By Pushkar Wagle
The integration of large quantities of renewable energy sources, such as wind and solar power, requires changes in how the electric transmission system operates. Here we focus on two key cost implications of renewable integration: the cost due to variable generation and the cost of transmission line expansions required to deliver energy from the point of generation to the load. Both of these are managed by the electric power system operator. For the majority of the State of California that entity is the California Independent System Operator (CAISO).
Both wind and solar energy show great variability in their generation because the wind is not always blowing and the sun is not always shining. With low penetrations of variable generation the related impact is small because the wind and solar variability is still much less than the load variability. At high penetrations, however, the renewable variability may be more challenging to respond to. For example, in California the increased generation from variable energy resources under a 33% Renewable Portfolio Standard (RPS) by 2020 is expected to lead to a higher frequency and magnitude of overgeneration conditions than exist today.
The CAISO explains the potential grid management challenges of variable generation via a duck curve. This curve plots the net load (load minus available generation) over a representative day. The duck curves vary over the year and Figure 1 shows the duck curve for March 31. The duck curve shows that over time as renewable penetration increases, overgeneration is expected to occur during the middle of the day when solar is generating the most. It also shows that the system will be required to supply an additional 13,000 MW, all within approximately three hours, to replace the electricity lost by solar power as the sun sets. To ensure reliability under changing grid conditions, the CAISO needs resources with ramping flexibility and the ability to start and stop multiple times per day.
Figure 1: The duck curve shows steep ramping needs and overgeneration risk (source)
Reliably operating the grid with a 33% RPS requires reevaluating how generating resources are dispatched given their operating capabilities. These operating challenges require all types of flexible capacity, including storage. Flexible resources are generation resources whose operations can be directly controlled (are dispatchable) and quickly start up, shut down, and ramp power output up and down. For example, some steam units are considered flexible because once in operation they ramp power output quickly, but they have very long start-up times. Some reciprocating engines units are considered flexible because they have short start times, but have little ramping flexibility once started. Slow-start resources may need to be committed hours in advance to be ready. This could result in increased costs because during those hours they would be running idle in preparation for providing flexible capacity.
The primary regulatory agency in California, the California Public Utilities Commission (CPUC), has requested that the major privately owned electric utilities in the state consider flexibility needs when contracting for new generation, but has not made explicit flexible capacity requirements, since flexibility needs are still uncertain. Thus, costs associated with renewables’ variable generation are not captured in the calculation for renewable resource procurement bids. Recently, the CPUC has sought stakeholder input into determining a “non-zero” renewable integration cost adder that would be used in evaluating the renewable generation contract bids. Although this appears to be a simple question, in practice, calculating the integration cost has proven to be very complex. Some studies have estimated the wind integration costs in the Western States to be ranging between $4 and $8 per MWh. These costs are significant given the current average wholesale electricity price in California at $40-$45/MWh.
Recent history indicates that the cost impact of transmission to interconnect and deliver the renewable energy might be even greater than the integration cost. Transmission is required to meet growing electricity demand to maintain electric reliability and to access both variable and conventional generating resources. In the past, transmission expenditures as a percentage of the overall cost of electricity to consumers were dwarfed by the cost of electricity production (i.e., fuel, operations, and maintenance) and the capital costs of generation development. This is no longer the case. Recent studies by the CAISO have concluded that expected increases in transmission upgrades and renewable generation interconnection and integration costs represent an enormous and unprecedented new statewide infrastructure investment. These transmission costs are paid for through the CAISO Transmission Access Charge (TAC), which has two components; the High Voltage (“HV”) Rate and the Low Voltage Rate. All users of the CAISO grid pay the HV TAC. The HV TAC has increased from $1.40 per MWh at CAISO Start Up, to almost $9.00 per MWh today (See Figure 2 below). Recent estimates of future increases by the CAISO have the TAC reaching nearly $13 per MWh by 2020. Approximately half of the HV TAC growth between 2010 and 2020 is attributed to transmission infrastructure to accommodate remote large-scale renewables.
Figure 2: Increasing High Voltage Transmission Access Charges for the CAISO System from 2001 to 2013 (source)
Since 2006, the CAISO has approved more than $8 billion of transmission network upgrades to interconnect specific large-scale renewable generators. Yet it has done so without utilizing any economic test to determine the reasonableness of these investments. The CAISO’s current policy for funding network upgrades through TAC’s charged to the ratepayer results in inefficient price signals for generation developers. By spreading the cost of the associated network upgrades across all ratepayers the generation owners or developers do not realize the true cost of the decisions they make in locating their generation. This lack of proper price signals has resulted in a large amount of remote renewable generation seeking interconnection through the CAISO’s generation interconnection queue, which has in turn driven the justification for further network upgrades that may have been unneeded had the generation owners felt the price pressures to locate their plants in more easily connected locations.
The decision-makers and the policymakers approve generation and transmission infrastructure investments for several different objectives including reliability, economics, and policy goals. Given the scale of renewable integration and transmission costs, proper renewable procurement mechanism taking into account variability and interconnection challenges will be necessary for smooth renewable integration into the grid without causing resource shortages and expensive stranded assets.
Pushkar Wagle is a Senior Consultant with Flynn Resource Consultants Inc. based in Discovery Bay, California. He has over 15 years of experience in the electric utility industry. He has worked extensively in the areas of electricity market design, generation interconnection, transmission planning, generation and transmission asset valuations, production cost modelling and risk management. His prior engagements includes a Senior Economist position with LCG consulting, Los Altos, California, a lecturer of economics at the State University of New York at Stony Brook and an intern at Resources for the Future, Washington, DC. Dr. Wagle holds a B.S. in Mathematics and a Masters Degree in Economics from the University of Bombay, India and a Ph.D. in Economics from the Stony Brook University.