Half-Empty Planes: Utilization Rates for California’s Electric Grid Part I

The electric grid is designed to handle the highest demand expected in a given period, commonly referred to as peak demand. Depending on many factors, the time needed for peak demand and period of high demand approaching peak can be a small percentage of the hours in a year. California utilities generally hit their peak level of demand in the summer, when temperatures are hot and air conditioners are running. But for most of the rest of the year, demand is relatively low. This means that there is capacity in the grid that is not used much of the time. To measure how much of this peak capacity is used on average we use asset utilization rates – or the more wonky term, load factor. This is not a new concept but one that rarely comes up in energy policy conversations.

We do hear about demand reduction, demand response, and load shifting. These important concepts are implemented through programs and tariffs offered by California utilities. They may also come up in relation to rate structures like time-of-use rates or the contribution of solar energy production or electric vehicles toward peak needs. These all are important topics in their own right but ultimately contribute to and affect overall grid asset utilization rates. 

What is Load Factor?

To understand the role of asset utilization in the electric industry, it is important to distinguish between energy and demand. Demand is a measure of capacity (in megawatts, or MW) and refers to an instantaneous level of power. Energy is a rate that measures the amount of MW consumed over time (megawatt-hours, or MWh). A water analogy is helpful to illustrate the difference. Imagine a water pipe connected to your home or business. The diameter of the pipe is analogous to demand (MW) and the amount of water flowing through he pipe is analogous to energy (MWh). If you need a lot of water, you may need a larger pipe, so more water can flow through. Now expand this analogy to an entire utility service territory. The size of the pipe is analogous to the peak capacity (MW) of an electric grid. That capacity determines how much water (or energy in our case) can flow through the pipe.

So, load factor is the ratio of average demand to peak demand. As a measure of asset utilization, a higher number is better. That means fewer assets are idle over time. Imagine a plane flying from San Diego to San Francisco 3 times a day. Now assume the plane has 200 seats (peak demand) and on average over the year it only fills 100 (average demand) of those seats on each flight. At the end of the year the plane was never more than half full on average. The load factor in this case would be 50%.

In the electric industry load factor compares average demand to the peak demand as measured in megawatts (MW). In California load factors for the three investor-owned utilities (IOU) are in the low 50% range. This means that average demand is half of the peak. Put another way, peak demand is twice average demand. So, much of the time we have grid capacity not being used, much like those empty seats in the plane example above.

Ultimately, load factor is important because it affects customer rates. As mentioned above, the electric grid is designed to serve load reliably. That means the physical grid must be sized in a way that can accommodate the peak demand – the one moment of when demand on the grid reaches its highest point. In general, as demand grows, so grows the physical grid. And, because investor-owned utilities earn a regulated rate of return on their rate base, and because that rate base includes the physical assets of the utility, the size of the physical grid affects utility costs, which in turn affects rates.

Load Factors for California’s Investor-owned Utilities

Load factor for California’s IOUs varies yearly but over the past 20 years the general trend has been declining – that is, peak demand is growing faster than average demand. Figure 1 plots load factors the three California IOUs. Generally, load factors declined through 1998 converging between 50-55. Shortly thereafter load factor increased in part due to the decrease in demand during the California Energy Crisis. SDG&E’s load factor spiked at this time with a load factor above 65, which likely is attributed to the fact that SDG&E service territory was the first to have divested itself of generation assets and to have market based rates under the industry restructuring rules at the time. Then a steady decline ensued as historic energy patterns resumed. Then lower demand due to the economic downturn seemed to have caused another uptick. The figure also shows that load factors differ fairly significantly among the IOUs.

Figure 1 Load Factor Trends for California Investor-Owned Utilities

Load Factor Trends

Figure 2 shows the relationship between load factor, average demand, and net peak demand for the SDG&E service territory. In periods when net peak demand declined faster than average demand load factor increased. This occurred in the early 1990s and then again in the late 1990s to early 2000s. Since about 2000 peak demand has risen more than average demand, therefore load factor has decreased.

Figure 2 Relationship between Load Factor, Average Demand, and Net Peak Demand

Relationship Chart

Optimizing Load Factor

Can California IOUs do better than a 50% load factor? What is the optimal load factor? In Part II, we will discuss the factors that contribute to load factor and consider the effect of California’s aggressive greenhouse gas policies.

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June 2015 Legislative Update: Energy Procurement, Net Energy Metering, Electric Vehicle Chargers, and Green House Gas (GHG) regulation.

A. Direct Access (DA): SB 286

SB 286 would require a 2nd phase-in period to expand individual retail nonresidential end-use customers direct transactions over a period not to exceed 3 years, raising the allowable limit of kilowatthours that can be supplied by other providers in each electrical corporation’s distribution service territory by that electrical corporation’s share of an aggregate of 8,000 gigawatthours. The bill would require that all associated retail sales be procured from eligible renewable energy resources with enforcement under the California Renewables Portfolio Standard Program. Electrical corporation would continue to provide direct access customers with support functions through its own employees, subject to certain exceptions. Finally, the bill would prohibit an electric service provider from offering consolidated billing beginning January 1, 2016.

B. Net Energy Metering (NEM): SB 550

Existing law provides that an electric utility that is not a large electrical corporation is not obligated to provide net energy metering when the combined total peak demand of all electricity used by eligible customer-generators in the service area exceeds 5% of the aggregate customer peak demand of the electric utility. Existing law exempts from the net energy metering requirements a local publicly owned electric utility that serves more than 750,000 customers and that also conveys water to its customers. SB 550 would delete the exemption for those local publicly owned electric utilities and define the “aggregate customer peak demand” for the purposes of calculating the net energy metering program limit for electric utilities that are not large electrical corporations. This bill would require those electric utilities to file with the Energy Commission and to make available to the public a quarterly report detailing their progress towards the program limit. The bill would require the Energy Commission to post on its Internet Web site data detailing the progress towards their program limit.

C. Streamlined Permitting Processes for Electric Vehicle Charging: AB 1236

The bill would require that a local jurisdiction adopt an ordinance, by September 30, 2016, that creates an expedited and streamlined permitting process for electric vehicle charging stations to implement consistent statewide standards to achieve the timely and cost-effective installation of electric vehicle charging stations. The bill uses similar language and requirements as AB 2188 that implemented streamlined solar permitting from last session.

D. Renewable Resource Procurement and GHG Emissions: AB 197

This bill would require the California Public Utilities Commission (CPUC), in adopting the RPS process that orders and selects least-cost and best-fit eligible renewable energy resources, to include consideration of any statewide greenhouse gas emissions limit established pursuant to the California Global Warming Solutions Act of 2006 and consideration of capacity and essential reliability services of the eligible renewable energy resource to ensure grid reliability. The bill further would require the commission to ensure that a retail seller of electricity consider the best-fit attributes of resources types that ensure a balanced resource mix to maintain the reliability of the electrical grid in soliciting and procuring eligible renewable energy resources. The bill would provide revisions to the authority of an electrical corporation to refrain from entering into new contracts or constructing facilities beyond the quantity that can be procured within the electrical corporation’s cost limitation. Finally, the bill would require an electrical corporation or local publicly owned electric utility, in adopting a procurement plan, to consider any statewide greenhouse gas emissions limit established pursuant to the California Global Warming Solutions Act of 2006 and consider capacity and essential reliability services to ensure grid reliability.

E. Clean Energy and Pollution Reduction Act of 2015: SB 350

RPS and Public Utility Procurement: This bill would:

  • Express the intent of the Legislature for the purposes of the RPS program that the amount of electricity generated per year from eligible renewable energy resources be increased to an amount equal to at least 50% by December 31, 2030;
  • Require the CPUC, by January 1, 2017, to establish the quantity of electricity products from eligible renewable energy resources be procured by each retail seller for specified compliance periods sufficient to ensure that the procurement of electricity products from eligible renewable energy resources achieves 50% of retail sales by December 31, 2030;
  • Require the governing boards of local publicly owned electric utilities to ensure that specified quantities of electricity products from eligible renewable energy resources to be procured for specified compliance periods to ensure that the procurement of electricity products from eligible renewable energy resources achieve 50% of retail sales by December 31, 2030; and
  • Exclude all facilities engaged in the combustion of municipal solid waste from being eligible renewable energy resources.

Renewable Procurement Plans and Enforcement: This bill would:

  • Require community choice aggregators and electric service providers to prepare and submit renewable energy procurement plans;
  • Revise other aspects of the RPS program, including, among other things, the enforcement provisions and would require penalties collected for noncompliance to be deposited in the Electric Program Investment Charge Fund; and
  • Require the CPUC to direct electrical corporations to include in their proposed procurement plans a strategy for procuring a diverse portfolio of resources that provide a reliable electricity supply.

Actions for Clean Air and Emissions Reductions: This bill would require the CPUC and the Energy Commission to take certain actions in furtherance of meeting the state’s clean energy and pollution reduction objectives.

Actions to Reduce Emissions from transport fuel: This bill would:

  • Require the State Air Resources Board to amend various standards related to emissions from motor vehicles to be in furtherance of achieving a reduction in petroleum use in motor vehicles by 50% by January 1, 2030; and
  • State that it is the policy of the state to exploit all practicable and cost-effective conservation and improvements in the efficiency of energy use and distribution, and to achieve energy security, diversity of supply sources, and competitiveness of transportation energy markets based on the least environmental and economic costs in furtherance of reducing petroleum use in the transportation sector by 50% by January 1, 2030.

Building Standards: This bill would require the Energy Commission, by January 1, 2017, and at least once every 3 years thereafter, to adopt an update to the program in furtherance of achieving a doubling of energy efficiency in buildings by January 1, 2030.

F. California Renewables Portfolio Standard: AB 645

This bill would express the intent of the Legislature for the purposes of the RPS program that the amount of electricity generated per year from eligible renewable energy resources be increased to an amount equal to at least 50% by December 31, 2030. The bill would direct the CPUC, by January 1, 2017, to establish the quantity of electricity products from eligible renewable energy resources to be procured by each retail seller for specified compliance periods sufficient to ensure that the procurement of electricity products from eligible renewable energy resources achieves 50% of retail sales by December 31, 2030, and in all subsequent years. Finally, the bill would require the governing boards of local publicly owned electric utilities to ensure that specified quantities of electricity products from eligible renewable energy resources to be procured for specified compliance periods to ensure that the procurement of electricity products from eligible renewable energy resources achieve 50% of retail sales by December 31, 2030, and in all subsequent years.

G. Unbundled Renewable Energy Credits: AB 1144

This bill would provide that unbundled renewable energy credits under the California Renewables Portfolio Standard Program may be used to meet the first category of the portfolio content requirements if (1) the credits are earned by electricity that is generated by an entity that, if it were a person or corporation, would be excluded from the definition of an electrical corporation by operation of the exclusions for a corporation or person employing landfill gas technology or digester gas technology, (2) the entity employing the landfill gas technology or digester gas technology has a first point of interconnection with a California balancing authority, a first point of interconnection with distribution facilities used to serve end users within a California balancing authority area, or are scheduled from the eligible renewable energy resource into a California balancing authority without substituting electricity from another source, and (3) where the electricity generated that earned the credit is used at a wastewater treatment facility that is owned by a public entity and first put into service on or after January 1, 2016.

H. California Global Warming Solutions Act of 2006 Emissions Limits: SB 32

This bill would require the California State Air Resources Board to approve statewide greenhouse gas emissions limits that are equivalent to 40% below the 1990 level to be achieved by 2030 and 80% below the 1990 level to be achieved by 2050, as specified. The bill would authorize the state board to adopt an interim greenhouse gas emissions level target to be achieved by 2040. The bill also would state the intent of the Legislature for the Legislature and appropriate agencies to adopt complementary policies that ensure the long-term emissions reductions advance specified criteria.

I. California Global Warming Solutions Act of 2006 Regulations: AB 1288

The California Global Warming Solutions Act of 2006 authorizes the Air Resources Board to include the use of market-based compliance mechanisms and to adopt a regulation that establishes a system of market-based declining annual aggregate emissions limits for sources or categories of sources that emit greenhouse gases, applicable from January 1, 2012, to December 31, 2020, inclusive, as specified. This bill would eliminate the program sunset date of December 31, 2020 that limits the applicability of a regulation that establishes a system of market-based declining annual aggregate emissions limits for sources or categories of sources that emit greenhouse gases from January 1, 2012, to December 31, 2020.

J. Climate Change Adaptation: SB 246

This bill would require the Natural Resources Agency, no later than January 1, 2019, to update the 2009 California Climate Adaptation Strategy, require the Governor’s Office of Planning and Research, no later than January 1, 2017, to update the Adaptation Planning Guide, and establish an advisory council to support those goals of the Office of Planning and Research.

K. General Plan Safety Element and Resiliency for Climate Adaption and Resiliency: SB 379

The Planning and Zoning Law requires the legislative body of a city or county to adopt a comprehensive, long-term general plan that includes various elements, including, among others, a safety element for the protection of the community from unreasonable risks associated with the effects of various geologic hazards, flooding, and wild land and urban fires. This bill would, upon the next revision of a local hazard mitigation plan on or after January 1, 2017, or, if the local jurisdiction has not adopted a local hazard mitigation plan beginning on or after January 1, 2022, require the safety element to be reviewed and updated as necessary to address climate adaptation and resiliency strategies applicable to that city or county. The bill would require the update to include a set of goals, policies, and objectives based on a vulnerability assessment, identifying the risks that climate change poses to the local jurisdiction and the geographic areas at risk from climate change impacts, and specified information from federal, state, regional, and local agencies.

L. Public Retirement System Divestiture of Thermal Coal Companies: SB 185

This bill would prohibit the boards of the Public Employees’ Retirement System and the State Teachers’ Retirement System from making new investments or renewing existing investments of public employee retirement funds in a thermal coal company, as defined. The boards would be required to liquidate investments in thermal coal companies on or before July 1, 2017 and, in making a determination to liquidate investments, constructively engage with thermal coal companies to establish whether the companies are transitioning their business models to adapt to clean energy generation. The bill would provide that it does not require a board to take any action unless the board determines in good faith that the action is consistent with the board’s fiduciary responsibilities established in the constitution. This bill would require, on or before January 1, 2018, these boards to file a report to the Legislature and the Governor, containing specified information, including a list of companies of which they have liquidated their investments. Finally, the bill would provide that board members and other officers and employees shall be held harmless and be eligible for indemnification in connection with actions taken pursuant to the bill’s requirements, as specified.

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June 2015 Legislative Update: CPUC, CEC, and Utility Reform

The following sections summarize proposed bills that have passed their house of origin with an emphasis on CPUC, CEC, and Utility reform measures.  Emphasis is given to proposed changes to Ex Parte rules.

A. California Public Utility Commission (CPUC) Reform: SB 48

Changes to CPUC President Authority: This bill would repeal the president of the Public Utilities Commission’s authority to direct the executive director, the attorney, and other commission staff and delete the authority of the president to direct or authorize the executive director and attorney to undertake certain actions, thereby requiring that they be directed or authorized to undertake those actions by the commission.

Rules Governing CPUC Session: This bill would require that the commission hold its sessions at least once in each calendar month in the City and County of San Francisco or the City of Sacramento and would require that the commission hold no less than 6 sessions each year in the City of Sacramento,

Administrative Code of Ethics: This bill would make the Administrative Adjudication Code of Ethics applicable to adjudication hearings of the commission.

Commission Function and Operation: The bill would:

  • Except for in adjudication cases, require the commission, before instituting an investigation or proceeding on its own motion, where feasible and appropriate, to seek the views of those who are likely to be affected by a decision in the investigation or proceeding, including those who are likely to benefit from, and those who are potentially subject to, a decision in that investigation or proceeding;
  • Require the commission to post all prepared written testimony submitted in its formal proceedings on its Internet Web site;
  • Expand the requirement that the required commission work plan describe in clear detail the scheduled proceedings that may be considered by the commission during the calendar year to include all proceedings and not just rate making proceedings;
  • Require that the work plan include performance criteria for the commission and executive director and evaluate the performance of the executive director during the previous year based on the criteria established in the prior year’s work plan;
  • Delete the requirement that the report include the number of cases where resolution exceeded the time periods prescribed in scoping memos and instead would require the report to describe the commission’s timeliness in resolving cases and include information on the disposition of applications for rehearings; and
  • Require that the report include the number of scoping memos issued in each proceeding and to include the number of orders issued extending the statutory deadlines for all adjudication, rate setting, and quasi-legislative cases.

Application of the Bagley-Keene Act: The bill authorizes an action to enforce the requirements of the Bagley-Keene Open Meeting Act or the California Public Records Act to be brought against the commission in the superior court.

B. California Public Utilities Commission Regulation of Officials and Ex Parte Rules: SB 660

Changes to CPUC President Authority: This bill would repeal the requirement that the president of the Public Utilities Commission direct the executive director, the attorney, and other commission staff and delete the authority of the president to direct or authorize the executive director and attorney to undertake certain actions, and would instead require that they be directed or authorized to undertake those actions by the commission.

CPUC Oversight and Operation: This bill would:

  • Authorize the commission to delegate specific management and internal oversight functions to committees composed of 2 commissioners;
  • Require the commission to vote in an open meeting on the assignment or reassignment of proceeding to one or more commissioners;
  • Require the commission to additionally adopt procedures on disqualification of commissioners due to bias or prejudice similar to those of other state agencies and superior courts;
  • For rate setting or adjudicatory proceedings, the bill would require a commissioner or an administrative law judge to be disqualified if there is an appearance of bias or prejudice based on specified criteria; and
  • Prohibit commission procedures from authorizing a commissioner or administrative law judge from ruling on a motion made by a party to a proceeding to disqualify the commissioner or administrative law judge due to bias or prejudice.

Ex Parte Communications and Conflict of Interest: This bill would:

  • Delete the provision that an ex parte communication concerns a substantive, but not a procedural matter, and instead would provide that an ex parte communication concerns any matter that the commission has not specified as being a procedural matter that is an appropriate subject for ex parte communication;
  • Require the commission to specify those procedural matters that are appropriate subjects for ex parte communications in its Rules of Practice and Procedure;
  • Define a person involved in issuing credit ratings or advising entities or persons who may invest in the shares or operations of any party to a proceeding as a person with a financial interest
  • Require that the commission, by rule, adopt and publish a definition of decision makers, that would be required to include each commissioner, the attorney for the commission, the executive director of the commission, the personal staff of each commissioner, including each advisor to a commissioner, the administrative law judge assigned to the proceeding, the director of the Energy Division, the director of the Communications Division, the director of the Water and Audits Division, and the director of the Safety and Enforcement Division;
  • Require communications between a person with an interest who is not a party to a commission proceeding and a decision maker to be reported by the decision maker but would not require the communications to be reported by the person with an interest who is not a party to a commission proceeding;
  • Require that a decision maker who makes or receives a prohibited ex parte communication, or who learns that a permissible ex parte communication was not reported as required, to disclose the content of the communication in the record of the proceeding;
  • Require the commission to establish rules for how to handle prohibited ex parte communications, including rules requiring reporting the person initiating the communication and whether the person persisted in continuing the communication after being advised that the communication was prohibited;
  • Require that an ex parte communication not be part of the record of any proceeding and not be considered, or relied upon, for purposes of the commission’s resolution of contested issues;
  • Provide that ex parte communications are permitted in quasi-legislative proceedings, but would require that they be reported within 3 working days of the communication by filing a “Notice of Ex Parte Communication” with the commission in accordance with procedures established by the commission for the service of that notice;
  • Require the commission to additionally prohibit communications concerning procedural issues in adjudication cases between parties or persons with an interest and decision makers, except for the assigned administrative law judge;
  • Delete the requirement that if an ex parte communication meeting is granted to any party in a rate setting proceeding, that all other parties also be granted individual ex parte meetings of a substantially equal period of time and that all parties be sent a notice of that authorization at the time the request is granted, at least 3 days prior to the meeting;
  • Prohibit oral communications concerning procedural issues in rate setting cases between parties or persons with an interest and decision makers other than the assigned administrative law judge, except that a commissioner would be authorized to permit an oral communication relative to procedural issues if all interested parties are invited and given not less than 3 days’ notice; and
  • Prohibit written ex parte communications concerning procedural issues in rate setting cases between parties or persons with an interest and decision makers other than the assigned administrative law judge, except that a commissioner would be authorized to permit a written communication relative to procedural issues by any party provided that copies of the communication are transmitted to all parties on the same day.

C. California Public Utilities Commission Ex Parte Communications: AB 1023

This bill would require the Public Utilities Commission to both establish and maintain a weekly communications log summarizing all oral or written ex parte communications and make each log available to the public on the commission’s Internet Web site.

D. California Energy Commission Conflict of Interest Regulation: SB 693

Existing law prescribes certain qualifications for members of the Energy Commission designed to eliminate professional, personal, and financial conflict of interests and makes the violation of these provisions a felony subject to fine of not more than $10,000 or imprisonment, or both. This bill would increase the maximum fine to $50,000 for a violation of those provisions.

E. Electric and Gas Corporation Excess Compensation Prohibition: AB 1266

Existing law requires that any expense resulting from a bonus paid to an executive officer, as defined, of a public utility that has ceased to pay its debts in the ordinary course of business, be borne by the shareholders of the public utility and prohibits any expense from being recovered in rates. This bill would:

  • Prohibit an electrical corporation or gas corporation from recovering from ratepayers expenses for excess compensation, as defined, paid to an officer of the utility following a triggering event, as defined, unless the utility obtains the approval of the Public Utilities Commission;
  • Following a triggering event and prior to paying or seeking recovery of excess compensation, the electrical corporation or gas corporation would be required to file a Tier 3 advice letter with the commission containing specified information If the electrical corporation or gas corporation sought or received authorization prior to the triggering event to recover excess compensation in rates; and
  • Require the commission to open a proceeding or expand the scope of an existing proceeding to evaluate the advice letter and, following a duly notice public hearing in the proceeding, to issue a written decision determining whether any expenses for excess compensation that the corporation was authorized to recover in rates should be refunded to ratepayers.
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The Canary in the Sunshine: San Diego Continues to Reach Net Energy Metering Caps First

San Diego has a history of being a leader in rooftop solar. In a March 2015 report by Environment California, San Diego ranked 2nd in total capacity installed and 4th in capacity per person. Previous versions of this same report had similar results. San Diego also has regularly been the first bumped up against statutory capacity limits to net energy metering. SB 656 (Alquist) was signed into law in 1996 and provided for net energy metering (NEM) to be offered to customers in California “…until the time that the total rated generating capacity owned and operated by eligible customer-generators in each utility’s service area equals 0.1 percent of the utility’s peak electricity demand forecast for 1996…” At the time, these limits added up to 53 megawatts (MW) statewide, including 17 for PG&E, 20 MW for SCE, and 3.6 MW for SDG&E.

Figure 1: SB 656 Net Energy Metering Capacity Caps by Utility

Original NEM Caps

Today, these sums seem laughable, but in 1996 when there was virtually no grid-connected solar, these may have seemed high. Today statewide grid-connected solar capacity for the three investor-owned utilities is nearing 3,000 MW. This is about half of the levels of utility-scale solar in California. In March of this year, the Energy Information Administration reported that California was the first state to generate more than 5% of its energy from utility-scale solar, with about 5,400 MW installed at the end of 2014. On June 11th of this year, the California ISO reported that it hit a new solar record of about 6,100 MW. Nonetheless, 3,000 MW of distributed solar a far cry from the original net energy metering cap of 53 MW in 1996. These days, California adds more net energy metering capacity in one month than the original 53 MW cap. In May 2015, incremental solar installations totaled about 80 MW with 164 MW in the queue.

Figure 2 Statewide Net Energy Metering Totals (Source: Advice Letters 3229-E, 4649-E, 2751-E)

Statewide NEM Totals

A Rising NEM Cap Lifts All Panels

With SB 656 (Alquist) in place, the NEM caps were 0.1% of peak demand. The San Diego region was the first in the state to near that cap. In September 2002, then Governor Gray Davis signed into law AB 58 (Keeley) to increase the NEM cap from 0.1% to 0.5%. San Diego again led California’s investor owned utilities (IOU) toward the new cap. This led to adoption of SB 816 (Kehoe) in 2005, a stopgap measure that increased the NEM limit to 50 MW for the SDG&E service territory. A year later, then Governor Arnold Schwarzenegger approved SB 1 (Leno), which among other things increased the cap from 0.5% to 2.5%. It did not take long for the solar installations to approach the new cap and in February 2010, the Governor signed into law AB 510 (Skinner) to increase the cap to 5%.

The current NEM cap remains at 5% but the definition of what that percentage applies to has changed. In 2012, the California Public Utilities Commission (CPUC) adopted Decision 12-05-036, which ruled that “aggregate customer peak demand” means the sum of the peak demand of each customer regardless of whether it occurs during the system peak. This effectively doubled the capacity cap for NEM. That brings us to the end of our legislative journey: AB 327 (Perea). Adopted in 2013, this bill codified the NEM capacity caps approved by the CPUC. These are 607 MW for SDG&E, 2,240 MW for SCE, and 2,409 for PG&E. AB 327 also set in motion a transition to a new NEM regime. It requires the CPUC to develop a standard tariff or contract no later than December 31, 2015. This NEM-replacement is to take effect on July 1, 2017 or when the current capacity caps are met.

Once again, SDG&E service territory is leading the pack and likely will hit the cap before the July 1, 2017 deadline. But when will SDG&E hit the cap?

A Look at the Numbers

Currently there are 56,259 net energy metered systems installed in the SDG&E service territory representing 388 MW. There are also 2,347 systems representing 22 MW in the queue for interconnection. If we count those too, this leaves about 197 MW to reach the cap of 607 MW. Each month the total capacity of systems installations and applications in the queue totals about 12 MW. If this pace continues, we would hit the cap in October 2016.

Figure 3 SDG&E Service Territory Net Energy Metering Totals (Source: Advice Letter 2751-E)

SDG&E NEM Totals

How accurate is this projection? Well, at EPIC we have found that our crystal ball is as cloudy as most, but it might be best to characterize this estimate as a business-as-usual projection. If the rate of installations accelerates in the next couple quarters due to the sense of scarcity – real or perceived – heard on San Diego’s airwaves, SDG&E service territory could hit the cap sooner. It is safe to assume that as we approach the capacity cap, there will be an acceleration of solar sales. The magnitude of this effect and when it begins are not clear. Based on the trends in the current data, there does not appear to be any significant uptick in installations. If, on the other hand, the rate of installations slows due to pending residential rate changes that would collapse four tiers eventually into two, reduce the upper tiers from the $0.40/kilowatt-hour (kWh) range to the $0.20/kWh range, and introduce a minimum bill, then it could take longer to hit the cap. It is also safe to assume that pending rate changes will have some effect in the marketplace but how much and when is also not clear.

By the way, using this same business-as-usual projection method, PG&E would hit its statutory capacity cap closer to the July 1, 2017 cut off date, and SCE would not hit its capacity cap until Spring 2018. So it is safe to say that barring some significant change in market performance, SDG&E’s service territory once again will hit the statutory capacity cap first.

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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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