersey No. 5, Hawaii No. 6, Georgia No. 7, and New York No. 9.
State mandates explain part of this growth. Renewable portfolio standards have been set by 29 states and the District of Columbia, while eight more have voluntary goals. Some RPSs specify carve-outs for solar.
Prices have tumbled. Costs of solar PV panels dropped 80 percent between 2007 and 2012 before rising slightly. Prices for racks and inverters — which convert direct current to alternating current — have also declined, while labor has become more efficient. Total cost of residential solar last year dropped an average nine percent, according to U.S. Solar Market Insight, and 14 percent in utility-scale projects.
| Energy Sources and Percent Share of Total Electricity Generation (2013) | |
| COAL | 39% |
| NATURAL GAS | 27% |
| NUCLEAR | 19% |
| HYDROPOWER | 7% |
| OTHER RENEWABLE | 6% |
| BIOMASS | 1.48% |
| GEOTHERMAL | 0.41% |
| SOLAR | 0.23%; |
| WIND | 4.13% |
| PETROLEUM | 1% |
| OTHER GASES | <1% |
Source: EIA.gov
Deal making
Financing options also have improved. You can lease your roof to a third party, which collects the tax benefits. Both of you make money. The largest of such businesses, SolarCity, of San Mateo, California, operates in 14 states and in the last year completed the industry's first securitization of distributed solar energy assets.
The $54.43 million deal carries an interest rate of 4.8 percent, about half of its previous financing. This will, explained U.S. Solar Market Insight, "both lower the cost of capital and increase its availability — removing two of the primary historical barriers to growth in the residential sector."
New partnerships between solar companies and major retailers like Home Depot have also lowered upfront costs to consumers. More intriguing, Honda and SolarCity agreed to explore opportunities to integrate solar power and electric vehicle recharging.
Ivanpah is the biggest project of all. It's in California, 40 miles southwest of Las Vegas. Three spires rise from the floor of the Mojave Desert, each roughly 459 feet tall. Concentric circles of heliostatic mirrors spread across 4,000 acres, focusing sunlight on the receivers. As with a conventional coal plant, the receivers heat water to produce steam that is used to generate electricity.
When the sun is out, Ivanpah can generate 392 megawatts of energy, equaling a good-sized coal-fired power plant. But despite the absence of greenhouse gas emissions, the $2.2 billion project troubled many environmental advocates. It occupies habitat that is home to the threatened desert tortoise, and birds can be scorched or killed. Many other utility-scale solar projects have come on line in the Mojave Desert, and more are expected.
Smaller scale
Colorado's San Luis Valley has several smaller solar farms. The valley is a triangle 80 miles long and up to 30 miles wide, bordered by the San Juan and Sangre de Cristo mountain ranges. The valley's interior, around Alamosa, has 330 to 340 days a year with at least one hour of sunshine. Its elevation is around 7,000 feet, meaning more intense sunshine. And it tends toward coolness.
That actually benefits PV panels, explains Paul McMillan, managing director of utility sales for SunPower, a California-based developer and operator of utility-scale solar projects. Just as with solid-state electronics, intense heat can damage PV panels. "In many ways, the San Luis Valley is one of the more ideal places in the U.S. to do this," he says.
McMillan's company recently announced a new project, its third, in the San Luis Valley. This 50-megawatt project will require 120 acres of land. It represents what McMillan sees as an easier middle ground for utility-scale solar production. Few sites outside the Mojave Desert can accommodate 250- to 500-megawatt solar power plants. He predicts more projects of between 10 and 100 megawatts now that financing terms have improved.
"As we get better, with a proven track record, we can go to the financial community for investment," McMillan says.
The San Luis Valley comes up short in one key respect. Local power needs are limited, and transmission is difficult. Utilities were defeated by billionaire hedge-fund manager Louis Bacon when they attempted to build a high-voltage line across his scenic ranch on La Veta Pass to deliver power to Colorado's Front Range.
Unexpected benefits
Alamosa County likes the new solar plants. Four have been built, and three more, including SunPower's planned farm, have permits to build. Rachel Doyle, the county's deputy land-use administrator, explains that excess aquifer pumping has forced some farmers to stop planting, eroding the county's production of potatoes and other crops.
"You take a piece of property that for tax purposes isn't worth very much, and solar tremendously increases the value of that property," she says. And it doesn't use a lot of water. The only downside she sees is that solar delivers far fewer permanent jobs than agriculture.
About 120 miles away, near Pueblo, a different utility-scale solar project is planned next to the Comanche Generating Station power plants operated by Xcel Energy. The coal plants can produce 1,426 megawatts. The Comanche Solar project will deliver 120 megawatts, the largest array east of the Rocky Mountains, says Eric Blank, executive vice president and cofounder of Community Energy, the developer. He points to tracking technology, which shifts the panels to follow the sun, producing 15 percent more power than fixed-position panels. "It nicely matches the air conditioning loads," says Blank. "If you look at how buildings heat up in Colorado, their peak demands happen between 4 and 6 p.m. on the hottest summer days."
Forecast
For Xcel Energy, which has committed to buying power from the Comanche Solar project, these new plants in the San Luis Valley and near Pueblo represent the future. "We are adding large-scale solar that competes with and surpasses other forms of generation alternatives, in terms of price, over the life of the project," says David Eves, president and CEO of Public Service Company of Colorado, an Xcel subsidiary.
That's a remarkable statement given that Xcel in 2004 fought hard against a renewable energy mandate. Now, Xcel and many other utilities are skirmishing with solar and other renewable energy advocates over net metering. The debate is how much, if anything, rooftop solar and other distributed renewable providers should have to contribute to pay for distribution lines and other infrastructure costs.
In metropolitan Denver, Xcel is still absorbing rooftop solar. There the rooftop of an old airplane hangar at Lowry, a former air force based now converted into a housing development, is larger than a football field. Clean Energy Collective — the same developer that created the array near Telluride — has covered the roof of the 100,000-square-foot hangar with enough PV panels to produce 400 kilowatts.
The project was aided by a $2 million grant from the Denver Urban Renewal Authority. The power is delivered via Xcel-owned infrastructure, while the project's owners reap the rewards of net metering.
Site selection
Suburban Arvada (pop. 110,000) encourages solar through its participation in the Solar Friendly Communities program. Members seek to lower the hoop-jumping required of solar installers in residential applications. For example, will just one rooftop inspection suffice?
Figuring out sites for community-owned solar installations has been more difficult. Arvada's sustainability coordinator Jessica Prosser, AICP, says she originally imagined scattered half- and one-acre plots of city-owned land being used for solar gardens. But developers such as Clean Energy Collective want plots within 1,000 feet of transmission lines, will pay no more than $1,000 per acre per year, and want leases for at least 25 years.
"The city has many such plots of land for 10 years, but not 25," she says. Open spaces could fit those parameters, but some question whether solar collectors are appropriate in dedicated open lands.
One project that is going forward is just beyond the Arvada city limits, on the edge of the Rocky Mountain foothills. There, the Colorado Board of State Land Commissions has leased 15.2 acres (out of a potential 160 acres) for 20 years. The agency has a directive of managing state lands to produce "reasonable and consistent revenue over time," and the commissioners decided that the leases for three solar gardens deliver that, says Page Bolin, renewable energy program manager for the agency.
In this case, the revenue was more attractive than an outright sale of the land for residential development, she says. The land had previously been used for a sandstone mine, and location of the three solar gardens was designed to be compatible with potential resumption of mining.
With experience in Colorado Springs and now Adams County, performance, innovation, and sustainability manager Nick Kittle says community solar gardens don't fall neatly into existing zoning categories. "There are these internal regulatory issues that I think local governments aren't totally ready for," he says.
But he does see opportunities. For example, can space dedicated to a drainage ditch be shared with a solar garden? He sees room for creativity and a natural partnership between solar garden developers and local governments.
Potential
Individually, these solar gardens are tiny compared to giant coal-fired power plants. But some analysts foresee a tipping point. In a 2012 report, the National Renewable Energy Laboratory said this: "Renewable electricity generation from technologies that are commercially available today, in combination with a more flexible electric system, is more than adequate to supply 80 percent of total U.S. electricity generation in 2050 while meeting electricity demand on an hourly basis in every region of the country."
At the lab's campus in Golden, just west of Denver, a new building was recently opened that is designed to explore how to hit that target. NREL representatives talk as if it's a matter of when, not if, the pieces in this giant transformation to a low-carbon economy come together.
After working at NREL for 30 years, Brian Parsons recently left to become director of the Western Grid Group, which works to incorporate low-carbon technologies into the electric system. He sees high-voltage transmission as the key to integrating rising amounts of renewables from disparate places into the grid.
"Transmission is difficult and very complicated and often very contentious, but it's not particularly expensive in the grand scheme of things," Parsons says. The barriers, he adds, are more institutional than technological.
California and Texas provide interesting examples of innovation and change, he says. Unlike the rest of the nation, Texas remains on its own electric grid and has pushed market reforms, technical integration of renewables, and transmission planning, all to the benefit of renewables. California is now shooting for 33 percent integration of renewables, "and there is talk now about raising it to 50 percent," he says.
It sounds crazy, yes — but then a decade ago, 20 percent seemed like a distant frontier. Now, it's been done.
Allen Best is a freelance writer based in metropolitan Denver and the publisher of the e-zine Mountain Town News.
| When Water Is Your Friend |
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By Allen Best Ouray, Colorado, calls itself the Switzerland of America. Water flowing through the town is perfect for producing hydroelectric power. But when the town decided to add a new length of pipe to power a small turbine, former Mayor Bob Rich faced a daunting federal regulatory process. Rich, a retired teacher, wrote dozens of letters. Now Ouray generates enough electricity to power circulating pumps at the town's Hot Springs Pool. Hearing such stories, Congress last year amended federal laws that had required the Federal Energy Regulatory Commission to use a one-size-fits-all approach for everything from tiny, backyard generators to giant dams. Two laws were passed with bipartisan support. The Hydropower Regulatory Efficiency Act exempts dams of up to 10 megawatts from FERC licensing requirements, double the previous five megawatts. The law also relaxes regulations on tunnels, canals, pipelines, and other "manmade water conveyances" used to distribute water on projects of up to 40 megawatts. An Oak Ridge National Laboratory study found that 12,000 megawatts of potential renewable energy, enough to meet the demand from 12 million homes, could be gained by outfitting existing dams. Only three percent of the 80,000 dams in the U.S. can now generate hydroelectric power. A second law authorizes power projects of five megawatts or less on infrastructure owned by the U.S. Bureau of Reclamation. A 2012 study found 373 small-conduit sites in Western states with the potential to provide electricity to 30,000 homes. Sandpoint, Idaho, was the first to apply for a hydropower installation under the new requirements. Scheduled to open this fall, Sandpoint's new $136,000 Pelton wheel will generate up to 65 kilowatts of electricity from water tumbling off the Selkirk Mountains into its primary water treatment plant. Jared Yost, GIS manager and special projects coordinator for the city (pop. 7,400), expects the new electricity source to offset power loads at the water treatment plant and provide perhaps half of wastewater power needs. Sandpoint expects to recoup its investment in just three years. Other authorized projects are in flatter areas, such as the irrigation ditches of the Snake River Plain by the North Side Canal Company of Jerome, Idaho. "We don't have a whole lot of vertical drop," says manager Alan Hansten. His district expects payback on investment of the six additional megawatts of generating capacity within 20 years. The company is owned by local farmers who use the water. In suburban Philadelphia, the North Wales Water Authority intends to capture the energy from a 12-inch water line at a microturbine. A reverse pump will replace a valve that reduces the pressure of a 65-foot drop of water volumes of 1,500 gallons a minute, says Raymond Berry, director of operations. Essentially, a pump has been reconfigured to operate as a turbine, he says. |
| WEB-ONLY SIDEBAR: Offshore Wind Energy: Prospects and Problems |
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By Joyce Rowley Comparing a satellite image of the East Coast to ocean wind resource charts is like looking at a map of energy demand and supply: Power-hungry coastal metropolitan areas coincide with plentiful wind energy just offshore. As much as 1,229 gigawatts may be available just off the East Coast, according to recent estimates by the National Renewable Energy Laboratory, a division of the U.S. Department of Energy. Because ocean winds are more consistent, offshore wind turbines could operate at 40 to 50 percent of their capacity, nearly double that of land-based wind turbines. The DOE in conjunction with the Department of Interior's Bureau of Ocean Energy Management proposes licensing 10 GW of offshore wind energy by 2020 and 54 GW by 2030. The agencies are focusing on the Northeast, where energy costs are arguably the highest in the country and the hurricane risk has been historically low. BOEM's recent 164,750-acre seafloor lease, 14 miles southwest of Martha's Vineyard, is projected to produce up to 1,100 MW of electricity. Additional offshore wind farm leases will be bid this year, including a second, larger tract near the Martha's Vineyard lease site. However, plugging into offshore wind energy is three times more expensive than on land, and questions remain about how to integrate an intermittent source with the power grid while maintaining reliability. Typically made of steel foundations and towers with fiberglass blades, offshore wind farms must withstand a corrosive marine environment. Too large to transport over land, components must be manufactured at a deepwater port and barged to the site. Wind farms are then assembled at sea, requiring the use of 200-foot-tall cranes on barges up to 500 feet long that are anchored in open water. Connecting to the power grid can be problematic. Sea substations are needed to convert the electricity from direct current to alternating current and to connect multiple transmission lines to a single cable. These platforms may be up to several acres in size, as is proposed for the Atlantic Wind Connector, a backbone cable connector planned to run from Virginia to New York. The platforms, too, must be built under marine conditions. The transmission cable to land must run for miles over and around shipwrecks and snags, avoid deep sea canyons—and be secured to the bottom to prevent entanglement by whales and fishing gear. And the cable must stay in place during hurricanes. These technologies have not been tested yet in the open waters of the Atlantic Outer Continental Shelf, a far different environment than that of the North Sea or the Gulf of Mexico, where wind farms and oil platforms dot offshore waters. Variability Factor in the impacts of intermittent power supply on the power grid and it is unclear just how much offshore wind will meet the East Coast's energy demand. The Northeast's two independent system operators, New England's ISO-NE and New York's NY ISO, use an economic dispatch system to manage their grids. Energy plants can bid on day-ahead scheduling for projected electricity demand or real-time scheduling for hourly variances in actual power demand. But neither ISOs' land-based wind farms typically bid in day-ahead scheduling. According to ISO-New England spokesperson Lacey Girard, one reason is that if electricity is not supplied as bid, the bidder must pay for it. Instead, because of wind's unpredictable nature, the majority of both New York and New England wind farms are "price takers," the term for power plants that bid in real time on a same day basis and take whatever price is offered. Further, if the demand is lower than projected, those not bidding a day ahead are dropped in a process known as "curtailment." This means that wind power is often curtailed. To help existing land-based wind farms access the grid, both ISOs developed wind forecasting systems based on individual wind farm historical output and meteorology. Forecasting improves wind farm entrance into the grid market and prevents wind farm curtailment, says Girard. But the ISOs must also maintain reliability, something wind is short on. "We're going to need more flexibility in resources to back up wind energy," Girard says, noting that the primary future energy source for New England will likely be natural gas. Joyce Rowley is a freelance writer who covers climate change and wind energy development for several environmental and trade journals in southeastern Massachusetts and Rhode Island. |
Resources
Solar Energy Industries Association: www.seia.org
National Renewable Energy Laboratory solar insolation maps: www.nrel.gov/gis/solar.html
Solar Friendly Communities: http://solarcommunities.org
DSIRE, Database of State Incentives for Renewables & Efficiency: www.dsireusa.org
Planning for Solar Energy (Planning Advisory Service Report 575) is available for free as part of APA's participation in the SunShot Solar Outreach Partnership.