Electric production and consumption in California, between shortages and contradictions

This article presents the main problems and contradictions of the Californian electricity system, which are:

• Net electricity imports;
• Wind and solar curtailments;
• Duck curve and frequency response;
• Carbon intensity of electricity consumption;
• Power shortages;
• Average retail price of electricity;

Subsequently, the conclusions and sources (link) are presented. Then, a summary analysis of total emissions and by sector is proposed in Appendix.

The article will be updated in the presence of news, or even expanded in content, while the last update date is shown at the bottom of the article.

INDEX

1. Introduction

1.1 Primary energy consumption

1.2 System electric generation

1.3 Emission indicators

2. Net electricity imports

3. Wind and solar curtailments

4. Duck curve and frequency response

5. Carbon intensity of electricity consumption

6. Power shortages

7. Average retail price of electricity

8. Conclusions

APPENDIX

A1. Total emissions by sector

A2. Forecast of average monthly energy costs in 2020-30

A3. US Sankey diagram for the primary energy consumption

A4. Graphs of total and per capita GHG emissions for all states in 2019

Link

1. Introduction

California has a population of some 39 million, which grew by over 25% through the 1980s and 12% through the 1990s. It is expected to reach 55 million by 2050. Its economy is the world's fifth largest, and includes a major high-technology sector. It produces 13% of US gross domestic product (GDP).

This chapter provides summary information on California's primary energy and electricity needs.

1.1 Primary energy consumption

The unit for measuring primary energy used in the US is the Btu (British thermal unit):

1 Btu = 0.293071 Wh = 1,055.06 Joule

1,000 trillion Btu = 10^15 Btu = 1 Quad

Therefore, in equivalences with multiples of Wh and Joule (J), respectively TWh (Tera = 10^12) and EJ (Exa = 10^18):

1 Quad = 293 TWh = 1.055 EJ

Said this, from 1960 to 2019, California primary energy consumption went from 3.45 to 7.79 quads, with peaks exceeding 8 quads in the 5 years from 2004 to 2008 and the absolute maximum in 2007 with 8.26 quads (EIA - United States Energy Information Administration). California has historically had a high consumption of fossil fuels, especially natural gas and petroleum, the latter mainly for transportation but also industrial sector. However, starting in the 1970s, as will be seen later, California began to have an increasing dependence on net electricity imports; only in the 4 years from 1962 to 1965 there was a small net export of electricity with the maximum of 0.62 trillion btu in 1963. From the end of the 1980s to 2011, nuclear power plants (NPPs) accounted for between 4 and 5% of primary energy consumption. In 2005, NPPs production peaked at 377 trillion Btu (4.6 %). Coal has always been a very marginal energy source. The source of programmable renewable energy (RE) used for the longest time is biomass (60s), to which geothermal energy has been added since the 80s; both have a non-negligible electricity production and in 2019 they accounted for 749 trillion Btu with the peak, in 2011, of 829 trillion Btu. Variable sources of renewable energy (VRE), solar and wind, had a moderate development especially in the early 2000s. In 2019, wind and solar contributed a total of 528 Trillion Btu of primary energy consumption.

The RE, in 2019, accounted for 9.6% and VRE 6.8% of primary energy consumption.

The total of fossil fuels (natural gas, petroleum and coal) is currently still very high, despite the fact that in the last decade the share of VRE has increased but the nuclear one has decreased.

After a progressive decline in the use of fossil fuels from the early 1960s to the mid-1980s, respectively from about 92% to 74% in 1986, this share has fluctuated to date around values of 75% with a slight decline in the pre-pandemic years 2020. The sum of RE (biomass and geothermal), VRE (solar and wind) and NPPs (nuclear power plants) has never exceeded 20% of shares on primary energy consumption, with a peak of 17.4 in 2011 and values just over 18% in 2017, 2019 and 2020. Net electricity imports fluctuate around values between 10 and 11% since the 80s.

Below is the most recent Sankey diagram, published by the Lawrence Livemore National Laboratory in 2018, which shows all primary energy flows in the five sectors:

• Electricity generation;
• Residential;
• Commercial;
• Industrial;
• Transportation;

Also, the end is reported:

• Rejected Energy;
• Energy service;

In 2018, out of 7,704 trillion Btu, 1,608 were for the electricity sector (about 22%) of which only 566 (35%) were transformed into electricity, while the remaining 65% is rejected energy (1,042 trillion Btu). The 35 % figure represents the average efficiency of power plants in California (2018). However, it was necessary to net import an additional 305 trillion Btu of electricity which adds up to the 566 produced in-state.

1.2 System electric generation

The latest data from the California Energy Commission (CEC)?showed in-state generation of 194?TWh from 81.7 GWe of installed capacity?and net imports of 83.6?TWh to give a total consumption of 278 TWh. In-state generation comprised: 16.5 TWh (8%) nuclear;?97.4 TWh (50%) natural gas;?33.3 TWh (17%) solar;?15.2 TWh (8%)?wind;?12.0 TWh (6%) large hydro;?11.1 TWh (6%) geothermal;?5.4 TWh (3%) biomass;?2.5?TWh (1%) small hydro; and 0.3 TWh coal. The imports were 32.6 TWh from Pacific Northwest and 51.1 TWh from Southwest, the latter including 15.7?TWh from coal and gas. About 12 GWe of gas-fired capacity was retired in the eight years to mid-2020. In 2021 in California most of the electricity imported is due to fossil and nuclear sources and programmable renewables (large hydro) for almost 70%, therefore 57.8 TWh of which 8 TWh from coal, 8 TWh from gas and 9.3 TWh from nuclear and the rest from hydroelectric sources (13.6 TWh) and other unspecified sources (18.9 TWh).

The share of fossil fuels, essentially natural gas, is historically always very high, as are net electricity imports (illustrated in the next paragraph). Electric energy production from in-state by nuclear sources has decreased over time, going from the peak of 36.7 TWh in 2011 to 18.5 TWh in the following year, while currently (2021) it has produced 16.5 TWh. Variable renewable energies (VRE), solar photovoltaic (PV) and wind, saw their share grow to 17.4% generation from in-state while this share grows to 25.6% if we include VRE consumption from net imports of electricity. Programmable renewable energies (RE), mainly represented by large hydroelectric plants, account for 17.3% of consumption (including RE consumption from net imports). Hydroelectric, however, has a rather variable state production, from the peak of 36.6 TWh in 2011 to 12 TWh in 2021. The item "other" mainly refers to the consumption of small hydro and biomass, but includes small consumption of oil and Waste Heat / Petroleum Coke.

However, when including net electricity imports in-state consumption, there is a "Unspecified" term that cannot be attributed to any specific source. In 2019, the share of low-carbon intensity sources (VRE, RE and nuclear) reached the maximum in percentage terms with 55.3% and 153.6 TWh; while the maximum production occurred in 2017 with 154.2 TWh. These data include consumption by sources from net electricity imports (see the graph below).

In general, the mix relies more on natural gas during the evening hours from 6:00 p.m. to 9:00 p.m., when electricity demand peaks and solar generation wanes (EIA).

1.3 Emission indicators

California accounts for about 7% of US greenhouse gas emissions. More than 4.5% for Florida but less than 13.6% for Texas, which is the state with the highest emissions.

Total emissions in California between 2011 and 2014 remained stable between 340 and 350 million tons of GHG emissions per year, while after 2014 there was a modest increase, until the decline with the 2020 pandemic, reaching the value o of almost 360 MtCO2eq in 2019. In Florida there was a similar trend, albeit with lower values, while in Texas there was a growing trend from 2009 until the decline with the pandemic.

However, Texas shows a better ratio between GHG emissions (kgCO2eq) and energy supply (Million Btu), historically lower than the national average but also lower than California since 2018, while Florida has values higher than the national average since at least 1970. So, a low value indicates a better environmental efficiency of the energy system.

California shows an good relationship between thousand Btu and chained 2012 dollar of GDP, so kBtu/USD. Florida is higher but lower than the national average, while Texas is higher than the national average. A low value indicates a better economic efficiency of the energy system.

Per capita energy-related carbon dioxide emissions from 1970 to 2020, in metric tons of CO2, are historically somewhat lower in California than in Florida, yet both still below the national average. Conversely, in Texas they are always higher than the national average.

Similar to the kBtu/USD ratio, California shows again a good relationship between GHG emissions and chained 2012 dollar of GDP, so tCO2eq/USD. Florida is higher but lower than the national average, while Texas is higher than the national average.

To conclude this short paragraph, it can be said that California has good ratios kgCO2eq/MBtu, kBtu/USD, tCO2eq/USD and per capita (tCOeq/person), however it is an energy importing country unlike Texas which is a large energy exporter; this affects per capita emissions but also tCO2eq/USD and the other two ratios kgCO2eq/MBtu and kBtu/USD. In fact, Wyoming is a country with few inhabitants (579,000) and has few total GHG emissions but being an energy exporting country it has the highest per capita emissions among all the other states (see Appendix A4, at the bottom of this item).

2. Net electricity imports

At the federal level, electricity routinely flows among the Lower 48 states and, to a lesser extent, between the United States and Canada and Mexico. From 2013 to 2017, Pennsylvania was the largest net exporter of electricity, sending an annual average of 58 million megawatthours (MWh) outside the state. California was the largest net importer, receiving an average of 89 TWh annually. Some states also import and export electricity outside the United States to Canada or Mexico. New York, California, Vermont, Minnesota, and Michigan are the five states that imported the most electricity from Canada or Mexico on average from 2013 through 2017. Similarly, Washington, Texas, California, New York, and Montana are the five states that exported the most electricity to Canada or Mexico, on average, for the same period.

In 2021, around 30%?of California's electricity supply came from outside the state. Net electricity imports in California are rather constant over time, both in terms of quantity (TWh) and as a percentage, as shown in the two figures below (CEC, 2021).

Most of the imported electricity comes from the Southwest. In 2012 there was a peak of imported electricity exceeding 100 TWh.

3. Wind and solar curtailments

As already illustrated, California has variable renewable energy (VRE) penetration, represented by solar PV and wind turbines, equal to approximately 1/4 of state generation and 17.4 % of total energy mix, which includes the net electricity imports (CEC, 2021):

• Solar (PV): 33.26 TWh (11.97 % of total energy mix)
• Wind: 15.17 TWh (5.46 % % of total energy mix)

This discontinuous production of electricity forces the electricity grid operator to cut production from VRE, this is known as "curtailment". Curtailment is greatest in the spring months and growing year by year.

The percentage of curtailment has been growing since 2015, apart from 2021. In 2022, out of a generation of 55,552 GWh of VRE, the curtailment was 2,449 GWh; in other words, 4.41% of solar and wind generation was curtailed (see the graph below that I made on CAISO and California Energy Commission data).

4. Duck curve and frequency response

The duck curve is a graph of power production over the course of a day that shows the timing imbalance between peak demand and solar power generation. Used in utility-scale electricity generation, the term was coined in 2012 by the California Independent System Operator (CAISO). This is due to the increased need for electricity generators to quickly ramp up energy production when the sun sets and the contribution from solar PV falls.

The figure below shows the lowest minimum net load day each year in CAISO from 2015 to 2023.

CAISO, in What the duck curve tells us about managing a green grid (Fast Facts), states that:

"System frequency measures the extent to which supply and demand are in balance. To ensure reliability, system frequency must be managed in a very tight band around 60 hertz. When an unexpected event occurs that disrupts the supply-demand balance, such as a loss of a generator or transmission line, frequency is impacted. These events do not allow time for manual response and balance is maintained through automated equipment. Conventional generation resources include frequency-sensing equipment, or governors, that automatically adjust electricity output within seconds in response to frequency to correct out-of-balance conditions. Part of the renewable integration analysis conducted by the ISO uncovered concerns about frequency response capabilities due to the displacement of conventional generators on the system. The 2020 33% studies show that in times of low load and high renewable generation, as much as 60% of the energy production would come from renewable generators that displace conventional generation and frequency response capability. Under these operating conditions, the grid may not be able to prevent frequency decline following the loss of a large conventional generator or transmission asset. This situation arises because renewable generators are not currently required to include automated frequency response capability and are operated at full output (they can not increase power). Without this automated capability, the system becomes increasingly exposed to blackouts when generation or transmission outages occur."

The EIA states that:

"The duck curve presents two challenges related to increasing solar energy adoption. The first challenge is grid stress. The extreme swing in demand for electricity from conventional power plants from midday to late evenings, when energy demand is still high but solar generation has dropped off, means that conventional power plants (such as natural gas-fired plants) must quickly ramp up electricity production to meet consumer demand. That rapid ramp up makes it more difficult for grid operators to match grid supply (the power they are generating) with grid demand in real time. In addition, if more solar power is produced than the grid can use, operators might have to curtail solar power to prevent overgeneration. The other challenge is economic. The dynamics of the duck curve can challenge the traditional economics of dispatchable power plants because the factors contributing to the curve reduce the amount of time a conventional power plant operates, which results in reduced energy revenues. If the reduced revenues make the plants uneconomical to maintain, the plants may retire without a dispatchable replacement. Less dispatchable electricity makes it harder for grid managers to balance electricity supply and demand in a system with wide swings in net demand."

Currently, this duck curve has become steeper and steeper, taking the shape of a canyon.

It means the power generators will have to shut down resources that can't ignite quickly to get out of the canyon during sunset, or they have to reduce solar (curtailment). Additionally, energy companies need more flexibility from the small pool of resources left.

5. Carbon intensity of electricity consumption

The effect of gas-fired power ramps, caused by the duck curve, is a high variance in mass emissions of carbon dioxide equivalent per energy produced (CO2eq/Wh) and a non-decreasing trend in emissions since 2018. Paradoxically, more the share of energy produced by solar and wind, the greater the variance of CO2eq per electric energy (Wh) and total emissions do not decrease.The graph below, created by Grant Chalmers and based on data from Electricity Maps, shows that California emission rates have become increasingly volatile as the renewable portfolio has increased, yet average emissions have not been reduced significantly (this time series include carbon intensity by sources from net electricity imports).

Currently, California uses two primary types of gas-fired generation for flexibility and renewable backup (as Bill Conlon summarizes):

• Simple cycle gas turbines (SCGTs) can quickly start up and reach full power to rapidly balance waning renewable energy. At full power, modern units have a fuel efficiency of about 38%, which corresponds to a CO2?emissions rate of 480 g/kWh, but efficiency falls when operated at part load to balance renewable variability (40 power plants);
• Combined cycle gas turbines (CCGTs) are the most fuel-efficient power plants because they harvest gas turbine waste heat to operate a steam turbine generator. These plants can achieve a fuel efficiency of more than 50%, reducing CO2?emissions to about 366 g/kWh. However, during the several hours it takes to start the steam system, fuel efficiency can be quite low, and emissions per kWh very high. To be able to respond to the ramp, many CCGTs operate at their minimum power (Pmin), at lower efficiency. Ironically this can also force renewables off-line to increase overall emissions and electricity prices (33 power plants);

The lowest average capacity factor for combined-cycle plants of all ages was in the California Independent System Operator (CAISO), at 41%, in 2020. Older units in the state had the lowest average capacity factor, at 21%, in 2020, but the average capacity factor for plants put into service between 2008 and 2020 in CAISO was also low, at 32%. Although newer plants tend to be run at higher rates than older plants, market conditions in some regions can affect how often newer plants are run, such as in CAISO. New plants may be run less often if they are built in areas where market conditions suddenly shift toward higher renewable or other alternative generation, where local natural gas prices are high, or where electric transmission grid congestion affects the zones where the plants are located (EIA - Natural gas combined-cycle plant use varies by region and age).

Even as natural gas plants in the state run for less time overall, many may start and stop much more frequently in 2030 (in case) than they did currently, potentially also resulting in more NOx emissions.

The table below, created by Grant Chalmers (based on data from Electricity Maps), shows that California in 2022 had the median value of emissions equal to 259 gCO2eq/kWh. Internationally this value is very high when compared with countries with a high share of nuclear energy in the energy mix, such as Sweden and France, which had 26 and 93 gCO2eq/kWh respectively (median value in 2022). In other words, California has 10 times the emissions of Sweden per unit of energy (kWh) and nearly 3 times that of France!

Note how despite the maximum share of low-carbon intensity sources (VRE, RE and nuclear) records in 2019, emissions (gCO2eq/kWh) have not decreased (this technical aspect will be dealt with in a my specific article.).

6. Power shortages

The last few decades in California have been punctuated by electricity shortages and crises due to poor management and failure to plan for the future. Here are just a few cases.

The World Nuclear Association reports that:

"Aside from some large wind farms, hardly any generating capacity was built in California in the 20 years to 2000. Development of almost all new capacity was prevented by environmental activism, despite annual demand growing at a rate of about 2% per year. By 2001, some 80% of California's generating plants were older than 35 years (the two largest gas-fired plants were 45 years old). Some 3000 MWe of gas combined cycle plant came online by the end of 2001 and a further 8400 MWe from then to the end of 2005. From 2001 to 2015, in-state capacity increased from 53.3 GWe to 79.4 GWe, including a lot of intermittent renewables, though in-state generation declined marginally."

Furthermore, the supply crisis, with rolling blackouts, ran from mid-2000 to late February 2001:

"Compounding the long-term problem, towards the end of 2000 the state had a lot of its generating capacity off-line, mostly catching up with maintenance deferred from peak summer load conditions. California thus faced severe power constraints and these continued through the winter into 2001."

and in summer 2020:

"In August 2020 California again experienced power shortages with rolling blackouts. Due to a severe, but not extraordinary, heatwave coinciding with little wind, day-ahead electricity prices spiked at above $1000/MWh. Demand climbed to 49 GWe. CAISO declared a high-level emergency for the first time in 20 years and ordered consumers to reduce electricity demand to keep the power on as much as possible. Imports of power were constrained due to high demand interstate."

Recently, on 31 August 2022, CAISO has issued a statewide Flex Alert, a call for voluntary electricity conservation. The request specifically concerned the use of air conditioning but also the recharging of electric vehicles before 4 p.m., when the grid stability conservation begins to become most critical and to minimize the discomfort:

"consumers are urged to conserve power by setting thermostats to 78 degrees or higher, if health permits, avoiding use of major applicances and turning off unnecessary lights. They should also avoid charging electric vehicles while the Flex Alert is in effect. To minimize discomfort and help with grid stability, consumers are also encouraged to pre-cool their homes and use major appliances and charge electric vehicles and electronic devices before 4 p.m., when conservation begins to become most critical. Reducing energy use during a Flex Alert can help stabilize the power grid during tight supply conditions and prevent further emergency measures, including rotating power outages."

7. Average retail price of electricity

The Energy?Information Administration (EIA), in Electricity data browser, reports the average retail price of electricity for following 5 sectors, aggregated by monthly, quarterly and annual:

• Residential;
• Commercial;
• Industrial;
• Transportation;
• Other;

but it also reports the average retail price for all-sectors (a single price that covers all sectors), always aggregated by monthly, quarterly and annual. In the graph below, which shows the annual average retail price of electricity in cents/kWh for all sectors in U.S., note the increase due to inflation from 2020 onwards (Fred).

Of course, retail electricity prices are usually highest for residential and commercial consumers because it costs more to distribute electricity to them. Industrial consumers use more electricity and can receive it at higher voltages, so supplying electricity to these customers is more efficient and less expensive. The retail price of electricity to industrial customers is generally close to the wholesale price of electricity. Electricity prices vary by locality based on the availability of power plants and fuels, local fuel costs, and pricing regulations.

Many factors influence electricity prices: electricity prices generally reflect the cost to build, finance, maintain, and operate power plants and the electricity grid (the complex system of power transmission and distribution lines). Some for-profit utilities also include a financial return for owners and shareholders in their electricity prices.

Several key factors influence the price of electricity (Electricity explained, EIA):

• Fuels: Fuel prices, especially for natural gas and petroleum fuels (mainly in Hawaii and villages in Alaska), may increase during periods of high electricity demand and when there are fuel supply constraints or disruptions because of extreme weather events and accidental damage to transportation and delivery infrastructure. Higher fuel prices, in turn, may result in higher costs to generate electricity;
• Power plant costs: Each power plant has financing, construction, maintenance, and operating costs;
• Transmission and distribution system: The electricity transmission and distribution systems that connect power plants with consumers have construction, operation, and maintenance costs, which include repairing damage to the systems from accidents or extreme weather events and improving cybersecurity;
• Weather conditions: Extreme temperatures can increase demand for heating and cooling, and the resulting increases in electricity demand can push up fuel and electricity prices. Rain and snow provide water for low-cost hydropower generation, and wind can provide low-cost electricity generation when wind speeds are favorable. However, when there are droughts or competing demand for water resources, or when wind speeds drop, the loss of electricity generation from those sources can put upward pressure on other energy/fuel sources and prices;
• Regulations: In some states, public service/utility commissions fully regulate prices, while other states have a combination of unregulated prices (for generators) and regulated prices (for transmission and distribution).

The cost of generating electricity is the largest component of the price of electricity.

In 2021, California has some of the highest retail price of electricity for all-sectors (annual average) in the US, with 19.65 cents/kWh, almost double the average (11.10 cents/kWh) across the 50 US States. Only Alaska is retail price higher than California, albeit slightly higher (20.02 cents/kWh). The EIA table below shows that in California, despite the high net summer capacity of 81.2 MW, net generation is only 197.2 TWh, therefore with a capacity factor of 27.7%. In contrast, lower-capacity (net summer capacity) Florida (64.6 MW) produced more energy than California, approximately 246.5 TWh (net generation), thus with a significantly higher capacity factor of 43.5%. So, in Florida, the electric system is significantly more efficient and more economically convenient, with a retail price of electricity of 10.67 cents/kWh, essentially half the California retail price.

Since 2008, when Governor Arnold Schwarzenegger signed an executive order (SB 375) requiring the state’s utilities to obtain a third of the electricity they sell from renewables by 2020, all-sector electricity prices in California have soared. In the residential sector, from 2008 to now, electricity prices have almost doubled from 13.81 cents/kWh in 2008 to 26.17 cents/kWh in 2022. So, California residents are now paying the highest electricity prices in the U.S., outside of Hawaii. Prices in Hawaii are high relative to other states mainly because the majority of its electricity is generated with petroleum fuels that have to be imported into the state. As can be seen in the graph below, the national average electricity prices for residential sector in 2022 is much lower than in California, at 15.12 cents/kWh, while in Florida at 13.92 cents/kWh is just over half the cost in California (see graph below and the Electricity Data Browser by EIA).

The high cost of retail price of electricity in California is evident by observing the trend for the industrial sector, since, as already mentioned, it is essentially the wholesale price. The annual average retail price of electricity for industrial customers even before the pandemic, in 2019 was (see graph below):

• California: 13.40 cents/kWh
• US: 6.81 cents/kWh
• Florida: 7.65 cents/kWh

Currently, 2022:

• California: 17.37 cents/kWh
• US: 8.45 cents/kWh
• Florida: 9.36 cents/kWh

Consistently, the cost of electricity to the commercial sector is also historically high in California (see graph below).

Since 2001, California has consistently had higher retail prices of electricity in all sectors than both the national average and Florida (it used in this comparison). Graphically representing the ratios, for all 3 sectors considered (residential, industrial and commercial), between the retail prices of electricity in California on the US and again on the retail prices of electricity in California on that in Florida, it can be observed that: up until 2009 these ratios were substantially declining, then since 2010 all these ratios have been on the rise. In 2010 the lowest retail price of electricity ratio (California/Florida) was reached in the industrial sector, but still greater than 1, therefore to the advantage of Florida; in other words, in 2010 the retail price in California was 1.1 times higher than in Florida. In the year before the pandemic, 2019, the lowest ratio was for California's residential retail price of electricity relative to the national average and that ratio was nearly 1.5; therefore electricity for citizens was 1.5 more expensive than the national average (see graph below). In addition, in 2019, the annual average retail price of electricity in California, for the industrial sector, was almost double the national one, and from 2020 (included) it is more than double! In other words, the post-2010 trend is telling here, as it coincides not with the timing of deregulation, but instead with the start of California’s aggressive commitment to reduce carbon emissions.??

Until 2016, Florida had higher percentage increases than both the national average and California, but having lower initial retail prices than California has always had lower costs. Similar considerations can be made between the national retail price and the Californian one (see graph below).

It's not all, in the report Utility costs and affordability of the grid of the future - an evaluation of electric costs, rates and equity issues (Pursuant to p.u. code section 913.1, May 2021, California Public Utilities Commission) on page 5 it states that:

"These projections show that, for energy price sensitive households, bills are expected to outpace inflation over the coming decade. The implication is that, if household incomes are expected to generally increase at the rate of inflation, energy bills will become less affordable over time"

and on page 33 (see table below):

"With California’s aggressive goals for transportation electrification over the next decade, significant upgrades to the distribution grid may be necessary to accommodate charging demand. While there is an ongoing policy discussion regarding the extent of ratepayer responsibility for TE costs, there is the potential for these costs to drive rate increases."

The composition of forecasted bundled residential rates ($ nominal/kWh) of the main 3 IOUs (Investor-Owned Utilities):

• Pacific Gas and Electric Company (PG&E)
• Southern California Edison (SCE)
• San Diego Gas & Electric (SDGE)

it shows that the cost of electricity is and will be inherently high throughout California.

It should be noted how the percentage sum of the transmission and distribution components is high, if compared to the national average, in which the largest component is generation with 56% (EIA, 2021).

8. Conclusions

California's power system has been plagued by crises and shortages for decades now. Overall, it has proven to be dependent on electricity imports for almost 1/3 of consumption, i.e. 83.6 TWh in 2021 on a total consumption of 278 TWh.

Already in the early 2000s, James L. Sweeney wrote that "in the 1980s annual applications to build new California electricity-generating capacity averaged about 1,000 MW per year. The majority of these were plants with capacity below 50 MW, which are not subject to California Energy Commission approval. But between 1990 and 1996, annual applications for certification averaged about 250 MW per year, while annual retirements of generating capacity averaged about 450 MW per year, decreasing generating capacity within California during those seven years by about 1,400 MW. Electricity use during that time continued to grow in California, as in the rest of the West. As opposed to the 1980s, when capacity was increasing by more than electricity use, California was increasing its need for electricity generation while decreasing the capabilities to provide that electricity." (The California Electricity Crisis, page 101 - Investment in new generating units in California).

In 2005, Charles J. Cicchetti, Jeffrey A. Dubin and Colin M. Long wrote that "The key downstream issues that flow from the wholesale power grid are generation? distribution? and what entity serves retail consumers. Upstream? California needs additional electric generation capacity. Neither the IOUs nor Independent Power Producers (IPPs) have been willing or able to assume the political risks inherent in building new generation in California. In 2000? Governor Davis promised that 20?000 MWs of new generation would be built in California by 2005. This promise has remained largely unfulfilled. Only about 5?700 MWs of this new generation is now operating. There are 6?635 MWs of new generation with approved licensing. Construction on about half (3?300 MWs) the licensed generation has been suspended or cancelled. Further? according to the California Energy Commission? about 5?000 MWs of new capacity has been withdrawn from the power plant siting process." (The California Electricity Crisis: What, Why, and What's Next, page 179 - New Generation Capacity).

California's electrical system, in addition to the shortage of electrical generation infrastructure, well documented here, it shows also inefficient because it increasingly resorts to curtailment for variable renewable energies (VRE), solar PV and wind, and in 2022 curtailment came close to 4.5% of the VRE produced for almost 2.5 TWh.

Not only, the California Independent System Operator (CAISO) uncovered concerns about frequency response capabilities due to the displacement of conventional generators on the system and the grid may not be able to prevent frequency decline following the loss of a large conventional generator or transmission asset. This makes California's electrical system unreliable.

The duck curve, with the consequent loading ramps for fossil sources, typically gas turbines (SCGTs and CCGTs), are responsible for high carbon intensity (gCO2eq/kWh) of the State's electricity consumption. In 2022, California emitted 259 gCO2eq/kWh (median value), 10 times the emissions of Sweden per unit of energy (26 gCO2eq/kWh) and nearly 3 times that of France (93 gCO2eq/kWh)! Both countries mentioned, Sweden and France, have a high share of nuclear power in the energy mix and are historically net exporters of electricity. In essence, California is a polluting state.

The retail price of electricity for all-sectors (2021) in California is the second highest in the United States, after the retail price in Alaska (a little higher), at 19.65 cents/kWh, nearly double the average (11.10 cents/kWh) in the 50 states of the United States United. In 2022, California surpassed the annual average retail price of Alaska (20.54 cents/kWh for all-sectors) and it's the state with the most expensive retail price of electricity, with 22.48 cents/kWh (all-sectors), outside of Hawaii. This aspect represents a problem for households and for the competitiveness of businesses. The high retail price of electricity in California, for the industrial sector, shows that the problem is mainly with the wholesale price.

The inefficiency, unreliability, emissions and high costs of the Californian electricity system, have generated obvious internal contradictions, including the invitation of the CAISO (Independent System Operator - ISO) in the umpteenth electricity crisis of August 2022, not to recharge electric vehicles, which among other things are subsidized by the Clean Vehicle Rebate Program (CVRP). Moreover, although in California there are no longer coal-fired steam turbines and the only operational nuclear power plant is Diablo Canyon, in 2021 a part of the net imported electricity is due to fossil and nuclear sources, of which certainly 8 TWh from coal, 8 TWh from gas and 9.3 TWh from nuclear.

Ultimately, all this is the result of decades and decades of ideological and irrational energy policies, which have created an unreliable, inefficient, polluting and very expensive electricity system.

Although California is the emblem of the worst management of the state electricity system, other states have also had to deal with the contradictions of their electricity system, among which Texas: Austin passes subsidies for gas power to counter wind-power subsidies that have destabilized the state electric grid. In other words, Texans will now spend tens of billions of dollars to bolster natural-gas plants that provide reliable power but can’t make money because of competition from subsidized renewable energy (Wall Street Journal).

MP

May 1, 2023

Update June 26, 2023

APPENDIX

A1. Total emissions by sector

The California Air Resources Board (CARB) identifies 7 sectors to which all GHG emissions are attributed:

• Transportation;
• Electric power;
• Industrial;
• Commercial and residential;
• Agricolture;
• High GWP (Global Warming Potential);
• Recycling and waste;

Below is the detailed distribution of emissions in 2020 as a percentage.

As can be seen (graph below), greenhouse gas emissions have not substantially decreased in almost any sector in the last 10 years, apart from 2 sctors: transport and especially electric power. The transportation sector represents tailpipe emissions from on-road vehicles and direct emissions from other offroad mobile sources. It does not include upstream well-to-tank emissions from oil extraction, petroleum refining, and oil pipelines. These upstream emissions are included in the industrial sector category. This sector dropped significantly from 2019 to 2020 due to the impact of the pandemic, but, however, it showed modest growth between 2013 and 2017 because California is the largest consumer of jet fuel and second-largest consumer of motor gasoline among the 50 states (California Quick Facts, EIA). The electric power sector is the only one that has shown a significant drop in emissions, but since 2017 it has remained "practically" constant, measuring in million metric tons of CO2eq:

• 2017: 64.2 MtCO2eq
• 2018: 65.0 MtCO2eq
• 2019: 60.2 MtCO2eq
• 2020: 59.5 MtCO2eq

The report California Greenhouse Gas Emissions for 2000 to 2020 - Trends of Emissions and Other Indicators (California Air Resources Board, October 26, 2022) on page 7, is stated that:

"The large decline in total statewide 2020 emissions is likely due in large part to the impact of the pandemic. Additional drivers of emission changes are noted for each sector below. The transportation sector remains the largest source of GHG emissions in the State. Direct emissions from vehicle tailpipes, off-road transportation sources, intrastate aviation, and other transportation sources, account for 37 % of statewide emissions in 2020. This is a smaller share than recent years, as the transportation sector saw a significant decrease of 26.6 MtCO2eq in 2020. When upstream emissions from oil extraction, petroleum refining, and oil pipelines in California are included, transportation is responsible for about 47 % of statewide emissions in 2020. Emissions from the electricity sector account for 16 % of the inventory in 2020 and had a slight decrease of 0.7 MtCO2eq compared to 2019. Continued growth in in-state solar generation and increases in imported renewable electricity more than compensate for the significant drop in in-state hydropower generation due to below average precipitation levels. The industrial sector trend has been relatively flat in recent years but saw a decrease of 7.1 MtCO2eq in 2020. Commercial & residential emissions saw a decrease of 1.7 MtCO2eq. Emissions from high-GWP gases have continued to increase as they replace ODS that are being phased out under the 1987 Montreal Protocol. Emissions from other sectors have remained relatively constant in recent years."

Overall, California's GHG emissions decreased from their 2007 peak, so from 484.7 MtCO2eq to 2019 404.5 MtCO2eq (2020 is pandemic-hit). This drop is essentially due to the drop in emissions from the electricity sector, which, as mentioned above, have ceased to fall since 2017 and therefore also the total GHG emissions between 2017 and 2019 have had a small decrease, about 1.5%. As a result, per capita consumption also decreased, from 13.8 tonnes per capita in 2001 to 10.2 in 2019.

A2. Forecast of average monthly energy costs in 2020-30

From report Utility costs and affordability of the grid of the future - an evaluation of electric costs, rates and equity issues (May 2021, California Public Utilities Commission), on the forecast of the costs of electricity, natural gas and gasoline, these forecast projections to 2030, in the graph below, show that in California (page 5):

"for energy price sensitive households, bills are expected to outpace inflation over the coming decade. The implication is that, if household incomes are expected to generally increase at the rate of inflation, energy bills will become less affordable over time".?

The rate forecasts developed as part of this white paper, in conjunction with estimates of natural gas rates and gasoline prices, were used to project total energy bills for a representative high energy usage household located in a hot climate zone based on rates for each of the major IOUs (see pages 5 and 6).

A3. US Sankey diagram for the primary energy consumption

Below is the most recent Sankey diagram, published by the Lawrence Livemore National Laboratory in 2021 for US.

The diagram below shows the flows as a percentage in 2021 for US.

The diagram below shows the U.S. primary energy consumption by energy source (EIA, 2021).

Energy Flow Charts for all states:

A single energy flow chart depicting resources and their use represents vast quantities of data. Energy resources included solar, nuclear, hydroelectric, wind, geothermal, natural gas, coal, biomass, and petroleum. Energy flow diagrams change over time as new technologies are developed and as priorities change. Search the flow chart database by year, country, and state. Some charts are not available for some years. Reset parameters for a new search.

A4. Graphs of total and per capita GHG emissions for all states in 2019

Link

CAISO

CEC

World Nuclear Association

EIA

Other

Duck curve

California Electricity Demand Forecast Zones:

Paper

Miscellaneous articles

U.S. inflation