One such challenge is transmission planning. Renewable energy resources are generally located in remote areas and away from the state’s load centers. This typically causes a “chicken and egg” problem, where generator commitments are needed to approve transmission cost recovery and generators are inhibited from committing due to uncertain availability and timing of transmission. Additionally, it takes six to eight years to permit power lines and other transmission infrastructure in California. Governor Brown wants to reduce this to three years. California initiatives seeking to address transmission problems include:
- Renewable Energy Transmission Initiative (RETI): from 2007–2010, RETI identified the next transmission projects that should be developed;
- Backstop Cost Recovery: allows the CPUC to guarantee approved cost recovery for new renewable transmission projects in retail rates;
- California Transmission Planning Group: intended to coordinate transmission planning studies and to develop a Conceptual Statewide Transmission Plan;
- Location-Constrained Resource Interconnection Process: a financing mechanism used to share the costs of interconnection facilities to renewable resource areas;
- Generation Interconnection Process Reform: intended to address the needs of renewable energy projects by reforming interconnection procedures; and
- Transmission Project Review Streamlining Directives: issued to coordinate and streamline approval of transmission facilities.
Thirteen major transmission projects, in various stages of completion, are underway in California for interconnection and delivery of renewable energy. They include: SCE’s partially stalled Tehachapi Renewable Transmission Project, PG&E’s Central California Clean Energy Transmission Project, SCE’s Eldorado to Ivanpah Transmission Line Upgrade, SCE’s Antelope-Pardee 500 kV Transmission Line Project, SCE’s San Joaquin Cross Valley Loop, and SDG&E’s recently completed 500 kV Sunrise Powerlink transmission line.
However, current thermal generation capacity and technology may not be enough to support California’s proposed 33 percent RPS mandate. The CEC, CPUC, and California ISO are all analyzing what market design and resource planning changes will be needed to accommodate the increased penetration of intermittent resources. Thermal plants shutting down due to environmental mandates are exacerbating the problem. Mitigation efforts, such as demand response and energy storage, are uncertain in their effects and will not eliminate the need for thermal generation, namely quick-response gas-fired power plants.
It appears California will meet most of its 33 percent RPS mandate through intermittent resources, such as solar and wind. Current estimates anticipate 22 percent of California’s electricity will be provided by intermittent resources in 2020.2 Incentive programs for intermittent resources, such as the California Solar Initiative, a $2.8 billion program, contribute to this reliance on intermittent resources. Additionally, several 2011-12 state legislative bills were introduced to stimulate California’s solar market, including:
- SB 843 (Wolk): allowing IOU customers to purchase renewable power from a “community renewable energy facility” and receive a credit on their utility bill;
- SB1222 (Leno): creating a cap on permitting fees for solar systems; and
- AB 1990 (Fong): creating a 190 MW pilot feed-in tariff to bring solar installation to low income communities.
California’s current portfolio of thermal generating units is not ideally suited to meet the flexible demand necessary to back up intermittent resources. Current system flexibility needs in California are +/- 4,300 MWh where anticipated load growth in 2020 will increase that number to +/- 6,000 MWh. Current concern is that forecasting error in intermittent resource generation, in addition to existing forecasting error on the demand side, will result in larger total discrepancies between forecasted and actual need. Intermittent resources only add more pressure to the flexibility needs of the grid as the amplitude of sustained load ramps and frequency of generation starts and stops will increase. For example, in July 2011, the California ISO experienced both a one-hour 845 MW upward swing and a 349 MW downward drop in another hour. Additionally, a 677 MW drop in wind generation was experienced within one hour in May 2011. Thermal resources need to be able to cover these sudden, large swings.
Increased reliance on intermittent renewable resources will increase the need for back-up, or ancillary, power as larger discrepancies will occur between forecasts and what is needed in real time. Additional ancillary resources, such as the recently opened Lodi Energy Center, will be needed to balance demand-and-supply fluctuations by providing reserves for unexpected events. The fast ramping nature of the new-technology, natural gas-fired plant at Lodi is expected to help meet the integration challenges of renewable energy in California by being able to deliver 200 MW of power within 30 minutes.
At the same time, environmental regulations on traditional power plants are decreasing California’s firm capacity resources. The State Water Resources Control Board adopted a policy in 2010 regulating the use of seawater for cooling purposes at power plants.3 This regulation, banning once-through cooling, affects 17,000 MW of power. The 19 plants affected by the regulation are required to reduce their use of seawater by 93 percent, resulting in two power plants already shutting down. Other plants are being evaluated for viability of continued operations. Additionally, the currently unknown future of the 2,150 MW San Onofre nuclear power plant adds to the pressure for additional firm capacity in California. The CEC, California ISO, and CPUC recognize the challenges presented by the amount of intermittent renewable resources anticipated to be on the grid by 2020 and are exploring several options to mitigate the challenges to grid reliability presented by achieving the 33 percent RPS.
Demand response (DR) is a market design to lower electricity use during periods of high demand by changing normal electrical consumption patterns through changes in electricity pricing or incentive payments. Advocates promote DR as a resource that will allow end-use electric customers to reduce or shift electricity usage and consequently lower peak time energy usage. The CPUC and CEC expect demand response to offset the need for additional power plants.
The CPUC also anticipates smart meters to reduce the need to build new power plants. Smart meters enable utilities to measure customers’ electricity use in hourly increments. This allows customers to participate in dynamic electricity pricing plans that reflect the cost of electricity procurement on a real-time basis. The CPUC has approved the installation by California’s independently owned utilities (IOUs) of over 11 million smart meters. The assumption is that informed consumers will reduce electricity consumption during high demand and therefore reduce total peak daily demand. While hoping time-based rates will reduce the daily peak demand, it will take a high confidence factor to forgo generation capacity in reliance upon smart meters.
The CPUC is also aggressively pursuing distributed generation (DG) and expects DG to play an important role in achieving the RPS mandate. DG resources are typically 3-10,000 kW generation units that are located close to where electricity is used. Of note, the CPUC revised section 399.20 Feed-in Tariff for DG projects up to 3 MW; established the Renewable Auction Mechanism; distributed a market-based procurement mechanism for projects up to 20 MW; and plans to oversee procurement of up to 1,000 MW of solar PV over five years. The CEC notes that DG will provide an alternative to the traditional electric power system. The CEC sees DG as a method to decrease peak demand. Despite the touted benefits of DG, cost-certainty, cost-allocation, and the distribution system’s finite capacity for these resources are still being addressed.
Electric storage technologies are also being investigated to counteract the variability of intermittent renewable resources, however, these technologies are not yet proven.
Geothermal resources are not subject to interruption and can provide reliable baseload power that the intermittent renewable energy resources of wind and solar cannot. California leads the United States in geothermal capacity with approximately 2,500 MW of installed geothermal capacity and is estimated to have the potential for over 3,000 additional MW of geothermal energy.
In summary, increased reliance on intermittent renewable energy sources will increase operational variability within the grid and will require more ancillary services and ramping capability to flexibly operate the grid. Current thermal resources may not be enough to meet this new type of demand and new, more rapid-response gas-fired resources will likely be required to meet the need for additional ancillary resources.
1. See Cal. Energy Comm’n, Pub. No. CEC-150-2011-002-LCF-REV1, Renewable Power in California: Status and Issues (December 2011).
2. Id. at 103.
3. Cal. State Water Resource Control Bd., Res. No. 2010-0020, Statewide Water Quality Control Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling, (May 4, 2010).