AB 2188: Streamlining Permitting for Small Residential Rooftop Solar Energy Systems at the Local Level under the Solar Rights Act

AB 2188, signed into law by the Governor on September 21, 2014 (Chapter 521, Statutes 2014), amends the Solar Rights Act implementing, among other requirements, the first codified streamlined permitting requirement for small rooftop solar energy systems at the local level in California. The bill builds upon existing requirements for local governments that:

  • Discourage passage of unreasonable restrictions on solar energy systems (Government Code Section 65850.5);
  • Require use of non-discretionary permitting process (Government Code Section 65850.5(a)-(b) and Health and Safety Code Section 17959.1(a)-(b));
  • Require demonstration of compliance when seeking state-sponsored incentives but leaves discretion to state (Civil Code Section 714 (h)(1)).

AB 2188 applies to all city, county, or city and counties responsible for permitting solar energy systems. The bill mandates that all cities, counties, or cities and counties pass an ordinance on or before September 30, 2015 to create an expedited, streamlined permitting process. Each jurisdiction must substantially conform its expedited, streamlined permitting process with recommendations for expedited permitting, including the checklist and standard plans contained in the most current version of the California Solar Permitting Guide adopted by the Governor’s Office of Planning and Research. The bill allows for modifications to the checklist and standards found in the guidebook for unique climatic, geological, seismological, or topographical conditions.

The bill also requires the adoption of a checklist that includes all requirements with which a small solar energy system must comply to be eligible for expedited review.  Systems that satisfy the checklist requirements will be deemed complete and must receive permit approval under the statute.   Permit approvals cannot be conditioned upon the approval of an association (i.e. an HOA) and a jurisdiction must provide a written notice detailing all deficiencies in an application if deemed incomplete.

The bill limits the streamlined, expedited permitting process to eligible small residential rooftop solar energy systems – as defined – that meet adopted checklist requirements. The bill defines small residential rooftop solar energy system to mean:

  • A solar energy system that is no larger than 10 kilowatts alternating current nameplate rating or 30 kilowatts thermal.
  • A solar energy system that conforms to all applicable state fire, structural, electrical, and other building codes as adopted or amended by the city, county, or city and county and paragraph (3) of subdivision (c) of Section 714 of the Civil Code.
  • A solar energy system that is installed on a single or duplex family dwelling.
  • A solar panel or module array that does not exceed the maximum legal building height as defined by the authority having jurisdiction.

Systems that meet this definition and the adopted checklist requirements are eligible to participate in a local jurisdiction’s expedited, streamlined permitting process for solar energy systems.

The bill creates the following additional major changes with regards to the expedited permitting process:

  • Requires that the checklist and other required documents be published on a publicly accessible website;
  • Requires that a jurisdiction allow electronic submission of an application and documents by email, the internet, or fax;
  • Requires that a jurisdiction allow electronic signatures on all required documents in lieu of wet signatures (Note: If this is not possible, a jurisdiction must state the reason why in its ordinance);
  • Requires a single inspection done in a timely manner (assuming that the jurisdiction has a consolidated inspection process);
  • Authorizes subsequent inspections where a system fails inspection;
  • Requires that a building official make a finding based upon substantial evidence that a system has a specific, adverse impact upon public health and safety to require an applicant to apply for a use permit;

Finally, the bill makes the following majors changes to the Solar Rights Act with regards to what constitutes a reasonable restriction on a solar energy system and the time frame that an association (i.e. a HOA) has to approve an application:

  • Solar Water Heater Systems: Changes the definition of “Significantly” in reference to determining whether a reasonable restriction significantly increases a cost or decreases efficiency for solar water heating systems. Significantly now means an amount exceeding 10% of the cost of the system, but in no case more than $1,000.00, or decreasing efficiency by an amount exceeding 10%;
  • Photovoltaic Systems: Changes the definition of “Significantly” in reference to determining whether a reasonable restriction significantly increases a cost or decreases efficiency for photovoltaic system. Significantly now means an amount exceeding more than $1,000.00 over the original system cost, or decreasing efficiency by an amount exceeding 10%; and
  • Shortens the time period during which an association, as defined, must deny an application in writing from 60 days to 45 days.

AB 2188 can be accessed on the California Legislative Information website.

Petitions to Re-Hear Denied: The Low Carbon Fuel Standard Still Stands Intact

(Many thanks to Joseph Mandry for his research and writing for this post).


On January 22, 2014, the Ninth Circuit Court of Appeals denied petitions to rehear Rocky Mountain Farmers Union v. Corey, en banc. Rocky Mountain Farmers Union v. Corey, 740 F. 3d 507 (9th Cir. 2014). Two opinions, a dissent and a concurrence, accompanied the denial.

            In response to the court’s decision to deny a rehearing of Corey, Circuit Judge M. Smith wrote in dissent that Corey was decided wrongly for two reasons, and thus, the petition for rehearing en banc should have been granted. Circuit Judge Smith first argued that majority opinion in Corey upheld a “protectionist regulatory scheme that threaten[ed] to Balkanize [the] national economy.” Judge M. Smith said further that the majority was impermissibly nullifying the constitutionally imposed constraints on California’s ability to discriminate against out-of-state producers of ethanol. Judge Smith’s second reason for dissenting was that the majority in Corey “sanction[ed] California’s clear attempt to project its authority into other states.” Judge Smith argued that, by allowing California’s low-carbon fuel standard to survive, the majority’s holding “stand[s] in open defiance” of controlling Supreme Court precedent and renders the dormant Commerce Clause “toothless” in the ninth circuit.

            Circuit Judge Gould offered a concurring opinion, which countered the dissent with several observations. Judge Gould first noted that the dissent was merely using “alarmist rhetoric” that misunderstood the LCFS legislation. Next, Judge Gould accused the dissent of misunderstanding the majority holding in Corey. Rather than uphold the LCFS, as the dissent contended, the disposition in Corey remanded the case back to the district court to apply either strict scrutiny or the Pike balancing test; the court had not conclusively endorsed the LCFS. Third, Judge Gould reiterated that, in his opinion, the LCFS did not facially discriminate against out-of-state ethanol producers because the LCFS made geographic distinctions based on carbon impact and intensity of various fuels, rather than based purely on state-of-origin. Judge Gould then speculated that the dissenting opinion’s tone and substance might have been aimed mainly at encouraging Supreme Court review. Finally, Judge Gould responded to the dissent’s accusation that the majority in Corey opposed binding Supreme Court precedent by citing Supreme Court precedent that supported the majority’s contention in Corey that California could permissibly regulate conduct within its borders with the goal of influencing out-of-state behavior.

                        On June 30, 2014, the Supreme Court of the United States denied certiorari to hear Rocky Mountain Farmers Union v. Corey. No opinion accompanied the Supreme Court’s denial of certiorari. As with the Ninth Circuit’s denial to rehear Corey en banc, the Supreme Court’s denial of certiorari does not change the legal status of California’s LCFS.

The LCFS remains legally intact and enforceable. If the legal status of the LCFS is to change from its current state, it will be because of the district court’s further factual findings and application of either strict scrutiny or the Pike balancing test.

The Eastern District Court of Fresno has set a scheduling conference for August 28, 2014.

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.