What is the Problem with Demand Response Baselines?

§  Incentive programs pay consumers to reduce their consumption relative to some level.  In order to gauge their reduction, one must estimate the counterfactual-- how much the consumer would have consumed in absence of the event.  There are several distinct problems associated with this:

o   Measuring the counterfactual of what the consumer would have otherwise consumed requires sophisticated statistical or economic models.  However, electric load is a fundamentally extremely difficult variable to explain and even the best models account for only a fraction of this variability.  Given this, although load reductions are typically communicated as static variables, it may be more accurate to describe them in terms or ranges, or atleast static quantities with error margins.  However, this is rarely the case.

o   Setting up baselines in this manner essentially rewards customers for having a higher baseline.  This creates incentive to game the system, attempting to over consume electricity during the days which will be used to calculate their baseline average.  This is exacerbated if customers are paid ahigher price for each KwH reduced than they actually would pay for that same kwh at the retail rates they pay while establishing their baseline.

o   Heavy support for incentive programs may crowd out dynamic pricing by overpaying customers for reductions that do not actually occur

Source: Jim Bushnell "When it comes to DR, is FERC its own worst enemy?"

Brief History of Demand Response Aggregators AKA Curtailment Service Providers

Aggregators have grown in popularity in recent years because of the profitable opportunity to be the middlemen between customers and utilities. Wholesale market DR programs in almost all ISO/RTO's were comprised of "legacy" incentive based DR programs offered by utilities.  In restructured markets with retail competition, non-utility entities began to spring up.  In ISO-NE, NYISO and PJM, rules had to be developed for these load aggregators.  The aggregators began to rely increasingly on incentive based DR programs because they provide ongoing capacity payments, as opposed to price-based programs that were less certain in terms of revenue.  Capacity payments represent a monthly stream of income for those enrolled.  The amount depends on how much the business can reduce and often there are limits, for example the ability to curtail atleast 200 kW of load within a certain time period.  There may be additional amounts paid out for the actual reductions that happen, calculated using the baseline methodology outlined earlier.  If enrolled in a price-based program, then the customer would determine the market price at which they would be willing to curtail load.  Payments are based on the market price for the amount of load reduced for each hour.  



Arranging with an aggregator is often a more attractive option for end use customers because they do not force them to pay penalties for underperformance.  If an end-use customer fails to perform for the aggregator, some may instead withhold future payments.  Others, such as Enernoc, make the fact that they charge no penalties for non-performance into a big part of their sales pitch to potential customers .  Aggregators often provide infrastructure such as advanced metering and customer support that utilities cannot necessarily match.  Another advantage of allowing aggregators into a market is that they often can leverage previous marketing experience in recruiting new customers .




Smaller C&I customers may not meet size requirements to deal directly with the utility.  Additionally, it reduces administrative costs for the utility by allowing them to deal with a single large entity as opposed to many smaller ones 

How Do California Demand Response Cost Effectiveness Protocols Work?

California seems to be taking the lead in thinking about how to evaluate demand reponse programs at a high level as compared to the other states we address below.  It has its own set of Cost Effectiveness protocols developed by the CPUC.  Before this, each IOU had its own set of criteria by which to judge their programs and their methodology was somewhat opaque, driven in part by proprietary models and data.  This is an attempt to standardize and make transparent the process by which these programs are judged.


Protocols are meant for programs that produce measurable load reductions, not permanent load shifting programs (ie energy efficiency) because these programs are not dispatchable.  It may be applicable to rates such as CPP.  


All IOUs must use the publicly available DR reporting template, a spreadsheet model with various preloaded specifications such as avoided energy and capital costs.  IOUs enter in their own data such as load impacts and energy savings.


The framework for the analysis includes four different cost benefit tests that examine the effects of DR programs for different actors.  Listed are also examples of what these costs and benefits are likely to be.

1) Total Resource Cost Test:  This attempts to examine the net effect on society as a whole, where society is defined as the LSE or IOU plus all of its customers. 

§  Benefits:  LSEs avoided cost of electricity, market revenue, environmental benefits

§  Costs: Increased supply costs

2) Program Administrator Cost Test:  This attempts to examine the net effect on the LSE or IOU alone

§  Benefits:  LSEs avoided cost of electricity

§  Costs: Incentives paid, administrative and capital costs

3) Ratepayer Impact Measure:  Examines the effect on Ratepayers

§  Benefits: Avoided cost of supply electricity, Market revenue, other market benefits

§  Costs: administrative costs, incentives paid out, increase in supply costs (where applicable)

4) Participant Test:  Examines the effect on Ratepayers who are also enrolled in DR programs

§  Benefits: bill reductions, incentives earned, tax credits

§  Costs: bill increases, capital and O&M of DR equipment installed, value of lost service (due to reduction in energy consumption), transaction costs

Implications of FERC Order 745 “Demand Response Compensation in Organized Wholesale Energy Market"

Much literature has focused on FERC order 745. Here are some insights on how this ruling will affect DR customers and aggregators.  


Although there are no firm size restraints mandated by the rule, other constraints make it difficult for, say a small residential consumer to participate directly in this large market. This is because,to participate in a wholesale market and become a recognized Load Serving Entity (LSE), one needs to demonstrate credit worthiness (usually by having a large sum of money in the bank), meet certain technical standards (telemetry, energy management systems, software to bid, etc) and any other requirements specific to that market.These factors make it so that aggregators have a much easier participating than would a normal end user of energy.  However, large industrial or commercial users of electricity with energy managers and sophisticated systems may choose to directly participate themselves outside of aggregator programs.

How Are Demand Response (DR) Programs Administered??

Administration of DR programs

Administration of demand response programs occurs at the utility or independent system operator (iso) level[1]. Utilities run these programs for the benefit of their RTO, or ISO to promote grid reliability and for other reasons.  They are usually (but not always) required to offer these programs by their overseeing authority, the public utility commission.  Aggregators function within these boundaries.  That is, at times utilities set up particular programs that the aggregators can participate in, but they are subject to program constraints like any other participant.  The only difference between joining with the aggregator and the utility is the level of service and support one receives.  In all other respects, they are the same programs and thus, the same rules. A confusing extra feature of this arrangement is that at times aggregators will bundle several distinct program options under one brand one and market it as a different program to the end-use customer[2].  It is worth noting that generally PUCs have no authority over the contract between the aggregator and the end use customer, the source of much of the jurisdictional confusion around aggregators.

Demand Response (DR) Program Classifications

Types of DR Programs

The traditional dichotomy is between incentive-based DR programs and time and price-based programs(Albadi & El-Saadany, 2008).For the price-based programs, the load reduction occurs because prices have reached a pre-specified high level.  Incentive programs require the customer to shed load in response to a system-wide events. in reality, the line between these programs is often blurry.

Among the incentive programs, market-based programs are growing in popularitydue to a recent high-profile FERC ruling [3].  FERC has mandated that wholesale energy market operators pay locational marginal price (LMP)[4] to demand response resources, effectively paying them as if they were analogous to traditional generating units such as natural gas plants.This has been seen as a boon to the demand response aggregators who can now enlist customers in DR programs and bid them load directly into wholesale markets, as opposed to being a middleman between utilities and customers.  It has also encouraged a host of programs where customers can bid their loads in themselves.  There will be more discussion of this ruling very soon.

Diesel Generation in Demand Response: California's Nagging DR Question

Introduction
This project is the continuation of work that was begun at the request of Bruce Kaneshiro of the California Public Utilities Commission’s Demand Response Section of the Energy Division during the summer of 2010. The primary goal was to assess the role of diesel backup generation in demand-response (DR) programs. There was suspicion among CPUC staff that demand response may have been indirectly incenting participants to rely upon backup diesel generation (BUG’s) outside of the threshold amount allotted by the State of California. Even until now, the true emissions impacts of demand response programs in California --when accounting for the effects of diesel generation-- remain unknown.

As I began to look into the issue it became clear why no one had been able to study it; the issue was multifaceted and nebulous. As complexity began to unfold, I realized that the results of my inquiry would not yield conclusive results during the time frame of a summer internship. The main reason for this was a lack of comprehensive data on when registered diesel engines actually run. However, as a result of our initial inquiry, regulatory processes set in motion by the CPUC and CARB will begin to collect this data and make it available for analysis by the fall of 2011. With the support of the EPA Star Fellowship, I want to apply myself to fully resolving this issue. In doing so, this will be the first comprehensive cost-benefit assessment of demand response that includes the full emissions impact due to diesel generation.


Context
Regulation of Diesel Generators
The main question that this project will try to address is “to what extent do DR participants shift their loads onto diesel generators instead of simply curtailing?” The question focuses on participants in demand response programs who utilize diesel backup generation to respond to events (instead of simply curtailing load) outside of their permitted usage. Understanding the policy framework around this question involves overlapping jurisdictional authorities such as the California EPA, The Air Resources Board, numerous Air Quality Management Districts and the Public Utilities Commission. Some context on the specific roles of each agency in regards to this issue is crucial to an understanding of the ambiguity surrounding it.

The California Air Resources Board (CARB) drafted The Airborne Toxic Control Measure for Stationary Compression Ignition Engines (ATCM) in 2004. Concerns about the toxicity of diesel particulate matter were a prime reason for this regulation. The ATCM specifies the requirements for initial compliance and classifies engines for emergency and prime use. Emergency use engines require less stringent standards because they are only to be used when normal electricity service fails. Prime engines are not used in emergency situations and thus face stricter emissions criteria. The 2004 version of the ATCM established standards for Stationary Compression Ignition Engines operating in demand response programs. Only two DR programs are specifically allowed to use BUG’s: Interruptible Service Contracts (ISC) and the San Diego Gas and Electric Company’s Rolling Reduction Blackout Program (RRBP). Any new customers enrolling in these programs after January 1, 2008 had to meet diesel PM standards of 0.01 g/bhp-hr, the standards set for prime engines. The ATCM mandates than an engine must be used to testing and maintenance a certain amount of hours per year.

Air Quality Management Districts (AQMD’s) are responsible for ensuring that BUG owners remain in compliance with the standards set by the ATCM. Local districts perform inspections of BUG’s every 1-3 years, record hours of usage, and are responsible for enforcement. The enforcement procedures take the form of fines and penalties. Owners of BUG’s are mandated to keep manual logs which indicate each instance of usage of the unit, duration and purpose for operation. All BUG’s are equipped with a tamper-proof meter which tracks cumulative hours of use in the same way that a car odometer tracks miles driven. Monitoring of compliance can vary drastically by district due to logistical necessity; some districts have less than 500 BUG’s while others have more than 9000. BUG owners must file to get a permit with the AQMD of their region. The information from these permits is stored in a local AQMDs database.

The California Public Utilities Commission was the source of this inquiry. In the context of this project, their primary role is to oversee demand response programs developed by utilities. The CPUC can exert authority over utilities, but has no regulatory oversight over BUG owners.

What is the issue?
Although most districts ban the usage of emergency class generators in demand response programs (except for Interruptible Service Contracts and the San Diego Rolling Reduction Blackout Program), the information to determine whether owners actually do this is currently not gathered. AQMD’s normally only record cumulative hours of usage when they do BUG inspections. They typically ensure veracity by inspecting the manual logs and verifying that the number of hours listed matches what is shown on the non-resettable meter of the unit. So, AQMD inspectors, while they know for how long a diesel engine has operated, do not know exactly when the operation occurred. Without knowing the date and time of operation for the engines, it is impossible to determine whether BUG usage coincides with demand response event times.

Another contributing factor may be that it is unclear whether DR customers understand what all applicable regulations are. Some districts have issued compliance bulletins specifying that emergency class generators must be upgraded to prime engine status if they want to participate in a DR Program; other districts (including some of the larger ones) have not reached an official stance on the issue. It is, in any event, likely that the only customers who would find out about whether it is appropriate to use backup generation to respond to a DR event are those who specifically approach the district to ask. It is also likely that most DR customers do not know that this practice is frowned upon by their local AQMD.

Furthermore, vague utility tariff information might contribute to customer propensity to rely inappropriately on backup diesel generation to respond to DR events. Many programs typically thought of as “demand response” do not include specific instructions regarding proper BUG usage. The programs which do make mention of BUG’s in the tariff language invite owners to use their backup generators to respond to the demand response events, but leave it up to them to act within the bounds of their permitted use. The tariff language adds to the general uncertainty surrounding the issue of BUG’s participating in demand response.

How are agencies addressing this issue?
CARB is currently amending the ATCM, the results of which could provide data on when CA BUG’s are used. According to contacts at ARB, The new version will add additional reporting requirements from BUG owners that would close match the list of data provided above. It will also make all new emergency engines adhere to tier 4 emissions standards (0.01 g/bhp-hr), the most stringent category. It proposes to remove the hourly cap on number of hours that engines can run in exchange for the higher emissions controls. The amended version of the ATCM will go to Board for opening comments on October 20th, 2010.

The new ATCM will stipulate that as much of the data be reported electronically as possible. The Board will vote on the measure by early January. The deadline it will extend to districts for the collection of this data will likely be 2-4 months. As such, comprehensive data on the run-time logs of the units could be provided by June 2011.

CPUC will also likely amend utility tariff language in January 2011 with regard to BUG’s. The spirit of these amendments will likely be to mandate that all participants in demand response programs with diesel backup generation provide copies of the run-time logs (detailing when units are run) to the utilities. The driving motivation behind this development will not be to punish BUG owners who participate in DR, but to gather the information necessary to conduct an analysis on the extent of this practice.

These actions in and of themselves, while helpful, may not produce conclusive results. The main reason is due to manpower limitations. In the case of the data being provided by CARB, massive amounts of data analysis must be conducted in order to distill the list of at least 20,700 BUG’s in down to a several hundred DR

Why is this important?
Even though in California stationary sources of pollution are not a majority of overall emissions, the diesel particulate matter (PM) is an ultra-noxious pollutant. Long-term exposure to PM has a well-acknowledged history of correlation with lung cancer and cardiovascular disease. The small particles from diesel exhaust are rough and bind easily to other toxins in an environment, driving up the overall unit risk factor of pollution in an area. Moreover, concentrations of BUG’s are highest in urban areas, so their emissions have a proportionally higher impact per capita. To add further incremental impact, the usage we are concerned with here occurs on DR event days which are typically, the hottest, smoggiest days of the year. In sum, the PM emissions from stationary diesel engines are a dangerous source of pollution that needs to be closely monitored, regulated and understood—no matter how limited we think the impact may be.

Understanding the role of diesel generation among DR participants is an important piece of the overall analysis of the benefits and costs of demand response. Demand response customers earn incentive payments that are funded by ratepayer dollars. The pretext of these subsidies is that demand response promotes grid reliability by encouraging curtailment among program participants. If DR customers are not actually curtailing, but only shifting loads onto their diesel generator, then in effect ratepayers have subsidized the trading of cleaner grid-generation for dirtier diesel. From a reliability perspective, this cost may be outweighed by the other benefits of DR. However, at this point, we do not know enough about how DR customers use diesel generation to tell. No assessments of the value of DR have included the role of diesel generation and looked at the consequent emission impacts of its usage based on real data.

This is an important question. FERC has been aggressively pushing demand response and the dominant philosophy has been to pursue as much capacity as possible. The analysis will allow distinctions between “good” DR and “bad” DR. Additionally, demand response in the Eastern states probably relies much more heavily on diesel generation than California. A study of this nature would provide a benchmark that others could use to adapt to other states and geographic locations.

The issue of diesel generation in DR is also important because it invokes a discussion of the growing role of third-party aggregators such as Enernoc, CPower, Comverge and Energy Connect. DR Aggregators may be relying on backup generation as a selling point to enroll customers. The added sense of security that the potential to rely upon such generation provides is a clear motivating factor for customers to participate in DR programs. DR Aggregator market share is growing rapidly. If reliance on diesel BUG’s is a standard business practice, then this may have substantial impacts on emissions in the future. In addition, DR aggregators market themselves as “green”. If the emissions impacts of aggregator demand response participation are not really known, then this assertion may be misleading. Fully understanding the usage of diesel backup generation in DR is important because it could affect conclusions about the desirability of demand response aggregators.

Finally, California’s utility industry seems destined to venture further into the realm of dynamic electricity pricing in the future. In this world of price spikes and uncertainty for businesses, it is possible that people will increasingly turn to stable diesel backup generators to hedge against price fluctuations and avoid risky curtailment. Looking at how much people are currently relying on diesel backup generation in demand response programs can give us a glimpse into how a future of dynamic pricing might look.