Navigant Research Blog

Automated Demand Response Takes Spotlight at DistribuTECH

— January 3, 2014

With the unveiling of LEED 4.0 in late 2013, the Pilot Credit, which has existed for a couple of years, became a full LEED credit.  That means participants can get three LEED points for enrolling in an existing demand response (DR) program using automated demand response (ADR), one point if there is not a program currently available but ADR capabilities exist in the building, and two points if the facility can shift load to off-peak periods.  This increased point potential may encourage more buildings that are going for LEED accreditation to include ADR in their design.

LEED 4.0 will be high on the agenda at DistribuTECH, the annual gathering of the power sector’s transmission and distribution vendors and customers.  The conference session on DR in the LEED Commercial Buildings track at this year’s DistribuTECH will cover the results of the Pilot Credit program and look ahead to what 2014 holds for the latest version of LEED.

DistribuTECH is well-timed, not only because it gets me out of Boston in January and in San Antonio.  Although I’ve worked for several vendors and utilities in the past that participate in DistribuTECH, I’ve not had the opportunity to attend in person.   I’m also currently working on an upcoming report on ADR, so it will be a good chance for me to talk face-to-face with the leaders in the field so they can tell me how accurate or inaccurate my forecasts are.

BYOD

In addition to LEED, there are a number of other ADR-related aspects of this year’s DistribuTECH.

The session on Demand Response Optimization from a utility perspective will examine ways to leverage DR resources for different value streams and operational purposes.  NV Energy will describe its experience with Alstom’s demand response management system (DRMS), which allows NV to interface with OpenADR or directly with programmable thermostats.  Oklahoma Gas and Electric (OGE), which uses AutoGrid’s DRMS to send signals to thermostats via the Zigbee-based Smart Energy Profile over OGE’s advanced metering infrastructure (AMI) network, is also on the panel.  The next generation of utility DR programs will be “bring your own device” (BYOD), where consumers choose the thermostats they desire at the store and initiate the enrollment process instead of having a technology preselected for them by the utility.

OpenADR falls under the microscope in San Antonio as well, as a number of system operators discuss the progress and results of their use of the standard.  Hawaiian Electric has been running a pilot program to enroll commercial and industrial (C&I) customers to respond within 10 minutes of receiving a signal of an imbalance between supply and demand in order to address a state mandate to incorporate 40% renewable energy in the grid by 2030.  OpenADR unveiled its 2.0 profile specifications in 2013, vastly expanding the applications that can be covered.  International interest in OpenADR has grown quickly, with 20% of member companies now coming from Asia Pacific, including 15 out of the 110 total members in Japan.

The list of exhibitors at DistribuTECH includes players on all sides of the ADR space.  On the C&I side, there are familiar names like Schneider, Siemens, and EnerNOC, as well as relative newcomers like REGEN Energy.  For residential DR, Comverge and ThinkEco represent the implementation and technology field.  Also represented are the companies that work to enable the utilities/grid operators to run DR programs with tools like DRMS, such as Aclara, Alstom, AutoGrid, GE, Lockheed Martin, and OATI.  Finally, groups like the OpenADR Alliance and Zigbee Alliance are working to create standards for DR signals to encourage open communication structures and interoperability of devices.

 

California’s Risky Path to Grid Reform

— December 30, 2013

In June, the California Independent System Operator (CAISO) presented a draft roadmap for integrating demand response (DR) and energy efficiency (EE) into California’s electric grid.  On December 17, a final version of the roadmap was released.  According to the report’s vision statement, “The ISO envisions demand response and energy efficiency becoming integral, dependable and predictable resources that support a reliable, environmentally sustainable electric power system.”  The ISO is working with the California Public Utilities Commission (CPUC) and the California Energy Commission (CEC) to create market opportunities for DR and EE as preferred resources, as the report title suggests.

The roadmap includes four interdependent paths that run from 2013 through 2020: load reshaping, resource sufficiency, operations, and monitoring.  Load reshaping focuses on applying DR and EE resources to the demand side of the market.  These resources will create a flatter load shape for the ISO system through enhanced EE programs and dynamic retail electric rates.  The needed alignment between retail and wholesale markets entails at least three primary approaches: smart grid automation, retail tariff changes, and the encouragement of energy conservation during times of grid stress.

Mind the Duck

Resource sufficiency focuses on the supply side of the equation to ensure sufficient resources are available in the right places and at the right times, while operations aims to make the best use of all resources that are made available through the resource sufficiency path.   Finally, monitoring is the feedback loop for the other three paths.   Systematic monitoring will foster a deeper understanding of the operational capabilities of DR resources, the effectiveness of procurement programs in aligning with system needs, and the impacts of EE and other load-modifying programs in reshaping load profiles.

Implementing new, more flexible and responsive resources will further advance California’s goals of a more reliable and cleaner power system, with the added potential of replacing or deferring investments in more expensive energy infrastructure.   From an operational perspective, DR resources will contribute to the low-carbon flexible capacity needed to maintain real-time system balance and reliability, while also supporting the integration of increasing levels of renewable energy resources, as displayed in the ISO’s famous duck graph.

 

(Source: California Independent System Operator)

California continues to walk the tightrope between markets and mandates as it confronts its rapidly changing energy landscape.  Unfortunately, I’m not sure it will be able to keep its balance and make it to the platform.  Rather, I think it may fall and need to create a new safety net in a few years.  The state needs to choose to either let the markets find solutions, or to stay fully regulated and not create paper markets.  I understand it has been burned by free-market solutions in the past and may be gun shy, but making quasi-markets is not the answer.

That’s not to say that other regions have pure markets.  State policies always interact with grid operations, whether it’s in single-state regional transmission organizations (RTOs), like New York and Texas, or multistate RTOs like PJM, ISO-NE, and MISO.  All have seen battles between market operators and regulators, but there still seem to be some sense of respect for each side’s territory of control.  Of course, California likes to blaze its own trail.  Sometimes that leads to glory, but in this case, it may lead back to the starting line.

 

Enforcement Report Highlights Demand Response Compliance Issues

— December 19, 2013

The Federal Energy Regulatory Commission (FERC) released its 2013 Report on Enforcement in November.  It includes the highest number of demand response cases of any Enforcement Report to date, showing that compliance with DR programs is coming under increasing scrutiny.  These cases, which involve violations of DR rules and lack of oversight on program management, have resulted in multimillion dollar penalties or settlements.  The penalties are often orders of magnitude greater than the original over-compensation, so it’s far more than a matter of just paying back what you owe and calling it even.  Furthermore, some of the penalties have been levied against end-use customers and even individuals in DR programs, so clearly the FERC feels that its jurisdiction goes beyond DR aggregators.

Several of the cases occurred in ISO New England (ISO-NE), which may point to the complexity of rules for DR participation there.  First, and largest in magnitude, is the Day-Ahead Load Response Program investigation.  The FERC found that two large paper mills and an energy procurement consulting company engaged in fraudulent inflating of customer load baselines in order to increase payments.  One of the companies has settled with the FERC for a $10 million civil penalty and $2.8 million disgorgement, or paying back undeserved revenues.  The other parties have multimillion dollar penalties outstanding, including $1.25 million against one individual whom the FERC claims to be a mastermind of the scheme.

Undue Diligence

The second ISO-NE related case involved a settlement between the FERC and EnerNOC.  The FERC claimed that EnerNOC failed to exercise adequate due diligence and resolve significant data quality issues for five assets it registered as DR, thereby inducing overpayments from the ISO and violating the due diligence requirement in the ISO’s tariff.  The settlement resulted in a civil penalty of $820,000 and $656,806 in disgorgement of unjust profits.  EnerNOC also agreed to develop a comprehensive compliance program and to submit to compliance monitoring.

The FERC also evaluated Connecticut Light & Power Company’s (CL&P) compliance with DR programs within ISO-NE and found that CL&P did not properly account for revenues associated with its conservation and load management programs and did not accurately record demand reduction data in its reporting system; however, there are no penalties associated with this case at this point.  The one case outside of ISO-NE occurred in PJM, where the FERC came to a settlement with Comverge on a claim that Comverge registered a large customer for a load reduction amount it knew the customer could not reliably achieve and then instructed the customer to artificially increase its electric load prior to a test event in order to demonstrate a larger load reduction.

No Free Passes

As described in Navigant Research’s recent report, Demand Response Tracker 4Q13, DR is becoming a bigger part of the reliability solution for the electric grid.  That means DR providers and customers must be aware that greater responsibility is required and higher risks must be managed. In the early days of DR, baseline and program rules were being refined and there may have been some loopholes that were exploited. These days, the FERC and RTOs rely more on DR to run the grid and will not give free passes to intentional or inadvertent infractions.

 

Demand Response Momentum Gathers

— December 6, 2013

The Federal Energy Regulatory Commission (FERC) released its 8th annual Assessment of Demand Response and Advanced Metering in October.  A few areas worth highlighting include advanced meter installations, DR program growth trends, DR events during summer 2013, and North American Electric Reliability Corporation’s (NERC) Demand Response Availability Data System (DADS) results.

The penetration of advanced meters is up from approximately 9% in 2009 to nearly 25% in late 2011/early 2012.  As of June 2013, approximately 12.8 million advanced meters were installed and operational under the U.S. Department of Energy’s (DOE’s) Smart Grid Investment Grant (SGIG) program.  Ultimately, 15.5 million advanced meters are expected to be installed and operational under SGIG.  All SGIG projects are expected to reach completion between 2013 and 2014.  Overall, the penetration is increasing, but the pace of new installations is slowing down as SGIG funds wind down.

Since 2009, demand response (DR) potential in organized markets operated by the regional transmission organizations (RTOs), independent system operators (ISOs), and the Electric Reliability Council of Texas (ERCOT) increased by more than 4.1%.  The potential increased by 6.3% from 2010 to 2011 to 32.5 GW, but fell in 2012 to 28.3 GW, a year-on-year decrease of 12.9%.  As a percentage of peak load, DR potential decreased by 0.7 percentage points from 2011 to 2012.  The main area attributed to the drop is PJM, where the old Interruptible Load as a Resource (ILR) program ended and was replaced with the Reliability Pricing Model (RPM) in which DR has to bid 3 years in advance.

DR Rising

DR resources made significant contributions to balancing supply and demand during system emergencies for several RTOs and ISOs in the summer of 2013.  Heat waves in the eastern United States in the third week of July and in mid-September drove demand for electricity to record levels in some areas.  NYISO activated DR every day for a full work week in July downstate and for 2 days in a row for the entire state.  In PJM during that same week, resources were dispatched for several days in multiple zones, mostly in its Eastern territory.  ISO-NE almost escaped that week without calling on DR, but on Friday afternoon it did need to do so.  CAISO issued calls for consumers to voluntarily reduce electricity use in July due to high temperatures.  Then, after the normal DR summer season was done, a late heat wave in September led PJM to activate DR, and it got the largest amount it has ever received.  In general, summer 2013 was not considered an extremely hot one, so it seems DR deployments are increasing as the technology becomes more deeply incorporated into the markets.

In March 2013, NERC published early stage Demand Response Availability Data System (DADS) results for 2011 summer and 2011-2012 winter.  There were 527 DR deployments during summer 2011, with 6.46 million DR resources enrolled during summer 2011 and 5.34 million during winter 2011-12.  Clearly, DR is not just a summer resource anymore, as places like ISO-NE and ERCOT have dispatched it during winter cold snaps.

Overall, opportunities exist for DR to expand, but there are some headwinds, as discussed in my previous blog on November 19.

 

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