Low Carbon Fuel Standard Litigation (California)


(Many thanks to Tyler Blix for his research and contributions for this post).

California Assembly Bill 32 (“AB 32”), also known as California’s Global Warming Solutions Act of 2006, set a goal for the statewide reduction of GHG emissions to 1990 levels by 2020. In addition, Executive Order S-01-07, issued by Governor Schwarzenegger in 2007 set a goal to “reduce the carbon intensity of California’s transportation fuels by at least 10 percent by 2020.”  The Executive Order tasked the California Air Resource Board (“CARB”) with the development and implementation of numerous regulations to achieve this goal. In April 2010, CARB adopted the Low Carbon Fuel Standard (“LCFS”) pursuant to AB 32. The LCFS seeks to “reduce greenhouse gas emissions by reducing the full fuel-cycle, carbon intensity of the transportation fuel used in California” by 10% in 2020. A number of fuel suppliers challenged the constitutionality of the LCFS, arguing that it violates the US Constitution’s Commerce Clause and sought to enjoin its enforcement. The case was heard in the United States District Court for the Eastern District of California and  issued in ten orders in December 2011. It was appealed in the United States Court of Appeals for the Ninth Circuit with decision in December 2013. The following is a summary of the main issues and holdings in the litigation.

Low Carbon Fuel Standard

The carbon intensity of a particular fuel is calculated by determining the GHG emissions created throughout the full life-cycle of a fuel, from production to distribution and consumption.  CARB assigned carbon intensity baseline values to different fuels based on the source of fuel involved such as biomass or crude oil as well as the “pathways” used to get the fuel to California. The carbon intensity score for a particular producers’ fuel is calculated and then compared to the statewide average carbon intensity level established for that year. A fuel provider can generate credits if the carbon intensity of their product is lower than the statewide average. However fuels with a score above the statewide average will create deficits which providers must offset with previously accumulated credits or by purchasing credits from others. Producers may also apply for a customized carbon intensity score if they can show that their production processes and pathways used differ from those calculated by CARB.

Rocky Mountain Farmers Union v. Goldstene (Case Number CV-F- 09-2234 consolidated with Case Number CV-F-10-163)

Two separate cases were enjoined, the Rocky Mountain Farmers’ Union et al v. Goldstene (representing the California Air Resources Board (CARB), and The American Fuels and Petrochemical Manufacturers Association et al. v. CARB. In the District Court, the plaintiffs argued that the LCFS was legally defective for four reasons. First, the LCFS is impermissibly discriminatory against out of state corn ethanol and discriminated against out-of-state crude oil.  Second, the LCFS impermissibly regulates commerce and the channels of interstate commerce (or impermissibly controls extraterritorial conduct). Third, the LCFS excessively burdens interstate commerce without producing local benefits. And finally, the LCFS is preempted by the Energy Independence and Security Act of 2007 (“EISA”), and preempted by federal Renewable Fuel Standard within the Clean Air Act.

The district court decision focused primarily on the commerce clause challenge, rejecting California’s arguments that Section 211(c)(B) of the Clean Air Act (CAA) provided authority to violate the Commerce Clause. A state law violates the commerce Clause if it is found to “discriminate against an article of commerce by reason of its origin or destination out of state.” Discrimination means “differential treatment of in-state and out-of-state economic interests that benefits the former and burdens the latter.” The industry plaintiffs argued that the LCFS was discriminatory because it assigned higher carbon intensity values to some out-of-state ethanol producers than it did to California ethanol producers. California countered that in determining carbon intensity values, the LCFS applies a uniform lifecycle analysis, which includes many different factors, to all ethanol in a nondiscriminatory manner. The court found that the LCFS “explicitly differentiates among ethanol pathways based on origin…and activities inextricably intertwined with origin”, such as transportation. The court held these differentiations to be facially discriminatory to out-of-state ethanol, discriminatory in purpose and effect against out-of-state crude oil and therefore discriminatory towards interstate commerce.

The court next considered whether the LCFS controls extraterritorial conduct. Answering the question in the affirmative, the court emphasized CARB’s statement that carbon intensity values would provide an “incentive for regulated parties to adopt production methods which result in lower emissions.”  The court found that the practical effect of such attempts to incentivize the reduction emissions would be to control conduct occurring “wholly outside of California”. As such the court held that the LCFS impermissibly controls conduct outside of its borders.

After a determination that a state’s regulation discriminates against interstate commerce, the state must show that the law “serves a legitimate local purpose” and that the purpose could not be achieved as well by available nondiscriminatory means. The plaintiffs maintained that since climate change is a global problem, attempts to regulate GHG emissions do not serve a local purpose. However, citing dicta from Massachusetts v. EPA, the court found that a state does have a local legitimate purpose in reducing global warming. Despite this finding, the court held that California had “failed to establish that they could not achieve [its] goal through other nondiscriminatory alternatives”. Therefore, the court determined that the LCFS failed the applicable commerce clause strict scrutiny analysis and struck down the regulation as unconstitutional.

After his decision in the case, Judge O’Neill refused CARB’s petition to stay his preliminary injunction pending the outcome of the appeal in the Ninth Circuit. Judge O’Neill determined that lifting the injunction “would require this court to reconsider and reverse the core issues of the appeal” and it was thus beyond his jurisdictional authority as it would alter the status of CARB’s appeal. However, the stay was subsequently granted by the Ninth Circuit Court of Appeals.

The Ninth Circuit then heard oral arguments in October 2012, and while the decision was pending, California has been able to continue its enforcement of the LCFS.

Rocky Mountain Farmers Union v. Corey (representing CARB) 2013 (Case Number 12-15131 09/18/2013)

The Ninth Circuit Court of Appeals issued its decision in September 2013. While the court reversed and remanded some holdings to the lower court, it also remanded for renewed decision on another holding.  The following summarizes that main issues decided.

The Court considered whether the Clean Air Act provides California the authority to violate the Commerce Clause and upheld the lower court holding that CARB cannot use CAA as authority to violate the Commerce Clause.

On the issue of whether the LCFS facially discriminates against interstate commerce, the Court held that the ethanol provisions do not facially discriminate against interstate commerce and that the crude oil provisions do not discriminate against out-of-state crude oil in purpose or effect. However, the issue was remanded to the district court to determine whether the ethanol provisions discriminate in purpose or effect. If yes, the district court should apply strict scrutiny to the provisions. If not, the District Court should apply Pike v Church balancing test, which states that “[w]here the statute regulates even-handedly to effectuate a legitimate local public interest, and its effects on interstate commerce are only incidental, it will be upheld unless the burden imposed on such commerce is clearly excessive in relation to the putative local benefits”.

Therefore, the burden is on the plaintiffs-appellees (Rocky Mtn et al.) to show that the LCFS imposes a burden “clearly excessive in relation to local benefits”. The Court also directs the court to apply the Pike balancing test to the provisions for crude oil, although they also stated that the crude oil provisions are not discriminatory in purpose or effect.

Finally, on the question of whether the LCFS constitutes impermissible extraterritorial regulation, the court ruled in favor of CARB, reversing the lower court decision. Therefore, the LCFS does not impermissibly regulate outside the jurisdiction.

It will be interesting to follow how the District Court will decide whether the ethanol provisions are discriminatory in purpose or effect. While purpose may be relatively easily shown to be non-discriminatory based on the suite of regulations including the LCFS adopted largely to lower greenhouse gas emissions, discrimination in effect may be more difficult to disprove.

Watch this space for future developments on the LCFS!

Disclaimer: This is for informational purposes only and is not meant to provide legal advice.

EPIC Presents at Western Energy Policy Research Conference

Western Energy Policy Research Conference 2013

Scott Anders and Nilmini Silva-Send attended and presented at this 3rd Annual conference in Portland, Oregon, Sept 5-6, 2013.

Scott Anders and Nilmini Silva-Send presented on a panel titled “Metropolitan and Regional Planning. ” Nilmini Silva-Send spoke about the effects of CEQA GHG Guidelines 2010 and SB 375 on local and regional greenhouse gas planning and in particular how GHG planning is being shaped by the courts. Litigation by “any interested group” and the Attorney General based on her duty to protect natural resources of the state are so far based on CEQA and the courts are doing what they always do – filling the gaps left by the legislature in application of these regulations. In particular, the courts have held that it is legally insufficient to not take into consideration Executive Order S-3-05 (state goal of reaching 80% below 1990 GHG levels in 2050) in any planning document that extends to that year.

Mr. Anders spoke about EPIC’s City-Scale Climate Planning Model for the San Diego Region.  This is a model developed by the Energy Policy Initiatives Center (EPIC), University of San Diego, to assist local jurisdictions to develop climate actions plans and the effects on GHG reductions of mitigation measures.  The model allows users to project emissions for planning years 2020 and 2035, select GHG reduction targets for those years, choose from a range of reduction measures to reduce emissions, and even estimate costs for a subset of measures. The tool is also designed to account for the inter-related nature of certain policy measures. For example, an increase in electric vehicles will increase electricity use but reduce emissions from the transportation sector. However, the emissions from this increased electricity use will depend on the percentage of zero-emission renewable energy sources used to produce the electricity.  Thus the model is based on two critical factors that drive emissions in the main emitting categories transportation and electricity: the GHG emissions intensity of a mile driven (CO2e/mile) and the GHG intensity of a unit of electricity (tons of CO2e per megawatt-hour).

Dr. Silva-Send also spoke on the “International Energy Policy” panel about National Energy Policies on Trial at the World Trade Organization. As negotiations on the future of the international climate regime languish, the obligations that most countries have taken on in the climate change regime require adoption of national energy policies that have significant impacts on international trade.  Because of this, climate change disputes have arisen at the World Trade Organization (WTO). In the past, the WTO dispute settlement body has attempted to find ways to balance trade and environmental rights and obligations affecting its members. While in theory the WTO has found a way to preserve non-discriminatory national environmental policies in the face of international trade rights, and this analysis may be extended to climate change-based national energy policies, none of the energy policy disputes are being defended on the basis of environment or climate.

The complaints recently decided or pending at the WTO are on wind energy subsidies (USA-China); feed-in tariff as subsidies and its domestic content rule (Japan/EU-Canada); biodiesel sustainability criteria of 35% GHG reduction as arbitrary and whether the EU’s FIT laws are actionable subsidies (Argentina-EU/Greece/Italy);  the biodiesel sustainability criteria of 35% GHG reduction is arbitrary and the EU’s FIT are actionable subsidies (China -EU); subsidies for solar cells and modules and domestic purchase rules (US/India).

Watch here for further developments in these areas of litigation!

Water-Energy Nexus: City of San Diego

This is the second in a two-part series on the water-energy nexus and this post focuses on the City of San Diego. The previous post, discussed the energy and greenhouse gases associated with moving water in the state of California. Generally, the water-energy nexus refers to how energy is consumed and embedded within the water use cycle. A common breakdown separates that energy into two categories:

a) energy use by the water industry, and

b) energy use by the water customer, known as end-use.

End-use represents the amount of energy used by the customer for heating and pumping water in a home, office or facility.

In 2010, per capita water use (end-use) in the City of San Diego was about 125 gallons/day. Total water use has remained steady since the mid 1990’s, decreasing only slightly within the last few years. Also, per capita water use is relatively independent of rainfall.


Source: Urban Water Management Plan 2010, SDCWA

Energy Use Associated with Water in San Diego

How does the City of San Diego compare with the state of California as far as energy use and GHG emissions within the water-energy nexus?

Much of the water supplying San Diego travels a considerable distance. As a result, the relative fraction of energy associated with end use in San Diego is below the sate average. However, even with grater up-stream energy demands for the water supply, end use remains the largest sector of the energy water nexus in San Diego. Furthermore, because little can be done to mitigate the physical distances water must travel to reach San Diego, end-use energy consumption still provides the greatest opportunity for conservation and efficiency improvements.

About 80% of end-use energy is natural gas. This is in contrast to each of the other sectors of the water-energy nexus, which are driven largely by electricity. Therefore, reductions in end use consumer water consumption, as well as end use efficiency improvements, would correspond to major reductions in natural gas consumption.

Energy use end use City SD copy

Precisely determining what fraction energy use within the water-energy nexus is associated with end-use can be difficult because the key variable, energy intensity, varies from study to study.

Two recent end-use energy intensities studies include a case study in 2004 for the San Diego region, and a California-wide study in 2008. The end-use energy intensity varies significantly between the two studies. The 2004 San Diego case study estimated 11,969 kWh equivalent per million gallons while the 2008 state-wide study estimated 19,715 kWh equivalent per million gallons.

Applying the lower 2004 energy intensity to San Diego data shows that about 50% of total water related energy is due to end-use.

end use SD low copy

Applying the higher 2008 state-wide end-use intensity for the City of San Diego suggests that end use represents about 63% of the total energy use within the water-energy nexus.

SD energy use high copy

Greenhouse Gas Emissions from City Water Demand

Electricity use within sectors of the water-energy nexus is assumed to have a GHG intensity of 800 lbs/mWh. However, the chief greenhouse gas emitter within the water-energy nexus depends on which end-use energy intensity is used. Using the lower value from the local case study indicates that the supply and conveyance sector has a larger than average fraction of greenhouse gas emissions. This aligns with intuition since water must be conveyed a longer than average distance to supply San Diego. Additionally, if the end-use energy intensity from the state-wide study is used, end-use appears to be the largest greenhouse gas contributor. However, uncertainties within the estimates and a dynamically and rapidly changing energy landscape require additional study before concrete conclusions can be made regarding relative energy consumption between the sectors.

City GHG Water low intensity copy

City GHG Water high intensity copy

Also important to note, is that because most end use energy demand is supplied by natural gas, most consumers derive no benefit to their end use energy-related emissions from state-wide electricity standards like the Renewable Portfolio Standard. The following shows a greenhouse gas emissions breakdown that is largely a function of consumers using either electric or natural gas water heaters.

GHG Water end use copy

Policymakers focused on optimizing energy use within San Diego’s water-energy nexus should recognize the while energy use and corresponding greenhouse gas emissions for the supply and conveyance sector are larger than the California state average, relatively little can be done to shorten San Diego’s proximity to water sources, or improve the conveyance system’s overall efficiency. However, local policymakers can have an impact on local end use water consumption and home water appliance energy efficiency.

For more information on end-use, see:

  • NRDC 2004 Case study of San Diego
  • University of California Berkeley, California state-wide Study 2008

World Energy Consumption Will Increase 56% by 2040

Yesterday, the U.S. Energy Information Administration (EIA) released it’s annual International Energy Outlook 2013, in which it projects that world energy consumption will increase 56% by 2040.

The report cites growth in the developing world as a primary cause for the increased energy demand, with over half of the total world increase attributable to China and India.

ScreenHunter_114 Jul. 25 10.30

The fastest-growing energy sources are renewable energy and nuclear power, each growing at a rate of 2.5% per year. However, despite the solid growth in those sectors, fossil fuels are projected to still satisfy almost 80% of the world energy demand in 2040.

ScreenHunter_115 Jul. 25 10.32

Accounting for the fossil fuel consumption projections, the EIA forecasts that given current policies and regulations, greenhouse gas emissions will increase 46% to 45 billion metric tons by 2040, with Asia accounting for 70% of that increase.

ScreenHunter_116 Jul. 25 10.35

For more, see EIA’s press-release presentation, the report available on EIA’s website.

Surviving Sub One-Percent Growth — The Choices Facing the Utilities

Coping with Sub-One Percent Growth

Ahmad Faruqui[1]

The Great Recession ended in 2009.  The economic recovery from the recession has been anemic at best.  Some have even argued that there has been no recovery.

This is particularly true for electric utilities.  Some 41 months later, electric sales have not bounced back to their pre-recession levels.  According to Dr John Caldwell of the Edison Electric Institute, electric sales have bounced back on average within five months during the post-war period.  The longest they have ever taken has been twelve months.  So something different is going on this time.  What could that be and what does it mean for the future of electric utility industry?

At the national level, the U.S. Energy Information Administration (EIA) is predicting growth in the sub-one percent range, down from the pre-recession average of two percent. Last year I did an informal survey of load forecasters around the country.  The consensus was that sales growth would range between 0.7 to 0.9 percent over the next several years.  One utility stated recently that it did not expect to get to pre-recession levels by 2019; another stated by 2024.

I believe three primary causes underlie the slowdown in growth. First, there has been a shift in consumer psychology.   A new generation of consumers armed with new values and new technologies is consuming less.  And the older generation has become more cost-conscious due to continued economic uncertainty.

Second, many utilities are increasing their spending on energy efficiency technology, prompted by governmental directives. Third, states and the federal government continue to push ahead with aggressive revisions of codes and standards, driven in most part by environmental concerns.

And two new forces are emerging on the horizon.  First, distributed generation, led by rooftop solar and supplemented by micro-turbines.  Second, fuel switching away from electricity, driven by the fracking revolution which has dropped oil and gas prices.

A few years ago, Brattle estimated that the electric utility industry will need to invest $1.3 trillion on upgrading and modernizing its transmission and distribution infrastructure.  Additionally, power plants that burn fossil fuels and notably coal-fired generation units will have to make modifications to reduce the emissions of carbon dioxide.  Where will the money come from to pay for all this investment at a time sub-one percent growth?

The challenge is daunting.  Utilities will have to consider many strategies for dealing with it, and once they have agreed on a strategy, they will need to develop the tactics for carrying it out.  While several strategies come to mind, four stand out.  First, stay the course and hope that the slowdown is an aberration.  This runs the risk of standing still at a time of momentous change.  Second, focus on electrifying the economy.  This has been tried before with limited success.  Third, retreat to the safe haven and become a wires-only company.  But unless rate designs change, this too has its limitations.  Most revenue is recovered through volumetric charges.  As sales decline, revenues will decline, even for wires companies.  And, fourth, go on the offensive and become a provider of distributed energy and energy efficiency services to customers.  Since utilities have limited experience in this area, this is also a high risk strategy.   Choosing the optimal strategy will require careful thinking about the future and laying out one’s attitudes toward risk.

Regardless of which strategy is chosen, new tactics will have to be developed.  Three come to mind.  First, change rate designs so that fixed costs are properly reflected in them.  This will represent a sea-change since rate designs have been largely volumetric.   Second, redesign forecasting models so they capture changing consumer preferences.  And, third, reinvent the load and market research functions so they can provide the necessary data to run the new forecasting models and support the design and evaluation of a new range of products and services.

Additional information is contained in my paper in Electricity Policy which can be downloaded at this link:


[1] The author, a principal with The Brattle Group based in San Francisco, holds a Ph. D. in economics from the University of California at Davis.  He can be reached at ahmad.faruqui@brattle.com.

The Water-Energy Nexus in California

Image Credit: http://u.s.kqed.net/2012/06/11/WaterPipeline20120611.jpg

Q: Are these pipelines supplying (a) water, (b) energy, or (c) both?
See bottom for answer.

The water-energy nexus has been in the news since the California Energy Commission’s landmark finding in 2005, that water related energy uses account for about 19% of all electricity use and 30% of non-power plant natural gas use in the state.

What does this mean for energy efficiency and greenhouse gas emissions? This is the first of two posts that describe the water-energy nexus in California. The second post will focus on the water-energy nexus at the San Diego regional level.

In general, the water-energy nexus refers to how energy is consumed and embedded within the water use cycle. The CEC uses the chart below to explain the key energy-consuming steps in the water use cycle. Energy use within the water industry is typically separated from energy use by the water customer, known as end-use (green box below). End-use represents the amount of energy used by the customer for heating and pumping water in a home, office or facility.

The CEC estimates that about 19% of total electricity and 30% of non-powerplant related natural gas is used in the following segments: (1) transportation and treatment of water, (2) transportation and disposal of waste water, and (3) end-use heating and consumption. Of this 20% of total electricity and 30% of non-powerplant related natural gas, end-use accounts for about 62% of electricity and 99% of natural gas use. Stated differently, for many Californians, upwards of 88% of energy use within the water-energy nexus is associated with the residential and commercial end-use segment.

Energy Associated with Water Use

Shown below is the total energy (electricity and natural gas) associated with the primary segments of the water use cycle:

ScreenHunter_98 Jul. 08 11.26
End-use represents roughly 88% of the total energy use, by far the largest component of the water use cycle. Accordingly, end-use has the greatest potential for water and energy savings through efficiency measures.
Energy and greenhouse gas policy considerations make it useful to consider energy consumption by energy type. The graph below shows, as stated earlier, that of the 20% of California’s total electricity and 30% of California’s non-powerplant related natural gas, end-use residential and commercial water demand account for about 62% of electricity and almost 99% of natural gas use.

ScreenHunter_94 Jul. 08 11.00

The energy intensity of each segment within the water use cycle is typically represented in kilowatt-hours per million gallons (kWh/MG) of water. The table below shows the energy intensities representing the fundamental elements of the water-energy nexus, excluding end-use, throughout northern and southern California.

Energy Intensities of Segments of the Water Use Cycle (Source) Indoor Uses Outdoor Uses
North. CA South. CA North. CA South. CA
(kWh/MG) (kWh/MG) (kWh/MG) (kWh/MG)
Water Supply and Conveyance 2,117 9,727 2,117 9,727
Water Treatment 111 111 111 111
Water Distribution 1,272 1,272 1,272 1,272
Wastewater Treatment 1,911 1,911 0 0
Regional Total 5,411  13,022 3,500  11,111

Note that water supply and conveyance represents the segment with the the largest difference in energy intensity between northern and southern California. This is a consequence of the extraordinarily long distances water must travel to reach otherwise dry and arid parts of southern California.

The various energy intensities of the water use cycle segments show the opportunity for energy efficiency improvements on a large, state-wide scale. For example, while water treatment facilities are vital and serve many useful ends throughout California, the opportunity for future efficiency gains within existing water treatment facilities are far outweighed by the water supply and conveyance, water distribution, and  wastewater treatment segments of the water use cycle.

The average energy intensities of the water use cycle segments shown above represent a wide range of values found throughout California. The range of energy intensities for each of the water use cycle segments, before losses are considered, is shown below.

 Range of Energy Intensity (kWh/MG)
Low High
Water Supply and Conveyance 0 13,800
Water Treatment 100 100
Water Distribution 1,200 1,200
Wastewater Collection and Treatment 1,100 2,050
Wastewater Discharge 0 400
Recycled Water Distribution 1,200 3,000
(Data Source)

Greenhouse Gas Emissions Associated with Water Use

ScreenHunter_95 Jul. 08 11.05

Embedded greenhouse gas emissions attributed to the various segments of the water use cycle result from combustion of fossil fuels used during electricity generation or while harnessing and consuming natural gas. Accordingly, the charts showing greenhouse gas emissions and energy intensities of the segments of the water use cycle look similar.

Again breaking down the emissions by energy type, we see that emissions associated with natural gas consumption occur almost exclusively at the end-use segment, and emissions associated with electricity are highly concentrated in the supply and treatment segment of the water use cycle.

ScreenHunter_97 Jul. 08 11.10

In California, natural gas consumption associated with water use produces slightly more overall emissions than electricity.

ScreenHunter_100 Jul. 08 11.39

As initiatives like the Renewable Portfolio Standard improve and continue to use renewables to produce cleaner electricity, the fraction of emissions associated with natural gas will continue to grow.

Further, considering that almost all of the natural gas consumption within the water use cycle occurs at the end-use stage, it remains clear that the greatest potential for energy savings as well as greenhouse gas reductions exist within the residential and commercial end-use sector.

For a more indepth look at the water-energy nexus in California, please see the following study: Navigant Consulting, Inc. 2006. Refining Estimates of Water‐Related Energy Use in California. California Energy Commission, PIERIndustrial/Agricultural/Water End Uue Energy Efficiency Program. CEC‐500‐2006‐118.

This brief primer on the water-energy nexus provides a background on how energy moves water in California. In Part II of this series on the water-energy nexus, we will be exploring the issues associated with the water-energy nexus on the San Diego regional level.

Answer to question at the top:

c) When water flows down the slope towards our homes and facilities, it is used to generate hydroelectricity.

Image Credit: http://u.s.kqed.net/2012/06/11/WaterPipeline20120611.jpg

Residential Rates Revisited – Part 3: Legislative Fixes

In Part 1 of this series was a brief retrospective of some of the antecedents of today’s discussion of residential rates in California.  In Part 2, we discussed in more detail the concept of inclining block rates, the policy rationale behind them, and how residential electricity rates look today in California. In the third and final part of this series we will discuss legislative actions to address residential rates.

Increasing Upper Tier Rates and SB 695

In Part 2, we left off with a look at the current residential rate structure for San Diego Gas & Electric customers.  With increases in costs allocated to the upper tiers until the Department of Water Resources bonds are recovered, the upper tiers have grown significantly to the point where the average rates for the upper two tiers are nearly double that of the lower two tiers.

In 2011, then Governor Arnold Schwarzenegger signed into law Senate Bill 695 (Kehoe), which modified the provisions of AB 1x to provide a mechanism to reduce the gap between the lower tiers and upper tiers by allowing a portion of the costs to be allocated to the lower tiers.  The bill, now codified as Public Utilities Code 739.9, stated, among other things, that the California Public Utilities Commission “may… increase the rates charged residential customers for electricity usage up to 130 percent of the baseline quantities, as defined in Section 739, by the annual percentage change in the Consumer Price Index from the prior year plus 1 percent, but not less than 3 percent and not more than 5 percent per year.”

As a result of SB 695, rates for Tiers 1 and 2 have increased slightly in the past couple years.  For example, the figure below shows a comparison between Tiered rates in place in 2001 and current rates.  Tiers 1 and 2 have increased slightly due to the effects of SB 695.  Tiers 3 and 4 have risen proportionately higher because of the AB 1x cap of Tiers 1 and 2.

Effects of SB 695

Arguments For and Against Current Residential Rate Structure

As mentioned in Part 2, there are at least two general policy rationales for inclining block rates:  (1) to encourage conservation, efficiency, and self-generation by sending a price signal to high users and (2) to mitigate the effect of rate increases on lower consuming – presumably lower-income – customers and to ensure that essential uses of electricity remained affordable for all customers. (Borenstein 2008, National Action Plan for Energy Efficiency 2009, Faruqui 2008). Below is a brief look at the arguments for and against the current rate structure.

Here are a few arguments supporting current rates.

  • Use More, Pay More – One argument in favor of current rates is that high consuming customers should pay more than lower using customers.
  • Equity – The lowest consuming customers, who presumably are in lower income categories, should not bear the full effect of cost increases.
  • Price Signals – Supporters of this structure also argue that higher upper-tier rates encourage conservation, efficiency, and distributed generation, such as solar photovoltaics.

And here are a few arguments critical of current rates.

  • Fairness – Critics of the current structure argue that because AB 1x caps Tiers 1 and 2, the higher Tiers are subsidizing the lower Tiers.  In effect, the upper tiers are paying a price for electricity that is higher than the cost to deliver that energy and the lower tier customers are paying a price lower than the cost to deliver energy.
  • Equity – Another argument against current rates is that some lower tier customers are upper-income customers and some higher-tier customers are low-income.  Geography may contribute to this phenomenon:  coastal communities may have lower consumption given the cooler climate.
  • Cost Causation - A central principle of ratemaking is cost causation; that is, charging a rate based the cost incurred to serve a customer or class of customers.  If increased costs to serve tier 1 and 2 cannot be appropriately allocated to those customers, cost causation is not possible.

Even though the arguments presented here are related, it is important to parse them a bit for clarity.  For example, the argument that higher marginal rates encourage efficiency and photovoltaics should be seen as support for inclining-block rates. It is worth having a discussion of whether inclining block rates lead to certain policy outcomes (look for a future blog post on what the literature says about whether inclining block rates encourage efficiency and conservation), but the discussion should not be clouded by the fact that tiers 1 and 2 are capped (a result of AB 1x).  If we agree that inclining block rates are appropriate, a discussion of the rate increases between tiers should follow.  Similarly, the issue of the cap on tiers 1 and 2 may be best discussed separately.  What are the consequences of the cap on equity, cross subsidization, fairness?

On balance, the discussion may come down to whether the benefits of price signals that encourage behaviors and outcomes that support California energy and climate policy outweigh the fairness of upper tiers subsidizing lower tiers. 

Enter AB 327

One important lesson in this saga of residential rates is that it is risky for any legislative body set utility rates by statute.  It is understandable that legislators sought to mitigate an otherwise disastrous situation during the Energy Crisis of 2000-2001; however, it can be difficult to change the law, especially when, as pointed out in Part 2, may result in a rate increase for a significant portion of voters.

The legislature is currently considering AB 327, which takes a different tack from AB1x and SB 695.  It would, among other things, replace the provisions codified by SB 695 (Public Utilities Code 739.9) with language that establishes rate making principles that the California Public Utilities Commission would have to follow when considering changes to residential rates.  The principles included in AB 327 are the same as those guiding the ongoing CPUC rulemaking (Scoping Memo R.12-06-013).

Specifically, the bills states the following:

“739.9. (a) In approving changes to the rates and charges to residential customers for electricity usage pursuant to this part, the [Public Utilities Commission] shall determine that the changes are reasonable, including determining that the changes are necessary in order to ensure that the rates and charges paid by residential customers are fair, equitable, and reflect the costs to serve those customers.

(b) In approving any changes to the rates and charges to residential customers for electricity usage pursuant to this part, the commission shall ensure that the rates are consistent with the following principles:

(1) Low-income and medical baseline customers should have access to enough electricity to ensure that basic needs, such as health and comfort, are met at an affordable cost.

(2) Rates should be based on marginal costs.

(3) Rates should be based on cost-causation principles.

(4) Rates should encourage conservation and energy efficiency.

(5) Rates should encourage the reduction of both coincident and noncoincident peak demand.

(6) Rates should be stable and understandable and provide customer choice.

(7) Rates should generally avoid cross-subsidies, unless a cross-subsidy appropriately supports explicit state policy goals.

(8) Incentives should be explicit and transparent.

(9) Rates should encourage economically efficient decision-making.

(10) Transitions to new rate structures should be accompanied by customer education and outreach that enhances customer understanding and acceptance of the new rates, and should minimize and appropriately consider the bill impacts on customers associated with the transition.

(c) By no later than January 31, 2014, the commission shall report to the Legislature its findings and recommendations relating to tiered residential electric service rates pursuant to its Order Instituting Rulemaking in Rulemaking 12-06-013.”[AB 327]

AB 327 has passed out of the Assembly and is making its way through the Senate.  If enacted, it will inform the ongoing Rulemaking (R.12-06-013) at the CPUC.  Note that another bill, SB 743, is also making its way through the legislature. It makes changes to residential CARE rates for low-income customers.  It remains to be seen what the outcome will be from the current effort to revisit residential rates, but it is safe to say that there will be changes to the current structure.