Navigant Research Blog

Winter Is Over: NYISO Releases Distributed Energy Resources Roadmap on Groundhog Day

— February 9, 2017

The New York Independent System Operator (NYISO) unveiled its much-anticipated Distributed Energy Resources (DER) Roadmap on Groundhog Day, meaning that winter is almost over for DER in the wholesale energy market. I attended the first meeting in this process last September, and NYISO has done a good job of having an open, transparent stakeholder process throughout and leading up to the final roadmap release.

NYISO has had demand response (DR) programs for over 10 years, but it may not be appropriate to simply use those same market rules for other types of DER. Energy storage, solar, and other types of distributed generation have different attributes than either DR or centralized, large-scale generation, so a new category of rules is required.

Electrical Grids of Today and Tomorrow

(Source: New York Independent System Operator)

One of the more intriguing proposals in the document pertains to capacity market participation for DER. NYISO says that it recognizes that not all DER will be able to deliver capacity in all 24 hours of a day (as a generator would be) in order to earn full capacity payments. It proposes a three-tiered service structure: full 24-hour service, on-peak service covering early morning through late evening, and daytime peak service for daily peak hours. While this proposal appears amenable for DER, the big question is how compensation will be prorated. Should it simply be done based on the number of hours available? Do peak hours have greater value than off-peak hours? That’s where the real value of the proposal will be determined.

One of NYISO’s primary reasons for this undertaking is to coordinate with retail energy markets, specifically aligning with the New York Public Service Commission’s (NYPSC) Reforming the Energy Vision (REV) proceeding. However, this strategy may be altered by another big news story from the last couple of weeks, that the NYPSC Chair and guiding force of REV Audrey Zibelman is leaving in March to take over as head of the Australian Energy Market Operator. That transition somewhat clouds the future of REV (at least in terms of the timeline for change, if not the content).

Hope for Standardized Rules?

Other Regional Transmission Organizations (RTOs) such as PJM and the California ISO have also undertaken DER processes and developed new market rules for these resources. Some of the biggest areas of contention have involved issues like aggregation, metering, interconnection, and performance measurement. I don’t expect any kind of national standards to result as each RTO’s markets and resource bases are unique; however, some level of commonality would help lower costs and barriers for vendors trying to develop projects in different regions.

The NYISO’s roadmap lays out a 2-4 year timetable for getting from concept to implementation for various aspects of the market changes. While not a quick, overnight snap-of-the fingers process, for the energy world it is an ambitious plan.

 

Accurately Measuring Savings from Integrated Distributed Energy Resources Offerings

— January 31, 2017

AnalyticsEnergy efficiency and demand response (DR) programs have long been administered by utilities, third parties, and local governments using taxpayer or ratepayer funds. Most recently, integrated offerings that span energy efficiency, DR, and other program areas have become more feasible due to the advent of the smart grid. The integration of information and communications technologies with the power system is enabling a better balance between demand and supply side resources.

Integrated offerings are key indicators of a broader integrated distributed energy resources (iDER) future. Identifying program design and savings attribution methodologies for harnessing the benefits of these resources are critical to enabling public support for the innovators that will populate this future with integrated offerings that bundle value streams into streamlined solutions. While existing program design and funding constraints may not be able to seamlessly support these emerging technologies, avenues are opening and should be explored so as not to thwart the iDER future.

In a new white paper, Navigant presents a methodology to account for all of the energy and demand savings from an integrated energy efficiency and DR offering on an annual basis. The methodology separates the attributes of each program type while avoiding double counting of savings across programs. It also proposes methods to accurately portray the costs and benefits of each program.

Methodology Breakdown

Methodology BF

 (Source: Navigant)

Navigant recognizes that each jurisdiction has its own policies and protocols for operating an  iDER offering. Ongoing activities in New York and California provide relevant lessons in light of the states’ recent focus on iDER. Navigant used examples of these lessons to identify key considerations across three areas that integrated offerings focusing on energy efficiency and DR should consider when developing implementation plans:

  • The importance of data granularity for analysis
  • Exploring legislative channels to support integrated offerings
  • A focus on avoiding double counting benefits

Navigant draws the following conclusions from this assessment for consideration by relevant stakeholders, including utilities, other program administrators, regulators, customers, and third parties:

  • Well-established methodologies and protocols exist for quantifying energy and demand savings for energy efficiency and DR offerings across North America.
  • Advanced generation thermostats have a proven market track record of providing demonstrable benefits for energy and demand savings through established methodologies and protocols to verify and attribute savings.
  • Energy efficiency and DR programs are funded and evaluated through individualistic incentive budgets; a structure that confounds shared budgeting for cross-program functionality and hampers integrated offerings from capitalizing on their multiple value streams to gain market traction.
  • To avoid discouraging innovators from pursing integrated offerings, regulators and utilities without integrated evaluation methodologies should consider the methodology to develop interim polices and protocols for iDER offerings to count savings in two or more program areas until an integrated methodology can be developed through official channels.
 

FERC Releases Latest DRAM Report

— January 11, 2017

ControlsIn December 2016, the Federal Energy Regulatory Commission released its 11th annual Assessment of Demand Response and Advanced Metering (DRAM) report. The report is meant to provide an update on national, regional, state, and utility progress in these two interconnected fields. Much of the report focuses on data and growth trends, but it also delves into regulatory and policy drivers and barriers in the markets to explain the trends. Publicly available data sources such as the US Department of Energy, regional transmission operators (RTOs), and state public service commissions were used for the analysis.

Expanding Markets

Starting on the metering side, the DRAM report states that an additional 6.6 million advanced meters were installed and operational in the United States between 2013 and 2014, for a total of 58.5 million meters. The penetration of advanced meters is also up from approximately 9% in 2009 to 41% in 2014. Regionally, Texas has the highest penetration at 80%, the Western Electricity Coordinating Council (including California) sits at 60%, and Florida is at 57%. After that, there is a large drop-off, with no other region above 35%; the Northeast Power Coordinating Council (New York and New England) is the lowest at 10% as of 2014. The report notes regulatory activities in numerous states that point to continued deployment of advanced metering infrastructure (AMI) across the country.

Regarding demand response (DR), potential peak reduction in the RTOs, independent system operators (ISOs), and Electric Reliability Council of Texas (ERCOT) markets increased to 31,754 MW, a 10% increase from the previous year, outpacing peak demand growth of 4%. The contribution of potential peak reduction to meeting peak demand increased to 6.6% in 2015, up from 6.2% in 2014. This increase can be explained to some degree by changes in the ISO-NE and PJM markets, which display the largest increases. The ISO-NE data includes energy efficiency, which continues to grow in the region while DR has remained flat. In PJM, the capacity price increased significantly in 2015, leading to a rise in DR in the market. However, in 2016, the price went back down and DR participation dropped.

Utilizing New Resources

The report also notes that the North American bulk power system is integrating an increasing level of DR, variable energy resources, and distributed energy resources. As a result, the North American Electric Reliability Corporation (NERC) is considering how these resources can be reliably integrated into the operation and planning of the bulk power system, as well as how these resources affect generation and load resources. To better understand and measure the performance of DR, NERC developed and approved four new DR metrics in 2015. These new metrics measure enrollment and event information to determine actual performance, including the resource’s contribution to improved reliability. Future efforts intend to focus on improving data collection, maintaining data quality, and providing observations of possible DR contributions to reliability.

The report closes by highlighting three barriers to DR growth: implementing time-based pricing, lack of additional market opportunities beyond emergency/capacity type programs, and coordination of federal and state policies. Those should all be easy to overcome by the next DRAM report in a year, right?

 

Wrapping Up a Tumultuous Year for Demand Response

— January 3, 2017

Power Line Test Equipment2016 started off with a bang for demand response (DR) with last January’s seminal Supreme Court decision on Federal Energy Regulatory Commission (FERC) Order 745. That beginning might have marked the high point for the year in DR, as various events in the regulatory, market, and corporate realms had a mix of positive and negative effects on its overall growth.

Regulatory

Champagne bottles were popped on January 25 in the offices of EnerNOC and other DR companies and advocates after the Supreme Court gave an unexpectedly early and overwhelming 6-2 decision that reversed the US Court of Appeals’ decision on FERC 745 on both parts of the case. The ruling established that DR does fall under FERC’s jurisdiction and that the payment of the full Locational Marginal Price (LMP) in the wholesale energy markets is just and reasonable.

It seemed like an auspicious start to 2016 for DR. However, counterbalancing the good news to some extent were the US Environmental Protection Agency’s (EPA) rules for emergency generators (EGs) for DR purposes. In 2015, the US Court of Appeals overturned an EPA rule that allowed 100 hours of EG use for emergency DR programs. It granted the EPA a 1-year stay, which expired on May 1, 2016. The EPA had no plans to make changes to the rule, meaning that the court’s ruling remained intact, affecting upward of 20% of DR resources in some markets.

Markets

On the market side, wholesale and retail developments affected DR prospects. The annual PJM Base Residual Auction (BRA) price results for the 2019/20 delivery year came in lower than most analysts predicted. There were actually more DR megawatts offered into this auction than the year prior, but fewer megawatts actually cleared, likely due to the reduced price. Only about 6% of DR megawatts cleared as Capacity Performance (CP), with the vast majority clearing as Base Capacity product. With the Base product set to be abolished for the next auction, there is a big question as to how much DR will clear in a CP-only environment.

While there may be no cohesive national energy plan for the United States, several individual states have taken matters into their own hands to modernize the electric grid, with New York and California taking the lead. In both states, utilities held auctions in 2016 to procure distributed energy resources (DER), including DR, to address electric grid needs. California’s investor-owned utilities—Pacific Gas and Electric, Southern California Edison, and San Diego Gas and Electric—ran the second edition of the state’s Demand Response Auction Mechanism (DRAM). New York took the spotlight in the form of ConEd’s Brooklyn Queens Demand Management (BQDM) auctions in July.

Corporate

2016 saw several corporate activities with major and emerging players in the DR arena, beginning in May with the announcement that Opower was being bought by Oracle for over $500 million. Later that same day, word spread that CPower acquired rival Johnson Control’s Integrated Demand Resources business. Not to be overlooked, AutoGrid, a DR management system and data analytics vendor, announced a new $20 million investment led by Energy Impact Partners. Finally, EnerNOC undertook several actions that raised questions about its future direction. First, it announced that it was ready to divest its acquisition of Pulse Energy’s utility customer engagement business from a couple of years ago, essentially laying off 5% of its North American workforce. A few months later, the company announced a restructuring, which included laying off 200 employees, mainly focused on the enterprise software side of the business. I don’t foresee 2017 being as active as the last, but a new administration in the White House could bring unforeseen changes to the DR landscape.

 

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