2017 Total System Electric Generation in Gigawatt Hour
In-State Generation (GWh)
|Percent of California
|Northwest Imports (GWh)||Southwest Imports (GWh)||California Energy Mix (GWh)||California Power Mix|
|Other (Petroleum Coke/Waste Heat)||409||0.20%||0||0||409||0.14%|
|Unspecified Sources of Power||N/A||N/A||22,385||4,632||27,017||9.25%|
Source: CEC-1304 Power Plant Owners Reporting Form and SB 1305 Reporting Regulations.
In-state generation is reported generation from units one megawatt and larger.
Data as of June 21, 2018
The Year in Review
In 2017, total system electric generation for California was 292,039 gigawatt-hours (GWh), up 0.5 percent from 2016’s total generation of 290,567 GWh. California’s non CO2 emitting electric generation categories (nuclear, large hydroelectric, and renewable generation) accounted for more than 56 percent of total in-state generation for 2017, compared to 50 percent in 2016. California's in-state electric generation was up by 4 percent to 206,336 GWh compared to 198,227 GWh in 2016 while net imports were down by 7 percent or 6,638 GWh to 85,703 GWh. The overall modest increase observed in California’s total system electric generation for 2017 is consistent with the recently published California Energy Demand 2018 – 2030 Revised Forecast.
“Annual growth from 2016 – 2027 for the CED 2017 Revised forecast averages 1.64 percent, 1.32 percent, and 1.02 percent in the high, mid, and low cases, respectively, compared to 1.02 percent in the CEDU 2016 mid case.”1
Factors contributing to the increase in total system electric generation include growth in the number of light duty electric vehicles registered in the state, increased manufacturing electricity consumption, and reductions in savings from energy efficiency programs, this last point suggesting that population growth is the primary driver of increased electricity consumption.
Temperatures and Precipitation
Continuing a trend from 2016, temperatures in California were above normal again in 2017, ranking as the third warmest year on record since 1895. Similarly, the average annual temperature across the contiguous U.S. was also the third warmest year since 1895.3 In California, every county averaged at least 3° Fahrenheit (F) warmer than their 100-year average of 1901-2000.4 San Diego County had the highest deviation from the average with 2017 coming in at 7°F higher than the 100-year average.5 The summer months for California, as measured from June through August, set a record as the warmest in 123 years of recorded temperatures. Temperatures peaked on September 1st as a heat storm shattered temperature records across California. San Francisco, Oakland, San Jose, and Santa Cruz all experienced record-setting temperatures, as did many other cities throughout California.
With the drought conditions of previous years coming to a close by the end of 2016, California started off the year with its second wettest winter on record. By February 1, 2017, parts of California had snowpack levels of more than 180 percent of normal.6 Accordingly, on April 7, 2017, Governor Brown declared an official end to California’s four-year drought.7 The wet conditions in the early part of 2017 gave rise to abundant underbrush growth. Later in the year, above average temperatures in the summer saw San Francisco reach a record-setting 104°F 8 and San Jose 108°F 9. The hot temperatures were followed by the Diablo winds in October resulting in some of the state’s most destructive fires on record. Diablo winds refer to air descending from a high-pressure area over Nevada and Utah to low pressure regions in Northern California. These winds compress and warm in the process, with attendant low humidity, and reach speeds of 40 to 50 miles per hour, gusting up to more than 75 miles per hour. By mid-October, more than a dozen large fires had broken out across eight counties in Northern California. Pacific Gas & Electric reported that Red Flag Warnings existed in 44 of 49 counties in its service territory during this time.10 The warnings denote strong winds and dry conditions in areas with very high or extreme fire danger. The most destructive fire in California’s history, the Tubbs Fire, started at this time.11 It incinerated more than 5,600 structures and burned more than 36,000 acres across Lake, Napa, and Sonoma counties. Similarly, Southern California’s dry conditions in December were accompanied by the Santa Ana winds that helped propel what started as a small brush fire into what would be named the Thomas Fire. Similar to Diablo winds, Santa Ana winds originate in dry, high-pressure areas in the Great Basin and blow through the mountain passes in Southern California. Burning over 280,000 acres in Santa Barbara Ventura counties, the Thomas Fire burned the largest acreage on record in California and also destroyed over 1,000 structures.12
Hydroelectric, Solar, and Wind Generation Displacing Natural Gas
California’s 2017 in-state hydroelectric generation climbed to its highest level since 2006, increasing by 50 percent over 2016 to reach 43,333 GWh by year-end. Imported hydroelectric energy added another 7,521 GWh for the year, bringing the total to 50,854 GWh - about 17 percent of the California Energy Mix. Strong precipitation in the beginning of the year, California’s second wettest winter, boosted snowpack conditions in parts of the Sierra Nevada to record and near-record levels. By the close of 2017, California ranked above average for annual precipitation with its 22nd wettest year since 1895. As hydroelectric generation increased, California’s natural gas-fired electric generation was similarly displaced, dropping to 89,564 GWh, its lowest level of the past 17 years. In-state solar photovoltaic (PV) and solar thermal generation increased 22 percent (4,391 GWh) from 2016 levels to 24,331 GWh. Both nuclear and wind generation fell by 5 percent from 2016 levels; nuclear energy from Diablo Canyon Power Plant dropped by 1,006 GWh to 17,925 GWh while in-state wind generation dropped by 633 GWh to 12,858 GWh for 2017.
Net energy imports from the Northwest and Southwest decreased by 7 percent from 2016 levels based on reported exchanges by California balancing authorities. Balancing authorities control power flowing across transmission ties between different regions within the Western Electricity Coordinating Council, which is the Western Interconnect. The following four California balancing authorities reported their annual energy exchanges to the Energy Commission: Balancing Authority of Northern California (BANC), California Independent System Operator, Imperial Irrigation District, and the Los Angeles Department of Water and Power. Net energy imports, including energy received directly from facilities in adjacent states that are dynamically scheduled for California consumption, were 85,703 GWh in 2017, down 6,638 GWh from 2016.
Reporting requirements for total system electric generation are limited to projects rated at 1 megawatt (MW) and larger. Because most solar PV systems on residential households and commercial buildings are less than 1 MW, data on these installations are not collected through the Quarterly Fuel and Energy Report CEC-1304, the power plant owners reporting form. With over 5,500 MW of installed self-generation solar PV for California, these systems represent a range of 6,700 GWh to 8,700 GWh per year of avoided electric generation from the system grid. Effective solar PV capacity factor assumed to range from 14 percent to 18 percent for residential fixed roof-mounted panels. This is significantly lower than capacity factors for utility-scale solar PV installations that range from 20 to 30 percent.
3 NOAA National Centers for Environmental Information, State of the Climate: National Climate Report for Annual 2017, published online January 2018, retrieved on May 30, 2018 .
4 Average temperatures are derived from the daily mean of the maximum and minimum temperatures observed on each calendar day.
5 NOAA National Centers for Environmental Information, National Climate Report - Annual 2017 Annual County Departures from Average, published online January 2018, retrieved on May 30, 2018.
6 NOAA National Centers for Environmental Information, State of the Climate: National Snow & Ice for February 2017, published online March 2017, retrieved on May 30, 2018 .
7 Executive Order B-40-17, State of California, retrieved on May 30, 2018 .
8 National Weather Service Forecast Office, retrieved on May 30, 2018 .
9 National Weather Service Forecast Office, retrieved on May 30, 2018 .
10 Pacific Gas & Electric, Currents - December 15, 2017, retrieved on May 30, 2018 from
12 National Wildfire Coordinating Group, retrieved on May 30, 2018.
California Energy Mix: Total in-state electric generation plus Northwest and Southwest energy imports
California Power Mix: Percentage of specified fuel types derived from the California Energy Mix for use on the annual Power Content Label
In-State Generation: Energy from power plants physically located in the state of California
Northwest Imports: Energy imports from Alberta, British Columbia, Idaho, Montana, Oregon, South Dakota, Washington, and Wyoming
Southwest Imports: Energy imports from Arizona, Baja California, Colorado, Mexico, Nevada, New Mexico, Texas, and Utah
Total System Electric Generation: Used interchangeably with California Energy Mix
What is Unspecified Energy?
Unspecified energy is the amount of energy not specifically claimed by a utility under the Power Source Disclosure Program. This category includes spot market purchases, wholesale energy purchases, and purchases from pools of electricity where the original source of fuel can no longer be determined. It can also include "null energy," energy from a certified renewable facility that has been separated from its renewable attributes (Renewable Energy Credits, or RECs) and sold separately.
Prior to 2009 there was no provision to account for unspecified/unclaimed energy imports in California’s energy mix. This was due to existing legislation that required the Energy Commission to develop a “Net System Power Mix” for utilities to use as a proxy for their spot-market electricity purchases. Accordingly, in the years 2001 through 2008, all unspecified energy was allocated across the source region’s entire energy mix, net of dedicated contracts to California utilities. This allocation tended to over-estimate imports from baseload power plants in adjacent regions.
On October 11, 2009, Assembly Bill 162 (Ruskin, Chapter 313, Statutes of 2009) was passed that added the definition of “unspecified sources” to the Public Utilities Code and allowed utilities to disclose this information to consumers on their annual Power Content Labels. Specifically, “’electricity from unspecified sources’ means electricity that is not traceable to specific generation sources by any auditable contract trail or equivalent, including a tradable commodity system, that provides commercial verification that the electricity source claimed has been sold once, and only once, to a retail consumer.”
For annual summaries that do not account for unspecified energy, years 2001 through 2008, there is a consistent bias toward overstating baseload power generation from adjacent regions and similarly understating imported renewable energy within California’s energy mix.
Generally, the unspecified energy category would be comprised of short-term market purchases from those power plants that do not have a contract with a California utility. Much of the Pacific Northwest spot market purchases are served by surplus hydro and newer gas-fired power plants. Southwest spot market purchases would be comprised of combined-cycle gas turbine energy and some coal-based steam turbine energy. Overall, a marginal supply approach for the determination of the energy available on the spot market would yield a more accurate assessment of the types of energy included in the unspecified energy category. However, allocation of unspecified energy into specific fuel types would tend to imply there is an auditable contract trail available and would add uncertainty to the California Power Mix. The California Power Mix is included on each utility’s annual Power Content Label.
Total System Electric Generation: Definition and Calculation Methodology
The California Code of Regulations (Title 20, Division 2, Chapter 2, Section 1304 (a)(1)-(2)) requires owners of power plants that are 1 MW or larger in California or within a control area with end users inside California to file data on electric generation, fuel use, and environmental attributes. Filings are submitted to the Energy Commission on a quarterly and annual basis. These filings cover all types of electric generation: wind, solar, geothermal, natural gas, hydroelectric, coal, and others. The reporting requirement includes generation from facilities that use power onsite such as refineries and university campuses. Additionally, loads from hydroelectric facilities that are equipped with reversible turbines (a combined pump and turbine generator) are taken into account. Pumping-generating facilities use electricity to meet water storage, water transfer, and water delivery purposes, while pumped storage facilities use electricity to transfer water from one reservoir to another, usually during off-peak hours at night, so that electricity can be generated during the next day to help peak electricity demand. Energy Commission staff collect and verify these reports to compile a statewide accounting of all electric generation serving California.
Quarterly data reports submitted by balancing authorities for energy imports and exports are used to determine the net energy imports for California. The net energy imports are separated into two geographical regions: the Northwest and the Southwest based on the location of the balancing authority area. This allocation of fuel types for imported energy is determined by utility reports under the Power Source Disclosure Program, described more fully below.
Total system electric generation is the sum of all in-state generation plus net electricity imports. Total system electric generation cannot be used to track the state's progress for the Renewable Portfolio Standard (RPS) program due to the special accounting requirements of the RPS legislation. For more information on the RPS program, see the Renewable Portfolio Standard (RPS) page.
Power Source Disclosure Program
The Power Source Disclosure provides current and historical information about the program, requiring retail electricity providers report purchase and sales information to the Energy Commission and their retail customers. The Power Source Disclosure Program was authorized by Senate Bill 1305 (Stats. 1997, Chapter 796, Statutes of 1997), and revised in October 2009 by Assembly Bill 162 (Stats. 2009, Chapter 313). Consistent with the original legislation, retail suppliers of electricity are required to disclose to consumers "accurate, reliable, and simple-to-understand information on the sources of energy that are (being) used...", (Public Utilities Code Section 398.1(b)).
The statutes require electricity suppliers inform their consumers about the types of generation resources used to provide their electricity. Suppliers are required to use a format developed by the Energy Commission called the Power Content Label. The statutes also require utilities to submit a detailed report of their fuel mix to the Energy Commission.
Assembly Bill 1110 (Ting, Chapter 656, Statutes of 2016) modifies Power Source Disclosure reporting by also requiring disclosure of the greenhouse gas emissions intensity associated with the electricity serving retail customers. The proposed changes to the Power Source Disclosure regulations are currently in the pre rulemaking stage. Retail suppliers will begin disclosing their greenhouse gas emissions on the Power Content Label in 2020 for the 2019 calendar year.