What is Business-As-Usual? Projecting Greenhouse Gas Emissions at the Regional Level

Projecting greenhouse gas (GHG) emissions is important because it helps us to assess how much the energy and GHG policies in place help to achieve targets set by law. For example, if we apply California’s AB32 target to the San Diego region, we would have to achieve the 1990 GHG emissions level (approximately 29 million metric tons CO2e) in 2020. To assess whether the policies we are enacting and implementing today can hope to achieve this target, we need a projection that tells us where we would be without these policies. Figure 1 shows the regional GHG emissions and a projection made in 2008 based on economic and demographic forecasts of the region (see San Diego County Greenhouse Gas Inventory September 2008 at http://www.sandiego.edu/law/centers/epic/reports-papers/reports.php). According to this projection, we would have needed to avoid about 14 million metric tons CO2e in 2020 to achieve the 1990 level.

Figure 1

Figure 1 San Diego region’s greenhouse gas emissions trends and 2008 BAU projection

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

transmissions lines

In Part I of this post, we discussed the concept of asset utilization — or load factor — and looked at recent trends for California’s investor-owned utilities (IOU). The trend over the past two decades for IOU load factors has been a decline from the 55%-60% range to the 50%-55% range. In Part II, we will explore the factors that affect load factor, whether there is an optimal load factor, and how California’s greenhouse gas policies may affect load factor.

Optimizing Load Factor

So, what is the optimal load factor for electric utilities in California? The short answer is that it depends. In a perfect world, we would design and operate our electric system to have a 100% load factor; that is, the average demand and peak demand are equal and we use all the capacity of the system all the time. Demand in this case would be flat – one level of demand every hour of every day of ever year. But, alas, we don’t live in that perfect world. Many factors contribute to load factor, including weather, customer type, and rate structures. As a result, there is no one-size-fits-all approach to determining the optimal load factor.  Continue reading

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

airliner landing at dusk, panoramic frame

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. 

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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.

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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.

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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

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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.

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