Total Electricity System Power
Total System Power for 2011: Changes from 2010
In 2011, Total System Power for California was marginally higher by half of a percent from 2010. The two primary reasons are the ongoing recession and continued mild temperatures. The effects of the recession resulted in a peak demand that was 5 percent less than the forecast. As for temperatures, they were lower than normal during the spring, near normal temperatures during the summer, and above normal temperatures during both the fall and winter.1 By design, California's electric generation system delivers electricity quickly to match peak air conditioning load conditions in the summer.
In-state generation declined by 2.4 percent in 2011 however net imports from the Northwest and Southwest combined made up for the difference. In particular, energy imports from the Northwest in 2011 increased by 42.7 percent due primarily to an increase in hydroelectric generation resulting from higher precipitation in the Northwest. Between March and May 2011, Oregon and Washington experienced their wettest periods in the last 116 and 117 years respectively.2
With the conversion of Mt. Poso Cogeneration coal facility to a biomass plant complete, the in-state coal category showed a slight decline from 2010. Mt. Poso Cogeneration is about 10 miles north of Bakersfield.
Large hydroelectric generation, a category based on nameplate capacity of 30 megawatts (MW) and larger, showed a significant increase of 24.8% for in-state generation. This coincides with California experiencing one of its wettest years. After three relatively dry years, statewide precipitation during the 2010 Water Year (ending September 30, 2010) was 105% of average. Precipitation during the 2011 Water Year (ending September 30, 2011) was 135% of average, and runoff was 146% of average. Though January 2011 was remarkably dry, the months of March and May were extremely wet with peak snowmelt in early July. As a result, in-state hydroelectric generation in 2011 was 127% of average compared to 101% in 2010.
Generally, when snowmelt and runoff is plentiful, California's hydroelectricity is less expensive to purchase than electricity generated by plants using natural gas-fired generation. Therefore, usage of natural gas-fired generation is reduced ("displaced"). This is especially so during the spring and fall months and during off-peak summer hours (afternoon and early evening hours). Wind generation increased in 2011 reflecting the continued siting of new wind projects in the state. Solar also saw some increase as commercial-scale systems came online in 2011.
Reporting requirements for Total System Power are limited to projects rated at 1MW and larger. Because most solar photovoltaic (PV) systems on residential households and businesses are less than 1 MW, data on them is not collected. As more installations of solar PV and other "behind the meter" distributed generation technologies take place, consumption of power delivered by utilities will continue to decrease. Whether to exclude these smaller systems from the Total System Power summary may need addressing in future, if the aggregate capacity and energy of such small systems becomes a significant portion of the state's generation mixture.
In-State Generation (GWh)
|Percent of California
|Northwest Imports (GWh)||Southwest Imports (GWh)||California Power Mix (GWh)||Percent California Power Mix|
|Unspecified Sources of Power||N/A||N/A||28,840||12,985||41,825||14.2%|
Source: QFER and SB 1305 Reporting Requirements. In-state generation is reported generation from units 1 MW and larger
Contact: Michael Nyberg, Mnyberg@energy.ca.gov
Data as of August 1, 2012
2012 Total System Power
2011 Total System Power
2010 Total System Power
2009 Total System Power
2008 Total System Power
2007 Total System Power
2006 Gross System Power
2005 Gross System Power
2004 Gross System Power
2003 Gross System Power
2002 Gross System Power
Total System Power: Definition and Calculation Method
The California Code of Regulations (Title 20, Division 2, Chapter 2, Section 1304 (a)(1)-(2)) requires owners of power plants that are 1 megawatt (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 generators, and others. The reporting requirement includes facilities that have generation for onsite use, and non-retail generation with reversible turbines used to pump water. (Some of these facilities use electricity to store water in later months, while others pump water at night to generate electricity during subsequent daytime hours). Energy Commission staff collect and verify these reports to compile a statewide accounting of all electric generation serving California.
Balancing Authorities (formerly known as Control Area Operators) are also required to report net amounts of electricity flowing across transmission ties from other Balancing Authority Areas.3 These quarterly reports of electricity imports and exports are at least transparent and do reflect a net import requirement for California.
The net electricity imported from outside California (total imports minus exports) are separated into two geographical regions: the Northwest (NW) and the Southwest (SW) based on the source of the reported import.4 This allocation of imports by specific fuel type is determined by utilities reporting under the Power Source Disclosure Program, described more fully below.
"Unspecified power" is the amount of energy that not specifically claimed by a utility under the Power Source Disclosure Program. This category includes spot market purchases, wholesale power marketing, purchases from pools of electricity where the original source of fuel determined, and "null power". Null power is the generic electricity commodity that remains when the renewable attributes (Renewable Energy Credits, or RECs) are sold separately.
Total System Power is the sum of all in-state generation plus net electricity imports (by fuel type) plus unspecified power. Total System Power cannot be used to track the state's progress for the Renewable Portfolio Standard (RPS) program due to the intricacies, nuances, and special requirements of the RPS legislation. For more information on the RPS program, please visit the following website address: http://www.energy.ca.gov/portfolio/ .
3 The boundaries of electrical California's Balancing Authority Areas do not correspond precisely with the state's geographic boundaries.
4 The Northwest includes Alberta, British Columbia, Idaho, Montana, Oregon, South Dakota, Washington, and Wyoming. The Southwest includes Arizona, Baja California, Colorado, New Mexico, Nevada, Texas, and Utah.
Power Source Disclosure Program
The Power Source Disclosure Program requires 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. These reports are available to the public upon request to the supplier.
Changes made by SBX1-2 (Chapter 1, Statutes of 2011) affecting the eligibility requirements for electricity products considered to be eligible under California's Renewable Portfolio Standard (RPS) also affect procurement claimed on the Power Content Labels. Because of this, revisions to the Power Source Disclosure Program have been delayed until the POU 33% RPS Regulations are further developed. However, changes to the Power Source Disclosure Program, as outlined in AB 162, do not require adoption of the new regulations to become effective. The requirements of AB 162 and the portions of SB 1305 not changed by AB 162 constitute current, effective law.
The term unspecified power is used in the context of allocating fuel types of power generation serving the state of California. California uses a variety of fuel types for power generation including natural gas, hydroelectric, geothermal, and other renewable and non-renewable sources. Unspecified power refers to the situation where the original fuel type of the generator is unknown. This only applies to power imported from out of state.
What is Unspecified Power?
Prior to 2009 there was no category allowed for "unspecified power" in the Net System Power Report - everything had to be allocated under Net System Power. Accordingly, the Electricity Analysis Office (EAO) developed a generation profile mix of the Northwest and Southwest. Essentially, EAO calculated a Total System Power profile for each region. From these profiles, EAO allocated specified claims and then prorated the remainder of the resource mix to the unspecified category. The problem with this methodology was that it treated all unspecified imports as if they were made up of a mix of resources. This method combined both base load power and marginal power as equal. Obviously this was not a good methodology to follow but at the time it was the only one available.
The averaging methodology applied to the old Net System Power reports was widely recognized as flawed because it overestimated the role of baseload plants in the western spot market. Baseload plants selling to California are/were tied to long-term contracts. Most of the unspecified imports are spot market sales that represent about half of the imports. These sales primarily occur when there is surplus generation on the market that is less expensive than variable costs of some California plants.
System averaging does not reflect rate based utility portfolios, dispatch dynamics and short-term market transactions. Surplus, or marginal generation, is what typically serves the spot market. Hydro and coal used to be the marginal resource through the mid-1990's, but load growth surpassed coal generation capacity. Generally, hydroelectric and natural gas-fired electricity generation are considered the marginal generation sources in the interconnected western electricity system. There may be some surplus coal available during off-peak periods, but California generators are usually at minimum load levels during these periods.
The Total System Power table does not show all long-term coal contracts. Most of these are associated with smaller public owned utilities. However, at most, the volume will push the fractional totals by only a few percentage points. The new Power Source Disclosure regulations are expected to reveal these transactions [draft regulations posted May 5, 2011 in Docket 2010-PSDR-01]. In addition, Air Resources Board's mandatory reporting requirements should already be collecting coal imports.
The Power Source Disclosure Program, modified in 2009, allows for "unspecified" imports. Now, EAO can accurately assess specified claims for imports and leaves the remaining unspecified imports as just that, imports not traceable to source fuel type(s).
Methodology for Determining Unspecified Power within Total System Power
For out of state imports, the Energy Commission collects quarterly electric energy import data from Balancing Authorities (BA) within California. The BAs report both imports and exports (exchanges) from other BAs both within California and those out of state. The difference between imports and exports results in net imports.
The net imports are mapped, based on the originating BA, to either the Northwest or Southwest import categories. The Northwest includes Alberta, British Columbia, Idaho, Montana, Oregon, South Dakota, Washington, and Wyoming. The Southwest includes Arizona, Baja California, Colorado, New Mexico, Nevada, Texas, and Utah.
California utilities make specified claims on imported power that directly match a fuel type to an out of state resource. For example, a California-based utility will make a specified claim for wind generation from the Oregon-Washington border (Northwest). Once all of the utilities' specified claims have been accounted for, any remaining net imported power is classified as unspecified power.
Generally, the unspecified power 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. The Southwest spot market purchases would be comprised of new combined cycle power and some coal. Generally, a marginal supply approach for the determination of spot market supply would yield the most accurate assessment of power included in the unspecified power category.
Finally, there is the issue of null power. Null power refers to power that was originally renewable power but from which the renewable energy credits have been unbundled and sold separately. Null power is not attributable to any technology or fuel type.