The data source has a strong influence on the ability to accurately detect and attribute changes in energy consumptions. The underlying change in electricity use is in the AC electricity use of customers enrolled in the program. Electricity use from other end-uses in participant households or from customers that are not in the program add to the background noise. The more extra data that is layered on top, the harder it is to detect and properly attribute changes in electricity use due to load control.
To illustrate, Figure I-1 shows electricity use for a specific feeder in one of the warmest cities in the Bay Area, San Ramon, on August 24th, 2010, a day when peak temperatures reached 103°F. The feeder had roughly 2,700 electric accounts at the time, some of which were commercial. It also had a relatively high penetration of the AC control program, SmartAC. The feeder had 266 electric accounts and 292 AC units under control at the time; which were roughly 10% of the accounts. The penetration exceeded the penetration in over 90% of the feeders in PG&E territory.
Figure I-1: Electricty Use for a Specific Feeder in San Ramon on August 24th, 2010
The graph on the left shows the electricity use on that feeder, while the graph on the right provides a more detailed look at the household and estimated AC use for customers enrolled in the AC control program. The overwhelming share of electricity use on the feeder, 92%, comes from electric accounts that are not enrolled in the program. In addition, for most hours of the day, the AC load is less than half of the household load. In any other, cooler day, the AC load would be a smaller share of the household electricity use. If we assume a 35% reduction of the AC electricity use during the hours with the highest AC use, at the feeder level it is necessary to distinguish a 175 kW (35% x 500 kW) change in electricity use from over 11,000 kW of feeder load. Because the change is relatively small, 1.5%, it is difficult to detect it and confidently
0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 0: 00 3: 00 6: 0 0 9: 00 12 :0 0 15 :0 0 18 :0 0 21 :0 0 kW
Feeder Data
Participant AC Load Other participant end‐uses Non‐participant load 0 100 200 300 400 500 600 700 800 900 1,000 0: 00 3: 0 0 6: 0 0 9: 00 12 :0 0 15 :0 0 18 :0 0 21 :0 0 kWHousehold Data
Participant AC Load Other participant end‐useseliminate alternative explanations, including random variation. In contrast, with household data of participants, the change is easier to observe and detect because it contains less noise.
Assuming a 35% reduction in AC electricity use, it is necessary to distinguish 175 kW from approximately 900 kW, a far easier task. However, this is a best case scenario because the AC load is a smaller share of household load in most hours and days, which are typically cooler. Clearly, it is easiest to detect changes in AC electricity use when it is directly measured.
In practice, it is possible to increase penetration feeders so the electricity reductions are a larger share of the feeder load and can be observed. Employing more aggressive load control strategies such as 100% cycling or load shed also leads to larger reductions that are more easily detected. Both PG&E and SCE tested the ability to increase feeder penetration level and observe impacts with feeders versus with AC cycling. In both cases, the feeders were atypical in the degree of AC control saturation and the feeders selected. Even for highly saturated feeders, the results are mixed and depend on the date and time of operations.
Figure I-2 compares impacts on feeder loads to impacts when AC units are directly measured. It illustrates why impacts are more difficult to detect with feeder data, even in feeders with
extremely high saturation of AC control. The example is from the PG&E 2009 Ancillary Services Pilot where 4 feeders were highly saturated and 2,000 AC compressors on 4 feeders were instructed to fully shut down 70 times for 15 minutes. The graph presents two different days, August 20th and September 8th, 2009, for the same feeders and AC units. A few observations are noteworthy. First, the reduction in AC load is easy to detect visually in both days, while it is more difficult to observe the impact using feeder data for September 8th. Second, although the impacts for August 20th are clearly visible of the feeder data, this is in part a product of the graph scale, which shows the feeder load above 20 MW, and the time resolution, which focuses on a single hour. Without the adjusted scales, the impacts on the feeder electricity load are less evident. Third, in both days, the impacts would be half or less if a 50% cycling strategy had been employed instead.
During the August 20th event window, the aggregate reduction in electricity use was 2.2 MW and the aggregated feeder electricity loads were 26 MW. The AC control produced a 8.5% reduction in feeder electricity loads. In contrast, the same reduction amounted to 76% of AC electricity use. For September 8th, the aggregate reduction in electricity use was 0.7 MW and the feeder loads were roughly 17 MW. The percent change in feeder electricity loads is smaller, 4.1%, and much harder to detect. In fact, a reader that was not informed of the event window could easily conclude the event occurred earlier, between 1:30 and 1:45 PM.
97
Figure I-2: Comparisons of Direct Load Control Impacts on Feeders and Air Conditioner Load
99
While it is possible to observe AC impacts on distribution feeder electricity data, in practice, few feeders will have high enough AC control penetration rates to be able to confidently and
accurately detect changes in electricity use using that data source. Feeder data includes load variation from residential and commercial accounts, accounts with and without AC and multiple end-uses, many of which are unrelated to air conditioning. For most feeders, controllable AC load is too often too small compared to other electricity use on the feeder. To see impacts at the feeder level, the right feeder at the right hour during the right temperature conditions need to be selected and an aggressive control strategy needs to be employed. Even for feeders with
extremely high AC control saturation levels, it can be hard to detect impacts using feeder data depending on weather conditions and hour of day. In testing the accuracy of settlement alternatives, rather than hand-pick highly saturated feeders, we employed a random sample of feeders to better understand the feasibility of feeder data for settlement on a program-wide basis. Table I-1 summarizes the distribution circuit feeders in PG&E territory with customers enrolled in their AC load control program. There are approximately 2,800 distribution circuit feeders in PG&E territory and nearly 2,000 had customers enrolled in the AC control program when the data was extracted. The tables and the analysis exclude 66 feeders with less than 100 total population accounts since the results for these feeders are less reliable.
Table I-1: Characteristics of PG&E Feeders with Accounts in Air Conditioner Control Penetration Deciles Feeders Central AC Saturation Avg. Residential Feeder Accounts Avg. Monthly kWh Avg. Number of Accounts in SmartAC SmartAC Participant Avg. Monthly kWh % Penetration of Accounts Top 10th 193 75.3% 1,980.7 801.5 199.7 766.4 10.0% 2nd 193 68.9% 2,002.7 726.6 143.7 734.8 7.1% 3rd 193 62.9% 1,795.2 713.6 102.7 746.6 5.7% 4th 193 57.8% 1,502.5 686.5 63.5 749.1 4.2% 5th 194 52.7% 1,640.9 693.7 47.6 748.2 2.9% 6th 193 49.2% 1,804.6 691.1 36.6 735.1 2.0% 7th 192 40.3% 1,821.9 618.1 24.9 663.5 1.4% 8th 194 31.7% 1,892.9 570.6 15.1 644.9 0.8% 9th 193 22.7% 1,700.9 537.1 6.0 650.7 0.3% Bottom 10th 194 11.0% 2,570.1 462.1 1.8 576.6 0.1% TOTAL 1932 47.2% 1,871.5 650.0 64.1 707.2 3.5%
In Table I-1, the top 10% of feeders with the highest penetration are grouped together, followed by the next 10% and so on. For each decile, the demographics of the average feeder are shown, including the total number of accounts, estimated central AC saturation and number of AC devices enrolled in the program. Not surprisingly, the AC control feeder penetration is higher
when central AC saturation is higher. However, as the example of the San Ramon feeder demonstrated, even when over 10% of the accounts on a feeder are enrolled, the impacts of curtailment operations are a relatively small share of the feeder loads in extremely hot days and make up an even smaller share of the feeder loads in cooler days.
References
Bode, J., M. Perry, and S. Morgan. 2010. Assessment of Settlement Baseline Methods for Ontario Power Authority's Commercial & Industrial Event Based Demand Response Programs.
Prepared for Ontario Power Authority.
Braithwait, S., D. Armstrong. 2009. Load Impact Evaluation of California Statewide Aggregator Demand Response Programs. Volume 2: Baseline Analysis of AMP Aggregator Demand
Response Program. Prepared for the California Demand Response Measurement & Evalution Committee.
Christensen Associates Energy Consulting. 2010. Highly Volatile-Load Customer Study. Prepared for Southern California Edison, Pacific Gas and Electric, and San Diego Gas and Electric.
Coughlin K., M.A. Piette, C. Goldman, and S. Kiliccote. 2008. Estimating Demand Response Load Impacts: Evaluation of Baseline Load Models for Non-Residential Buildings in California. Ernest Orlando Lawrence Berkeley National Laboratory. LBNL-63728.
http://eetd.lbl.gov/ea/EMS/EMS_pubs.html
Eto, J., Nelson-Hoffman, C. Torres, S. Hirth, B. Yinger, J. Kueck, B. Kirby (Oak Ridge National Laboratory), C. Bernier, R. Wright, A. Barat, D. Watson. 2007. Demand Response Spinning Reserve Demonstration. Ernest Orlando Lawrence Berkeley National Laboratory. LBNL-62761.
Eto, J., C. Bernier, P. Young, D. Sheehan, J. Kueck, B. Kirby, J. Nelson-Hoffman, and E. Parker (2009). Demand Response Spinning Reserve Demonstration — Phase 2 Findings from the Summer of 2008. Ernest Orlando Lawrence Berkeley National Laboratory. LBNL-2490E. Gifford, W., S. Bodmann, P. Young, J. Eto, J. Laundergan. 2010. Customer Impact Evaluation for the 2009 Southern California Edison Participating Load Pilot. Lawrence Berkeley National Laboratory. LBNL-3550E.
KEMA, Inc. 2003. Protocol Development For Demand Response Calculation—Findings and Recommendations. Prepared for the California Energy Commission.
http://www.energy.ca.gov/reports/2003-03-10_400-02-017F.PDF
KEMA, Inc. 2011. PJM Empirical Analysis of Demand Response Baseline Methods. Prepared for the PJM Markets Implementation Committee. http://pjm.com/markets-and-
operations/demand-response/~/media/markets-ops/dsr/pjm-analysis-of-dr-baseline-methods-full- report.ashx
Kirby, B. 2003. Spinning Reserve From Responsive Loads. Oak Ridge National Laboratory. ORNL/TM-2003/19.
Kirby, B. 2006. Demand Response For Power System Reliability: FAQ. Oak Ridge National Laboratory. ORNL/TM-2006/565.
Kueck, J., B. Kirby, R. Staunton, J. Eto, C. Marnay, C. Goldman, C.A. Martinez. 2001. Load As a Reliability Resource in Restructured Electricity Markets. Prepared for the U.S Department of Energy. http://certs.lbl.gov/pdf/load-reliability.pdf
Kueck K., B. Kirby, M. Ally, and. Rice. 2009. Using Air Conditioning Load Response for Spinning Reserve. Oak Ridge National Laboratory. ORNL/TM-2008/227.
Mathieu, J., D.S. Callaway, and S. Kiliccote. 2011. Variability in Automated Responses of Commercial Buildings and Industrial Facilities to Dynamic Electricity Prices. Energy and Buildings. Volume 43, Issue 12, December 2011
Quantum Consulting and Summit Blue Consulting. 2004. Working Group 2 Demand Response Program Evaluation – Program Year 2004 Final Report. Prepared for the California Public Utilities Commission.
Sullivan, M., J. Bode, P. Mangasarian. 2009. 2009 Pacific Gas and Electric Company SmartAC Ancillary Services Pilot. Prepared for Pacific Gas and Electric.