Since the first renewable portfolio standard was enacted in Iowa in 1983, more than 30 states, the District of Columbia and three U.S. territories have adopted renewable energy mandates that require utilities to generate an increasing percentage of their electricity from renewable resources—such as wind and solar energy—over time.
The renewable portfolio standard has become a subset of a series of state clean energy laws aimed at eliminating carbon emissions from not just large, investor-owned utilities—which are forced to rethink the way they have done business for the past century—but from transportation and other sectors of the economy.
Some of the toughest renewable energy standards in the country are in the Western United States. California enacted the first RPS in the West in 2002. Now, nine of 11 Western states require utilities to generate a percentage of their electricity from renewable sources. Six states in the West—Washington, Oregon, California, Nevada, New Mexico and Colorado—have put utilities on a path to providing 100% renewable energy by as early as 2040.
In 2001, the U.S. generated 36 megawatts of solar energy, according to the U.S. Department of Energy. By 2020, there were 97,000 MW in operation, thanks in part to state RPS rules. Today, California accounts for 31,872 MW of solar energy, according to the Solar Energy Industry Association.
California’s current RPS calls for renewables to generate 100% of the state’s electricity needs by 2045. To do that, the state will need to build 6 gigawatts of new renewables and storage every year for the next 25 years, according to the California Energy Commission.
During the past decade, California has built an average 1 GW of utility solar and 300 MW of wind a year. Over the next three years, electricity providers regulated by the California PUC will add another 8 GW of clean energy resources, the CEC says.
The impacts of the RPS and clean energy standards depend on the size of the utility and the state. It’s a game changer for investor-owned utilities in states with a 100% clean energy standard.
“It’s been hugely transformative for us,” says Mary Kipp, CEO of Puget Sound Energy, Washington’s largest utility. “It’s changed how we do everything.”
Today, PSE meets the needs of its 1.2 million electric customers with a generating portfolio that includes about 35% coal, 31% natural gas, 23% hydroelectricity and 9% wind. Under Washington’s Clean Energy Transformation Act, PSE needs to be operating on 100% clean energy by 2040.
“At this point, we don’t really know what our generating portfolio will look like,” Kipp says. “We know it will be different. We have to be out of coal in 2025 and natural gas (for electricity generation) by 2030. We’re going to have to find a way to get there, and to do so in ways that maintain reliability and are cost effective.”
State RPS and clean energy standards vary by state. In California and Nevada, electric cooperatives fall under the same standards as investor-owned utilities. In Arizona, both investor-owned utilities and electric co-ops must meet escalating standards that peak at 15% of their load with renewable energy by 2025. Part of that must be from distributed energy resources such as residential solar energy.
Public power utilities in Washington and Oregon don’t have to meet the state’s 100% clean energy standard, but are bound by previously passed RPS rules.
Washington’s Energy Independence Act, passed in 2006, requires utilities serving 25,000 or more customers to pursue all cost-effective energy conservation and acquire “qualifying” renewable resources, with 15% by 2020. Fourteen consumer-owned utilities in Washington fell under the mandate in 2020. Most met the requirement by buying renewable energy credits—a financial commodity associated with renewable energy generation.
Oregon’s RPS requirements divide utilities into large and small classifications. Large consumer-owned utilities must meet 25% of their sales with renewables in 2025. Small utilities must meet 10% of sales with renewables in 2025. Even the smallest Oregon consumer-owned utility must meet 5% of sales in 2025 with renewables.
While RPS policies are popular among legislators and residents in urban areas of the West, they aren’t as popular among some consumer-owned utilities, which view the laws as largely unnecessary and costly.
Consumer-owned utilities in Idaho, Montana, Oregon and Washington receive the bulk of their power from the Bonneville Power Administration, which markets emission-free electricity from federally owned dams on the Columbia and Snake rivers to 127 consumer-owned and three tribal utilities in the West.
However, because hydroelectric power was cut out of the states’ RPS rules as a way to incentivize development of wind and solar energy in the West, many consumer-owned utilities likely must meet their requirement by buying renewable energy credits, largely associated with efficiency upgrades at federal hydroelectric dams.
Even though many small, consumer-owned utilities don’t need to develop renewables to meet state requirements, they may play an important role by helping integrate energy projects onto the regional grid.
Umatilla Electric Cooperative, based in Hermiston, Oregon, already has done that.
“We built a transmission line to help facilitate a renewable project that will help all Oregonians,” says UEC General Manager Robert Echenrode.
A 23-mile transmission line connects a 500-MW wind farm in UEC’s service territory to the regional grid. Power from the wind farm is under contract with Portland General Electric, which is using it to help meet the state’s clean energy standard.
Echenrode says thousands of megawatts of renewable energy projects being built could use that line, and will help meet the state’s clean energy standard.
“Eventually we will all get there,” he says of the 100% clean energy mandate. “The question is how fast and at what cost, and can we do it without eroding reliability?”
Management of Entire Western Wholesale Market Would Help
While utilities feverishly develop and acquire renewable energy projects to meet state mandates, some industry experts say growth has come at the expense of “capacity resources”—power plants that can be turned on when demand increases and renewable energy isn’t producing.
There are 37 balancing authorities in the West—areas where a single utility is responsible for balancing a section of the grid. To take advantage of geographic resource diversity—wind generated in the Intermountain West, hydroelectricity in the Northwest and solar in the Southwest—one or two regional transmission organizations or independent system operators should manage the wholesale market and balance the grid.
To help meet demand in times of low renewable generation and share energy during periods of overgeneration, the California Independent System Operator and PacifiCorp formed the Western Energy Imbalance Market in 2014. The EIM consists of 15 Western utilities, with seven more set to join starting in 2022. However, the EIM covers only about 5% of wholesale energy trades in the West. But forming a regional market where power is traded on a day-ahead basis or in real time will be a huge political undertaking because Western utilities are regulated by state commissions. Each state looks out for its own interests.
“We are getting to the point where we have to look across the West, and that will require a different governance structure that allows various state commissions and utilities to feel they have a voice,” says Mary Kipp, CEO of Puget Sound Energy. “That won’t be easy. If it were purely physics, we could figure it out. But this is going to take some political fortitude.”