How can Demand Response (DR) resources be compensated at the retail level in light of the D.C. Circuit Ruling on FERC Order No. 745?

shutterstock_64255963On a January 21, 2015, former Federal Energy Regulatory Commission (FERC) Chair Jon Wellinghoff participated in a webinar produced by the Advanced Energy Economy entitled Order 745 and the Future of Demand Response: An Interview with former FERC Chairman Jon Wellinghoff.  During the webinar, Mr. Wellinghoff discussed the D.C. Circuit’s ruling on FERC authority with regards to demand response (DR) under Order 745 (Electric Power Supply Association v. FERC, 753 F.3d 216 (D.C Cir. May 23, 2014)).    Order 745 created market based demand response compensation for DR resources by requiring electric utility and retail market operators to pay the market price or locational market price (LMP) when load reductions contribute to balancing supply and demand avoiding the need for additional generation.  The D.C. Circuit found that Order 745 directly regulates the retail market and that the Federal Power Act unambiguously restricts the FERC from “directly regulating a matter subject to state control, such as the retail market.” (Electric Power Supply Ass’n, 753 F.3d 216, 222-224).  The court held that the FERC consequently exceeded its statutory authority in promulgating Order 745 requiring compensation for DR resources in wholesale bulk energy markets.  This decision is being appealed to the U.S. Supreme Court and is currently stayed.

Mr. Wellinghoff and Jon Tong proposed the creation of an independent distributed system operator (IDSO) to help the retail distribution system manage distributed generation resources (DER) such as DR with a market based approach (Public Utilities Fortnightly, August 2014, p. 19).  During the webinar, Mr. Wellinghoff again advocated for the creation of IDSOs to help manage these resources at the distribution level, which brought to mind interesting questions:  First, how can DR resources be compensated at the retail distribution level to ensure that DR resources and other DERs are correctly and cost effectively procured, used, and valued? Second, what will be the major driver for DR at the retail distribution level?

These questions are premised on the need to compensate DR resources for services rendered to the grid and the fact that there is nothing comparable to wholesale transmission markets such as PJM driving the creation of DR resources.  If the U.S. Supreme Court does not hear the case or upholds the Electric Power Supply Association decision, aggregated DR resources that provide services at the wholesale transmission level cannot receive compensation within existing wholesale markets.   This could leave retail distribution as the likely place for a compensation mechanism for DR resources.  Compensation for DR can be achieved through several paths at the distribution level, including creating a DR compensation tariff, mandating procurement of DR through existing integrated procurement processes, or through systemic changes such as creating a distribution level market under an IDSO.

In California, tariffs serve as the most defined mechanism for compensation under current California Public Utilities Commission (CPUC) authority.  The CPUC can act through its rule making process to create a mechanism for investor owned utilities (IOUs) to compensation DR resources for services to the IOU.  However, it remains unclear whether tariffs are a sufficient tool to effectively incorporate DERs into the distribution system and then into the wholesale system.  The CPUC can also mandate that IOUs procure specified amounts of DR as a preferred resource under California’s Loading Order through their long-term procurement processes.  Southern California Edison’s recent Long-Term Procurement for Local Capacity process to replace capacity lost from the retirement of the San Onofre Nuclear Operations Station (CPUC D. 14-03-004) represents this type of process and allowed the IOU to procure preferred and non-preferred resources under a request for proposal (RFP) process.  Finally, the California Legislature could pass a bill authorizing the CPUC to create a market or IDSO to expand, integrate, and optimize DERs such as DR.  The CPUC has little to no experience creating and regulating markets making it unclear whether this mechanism is viable.

The need to accurately and fairly compensate resources that provide services at the distribution and transmission levels grows with the interconnection of more distributed energy resources, increasing participation in the electric market by retail customers, the ongoing debate over how utilities and the grid should operate, and the decarbonization of the grid under the U.S. EPA’s proposed Clean Power Plant Rule and California’s Cap and Trade program.  If resources like DR cannot receive compensation at the transmission level than a mechanism at the distribution level could be an option to provide compensation for the services that they provide.

The need for such a mechanism at the distribution level becomes clearer if the D.C. Circuits’ ruling stands.

Note: Jon Wellinghoff and Lorenzo Kristov (CA ISO) spoke about the distribution system operator concept at the 6th Annual Climate and Energy Law Symposium in November 2014. To see the webcast of these talks, see the USD School of Law’s webpage. Mr. Wellinghoff participated in the morning keynote panel. Mr. Kristov was the third speaker on the first panel.

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How to Allocate GHG Emissions Reductions Among Mitigation Measures


Climate planning is a relatively new science.  And like all sciences still in their infancy, numerous methodologies exist for accomplishing essentially the same task.

There are many aspects to developing a climate plan, however aspects fundamental to all climate plans include:

  1. developing an inventory of greenhouse gas emissions for a given jurisdiction,
  2. identifying which federal, state, and local greenhouse gas mitigation measures to include in the climate plan,
  3. setting realistically achievable greenhouse emissions reductions targets,
  4. determining how much each mitigation measure contributes to reaching the targets,
  5. and finally developing an implementation and monitoring strategy.

EPIC has just released a paper focusing on the fourth step.  Properly determining how much each mitigation measure contributes to reaching the greenhouse gas reduction targets is a very important step, and prone to modeling mistakes.

Climate planning documents regularly feature forecast greenhouse gas emissions curves that just barely hit a desired future emissions target. Further, interested parties frequently and contentiously debate the underlying assumptions that comprise individual mitigation measures out to the very last decimal. For these reasons, insuring that the affects of each greenhouse mitigation measure are properly accounted for is crucial.

A commonly used method for measuring greenhouse gas emissions is to multiply the total level of a particular activity (e.g., electricity consumption) by an emissions factor associated with the same activity (e.g. lbs CO2e/MWh). While this relation is efficient at measuring total GHG emissions, it has limitations when used to determine emissions reductions.

Here’s the question:

How should emissions reductions be allocated between two or more mitigation measures that simultaneously reduce overall greenhouse gas emissions, where some measures affect the total level of a particular activity (e.g., electricity consumption), and other measures affect the emissions factor (e.g. lbs CO2e/MWh)?

Addressing this problem is the subject of EPIC’s most recent technical working paper.

A seemingly natural solution to this problem is to calculate the effects of all the various mitigation measures sequentially. This method leads to the correct answer for total greenhouse gas emissions reductions, but will lead to incorrect results for the emissions reductions attributable to each individual mitigation measure. Indeed, this method will yield emissions reductions allocations that are wrong by ±10-15% for certain mitigation measures.

EPIC’s latest paper provides a solution to this problem within the electricity sector. In the paper we derive a refined methodology that minimizes methodological errors in allocating greenhouse gas emissions reductions, without overly complicating the calculation procedure.

Be on the lookout for a complimentary paper focusing on the transportation sector to be released soon.

Please feel free to contact EPIC with any questions or comments.

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Addressing the Role of Electric Vehicles in Greenhouse Gas Reduction: California State Legislative Action

carThis is the first post in a series looking at legislative and regulatory action addressing Electric Vehicle (EV) greenhouse gas (GHG) emission reductions. This first post focuses on state legislative action.

California depends on petroleum for 92% of its transportation fuel needs. Transportation accounts for 36% of California’s total GHG emissions with passenger vehicles accounting for 25.8% of total GHG emissions in the state according to the California Energy Commissions 2014 Draft Integrated Energy Policy Report Update. The transportation sector presents a unique opportunity for regulatory stakeholders to advance technology, policy, and public attitude to reduce GHG emissions.

GHG reduction mandates come from both state and federal authority. AB 32, or the California Global Warming Solutions Act, was passed in 2006 to address the adverse impacts of anthropogenic climate change in California. AB 32 lists the potential adverse impacts as: air quality problems, a reduction in the quality and supply of water to the state from the Sierra snowpack, a rise in sea levels, damage to marine ecosystems and the natural environment, and an increase in the incidences of infectious diseases, asthma, and other human health-related problems. To avoid these negative consequences, AB 32 sets the goal of reducing GHG emissions to 1990 levels by 2020 with Executive Order S-3-05 and B-16-2012 setting a goal of reducing GHG emissions to 80% below 1990 levels by 2050. The Federal Clean Air Act also drives an 80% reduction in emissions from oxides of nitrogen (NOX) from current levels by 2023.

The state legislature created the Alternative and Renewable Fuel and Vehicle Technology Program (ARFVTP) under AB 118 (Chapter 750, Statutes of 2007), amended the program under AB 118 (Chapter 313, Statutes 2008), and reauthorized the program under AB 8 (Chapter 401, Statutes of 2013) to help the California Energy Commission facilitate electric vehicles (EVs) as one viable solution for the reduction of GHG emissions in the transportation sector. While pure EVs have no tailpipe emissions, the overall GHG emissions of driving an EV depends on how the electricity is generated, which is largely dictated by which regional grid electricity is drawn from. For example, charging an EV in California, part of one of the cleanest electricity regions, yields GHG emissions equivalent to a 70 mpg gas-powered vehicle.

Recognizing the potential for EVs to further the goal of AB 32, achieve Executive Order B-16-2012’s goal of 1.5 zero-emission vehicles by 2025, and to cap off National Drive Electric Week, Governor Brown signed several bills during the 2014 legislative session relating to GHG reductions in the transportation sector:

1. AB 1721 grants free or reduced-rates in high-occupancy toll (HOT) lanes to clean air vehicles.
2. AB 2013 increases the number of advanced technology partial ZEVs that may be allowed in high-occupancy vehicle lanes to 70,000, regardless of how many people occupy the vehicle.
3. AB 2090 repeals the level of service requirements on HOT lanes for the San Diego Association of Governments and the Santa Clara Valley Transportation Authority, and directs them to work with the California Department of Transportation to develop appropriate performance measures.
4. AB 2565 requires commercial and residential property owners to approve installation of an EV charging station by renters for any lease executed, renewed, or extended on and after July 1st 2015, so long as the station meets certain requirements.
5. SB 1275 creates the Charge Ahead California Initiative, which establishes its own goal of at least 1 million ZEVs and near-ZEVs in California by January 1, 2023. The California Air Resources Board (ARB) will prepare a funding plan that includes a market and technology assessment, assessments of existing zero and near-zero emission funding programs, and a focus on programs that increase access to disadvantaged, low-income, and moderate-income communities and consumers. SB1275 also builds on the Clean Vehicle Rebate Project (CVRP) that offers rebates for the lease or purchase of qualified vehicles. Rebates of up to $2,500 per light-duty vehicle are available for individuals, nonprofits, government entities, and business owners who purchase or lease a qualified vehicle. No later than June 30, 2015, the ARB shall adopt revisions to ensure that rebate levels can be phased down in increments based on cumulative sales levels, eligibility is based on income, and consideration of the conversion to prequalification and point-of-sale rebates or other methods to increase participation rates.

With the legislature’s continued drive to decrease GHG emissions, there is an ever-evolving need to address issues at the regulatory and technical level to develop the EV market and deploy needed infrastructure. Future posts will look at how the California Independent System Operator (CAISO), California Energy Commission (CEC), California Public Utilities Commission (CPUC), California Governor’s Office, and the California Air Resources Board (CARB) are working to address and solve these issues.

Katrina Wraight coauthored this blog post.  Katrina is a legal intern for EPIC and a second year law student at the University of San Diego School of Law.

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Senator Pavley Introduces SB 32 (2015-2016) to Amend the AB 32 California Global Warming Solutions Act of 2006

The California Global Warming Solutions Act of 2006, generally known as AB 32, mandated that the California Air Resources Board (CARB) adopt both statewide greenhouse gas (GHG) emissions limits equivalent to the statewide GHG emission level in 1990 and rules and regulations to achieve maximum, technologically feasible, and cost-effective GHG emissions reductions. AB 32 mandated that California achieve the adopted GHG emission reductions by 2020.

On December 1, 2014, Senator Pavley introduced SB 32 requiring the CARB to adopt a statewide GHG emission limit equivalent to 80% below the 1990 level to be achieved by 2050. The bill authorizes the CARB to adopt interim GHG emission level targets for 2030 and 2040.

The bill explicitly expresses “the intent of the Legislature for the Legislature and appropriate agencies to adopt complementary policies that ensure long-term emission reductions adopted pursuant to subdivision (b) of Section 38550 [that] advance all of the following:

(1) Job growth and local economic benefits in California.

(2) Public health benefits for California residents, particularly in disadvantaged communities.

(3) Innovation in technology and energy, water, and resource management practices.

(4) Regional and international collaboration to adopt similar greenhouse gas emissions reduction policies.”

This bill would codify former Governor Schwarzenegger’s Executive Order No. S-5-05 2050 emission reduction targets.   If signed into law, this bill will remove any uncertainty with regard to the long-term emission reductions for the state that have created long-term planning uncertainty for local governments and regional planning entities (See our previous posts on: Regional Transportation Plan Litigation and Climate Action Plan Litigation). This bill will be taken up by the Legislature at the beginning of the 2015-2016 legislative session.

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Regional Transportation Plan Litigation: Fourth Appellate District Finds SANDAG Transporation Plan Violated CEQA

In Cleveland National Forest Foundation v. SANDAG, a three-judge panel from the California Forth Appellate District heard SANDAG’s appeal of a trial court ruling on the first Regional Transportation Plan put forward by one of the state’s nine regional planning entities to comply with SB 375. The trial court found that SANDAG abused its discretion under CEQA with its Environmental Impact Report (EIR) analysis of its 2050 Regional Transportation Plan. The Cleveland National Forest Foundation, the Sierra Club, and the State of California filed cross-appeals expanding the review of the original decision to include additional CEQA challenges. Justice McConnell – with a concurrence from Justice Irion – issued a two to one opinion on November 24, 2014 finding that the EIR violated CEQA. The opinion expanded the CEQA analysis resulting in a modified judgment. Justice Benke drafted a scathing dissent finding substantial evidence to uphold SANDAG’s EIR and no basis for an executive order to become a mandate or CEQA threshold of significance where the legislature has not expressly created such requirements.

The trial court granted the original petition in part finding that the EIR failed as an information document for not analyzing the inconsistency between the state’s climate policy under Executive Order S-3-05 and the transportation plan’s greenhouse gas (GHG) emission impacts after 2020.   The trial court also found that the transportation plan EIR failed to adequately address mitigation measures for GHG emission impacts.

On appeal, the court found that SANDAG abused its discretion by approving an EIR that lacked a consistency analysis with the overarching emission reduction goals that form state climate policy out to 2050. The court combined the emission reduction targets from Executive Order S-3-05, AB 32, SB 375, and the California Air Resources Board’s (CARB) regional emission reduction targets to provide a state climate policy that extends out to 2050.  The court found that SANDAG’s analysis that GHG emissions will increase between 2020 and 2050 violated state climate policy and CEQA.

This places the burden on SANDAG to forecast regional emission reduction targets out to 2050 using only the S-3-05 statewide goal because the SB 375 CARB regional emission reduction targets only extend to 2035.   The court also found that criteria used to determine significance of impact must be consistent with the state climate policy and cannot necessarily depend on only using the expressed three significant thresholds found in CEQA Guideline Section 15064.4.

Next, the court found that the EIR must discuss mitigation alternatives that are both (1) substantially lessen GHG emission impacts and (2) be feasibly implemented.   The court reviewed the three thresholds used to determine significant impact and the six mitigation alternatives for substantial evidence.   The court stated that the first three mitigation alternatives deemed feasible by SANDAG required no effort to implement and provided no guarantee or concrete steps towards emission reductions and were therefore questionable as to “whether these measures even qualify as mitigation measures.”   The court further stated that the three infeasible measures included in the EIR were illusory because these measures were difficult to impossible to enforce and required implementation resources not readily available.   The court concluded by referencing potential mitigation alternatives from SANDAG’s Climate Action Strategy that may substantially lesson greenhouse gas emissions and can be feasibly implemented.

The court then took up the cross-appeals finding that:

  • Transportation Planning project alternatives should account for long-term planning concerns and reduce total vehicle miles traveled consistent with SANDAG’s Climate Action Strategy;
  • SANDAG’s omission of toxic air contaminants (TAC) exposure must be supported by substantial evidence or TAC baseline exposure information must be provided in its EIR;
  • Plan level air quality impact review must correlate adverse air quality impacts to resulting adverse health impacts to meet substantial evidence;
  • Program level air impact analysis and enforceable mitigation measures cannot be deferred without a showing of substantial evidence that the measures are infeasible; and
  • SANDAG must use best practically available scientific information regarding resource areas and farmland in the region.

Finally, the court dismissed the last challenge to the EIR analysis on agricultural land impacts because the plaintiffs failed to exhaust their administrative remedy on these issues.

The SANDAG Board of Directors nearly unanimously approved appealing the decision to the California Supreme Court on December 5, 2014.

Posted in CEQA, Greenhouse Gas, Litigation, Transportation | 1 Comment

Climate Action Plan Litigation: San Diego County Appeals Fourth Appellate District CEQA Decision

shutterstock_4540564In Sierra Club v. County of San Diego a three-judge panel of the Fourth Appellate District heard an appeal by the County of San Diego of a superior court finding that the County violated CEQA by not complying with the requirements of its own Climate Change Mitigation Measure CC-1.2 (Mitigation Measure CC-1.2) in its Climate Action Plan (CAP).   The superior court based its decision on the finding that the CAP lacked enforceable GHG reduction measures that would achieve the specified emission reductions under Mitigation Measure CC-1.2.

The appellate court affirmed the lower court decision.  The Court of Appeal dismissed the County’s first claim that the original cause of action was barred by the statute of limitations and moved to its CEQA analysis. The court’s CEQA analysis first found that the CAP violated CEQA as mitigation for a plan-level document because the CAP failed to adopt a CAP that complied with the requirements of Mitigation Measure CC-1.2.  The court found that the CAP lacked enforceable greenhouse gas (GHG) emissions required by the mitigation measure, lacked detailed deadlines for GHG reduction, and the County lacked evidence to support its assertions that the CAP mitigation would achieve GHG reductions. In essence, once the County incorporated Mitigation Measure CC-1.2 in its general plan EIR the implementation of the mitigation measure became necessary unless the County instituted a review of the need for the mitigation and a stated reason supported by substantial evidence for removing the mitigation.

Second, the court found that the County did not proceed in the manner required by law by failing to analyze the environmental impact of the CAP and Threshold project. The court found that the County erroneously relied on the EIR of the general plan update when adopting the CAP and Threshold project.   Third, the court found that the County failed to proceed in a manner required by law when it did not incorporate mitigation measures directly into the CAP as a plan-level document. Fourth, the court found that substantial evidence supported the lower courts decision that an EIR was required for the CAP and Threshold project. The court found that the County’s failure to comply with Mitigation Measure CC-1.2, AB 32, and Executive Order No. S-3-05 supported the conclusion that the CAP and Threshold Project “will have significant, adverse environmental impacts that have not been previously considered, mitigated, or avoided.”   This finding is consistent with other appellate rulings that that local and regional climate action plans or regional transportation plans (See Cleveland National Forest Foundation v. SANDAG) must be consistent with an agency’s own mitigation or strategic documents in the administrative record and achieve enforceable emission reductions as required by AB 32, SB 375, and Executive Order No. S-3-05.

The San Diego County Board of Supervisor voted on December 2, 2014 to submit a petition to review the appellate court decision as reported by the UT-San Diego.

Posted in CEQA, Energy, Greenhouse Gas, Litigation | 1 Comment

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

solarpanels_roof_closeup-791688AB 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.

Posted in Energy, Renewable Energy | 2 Comments