Navigant Research Blog

Utility Customers Respond to Variable Pricing

— September 7, 2014

On July 23, Baltimore Gas and Electric (BGE) customers earned more than $2.5 million by reducing their electricity usage during peak summer heat hours.  Over 640,000 residences voluntarily participated – nearly an 80% participation rate among those who were notified – amounting to an average bill credit of $6.80, enough to buy an ice cream cone while turning down the air conditioning a few degrees.

BGE is the first utility in the country to put all of its customers with smart meters on a default Peak Time Rebate program.

It works like this: BGE customers with a smart meter can participate in the BGE Smart Energy Rewards program by voluntarily reducing their electricity usage to earn a bill credit of $1.25/kWh saved from 1 p.m. to 7 p.m. on designated energy savings days.  Eligible customers will be notified, usually the evening before, by an automated phone call, e-mail, or text message.  BGE anticipates that there will be 5 to 10 energy savings days in a summer season.

Smarter Grids, Smarter Customers

BGE has had a traditional direct load control (DLC) residential DR program for many years, and it has been successful within its own parameters.  However, the company has been installing advanced metering infrastructure (AMI), as covered in Navigant Research’s Smart Meters report, over the last few years, and with that network comes new capabilities (and regulatory requirements to meet cost-benefit thresholds).  AMI provides the utility and potentially customers with near-real-time interval meter data, so the utility can send time-based price signals and get almost immediate feedback on customer performance.  Couple these abilities with new end-user device and thermostat technologies that enable fast response and remote control by the customer, and you have more customer-centric, flexible demand response (DR) programs than were possible before; this can increase customer penetration rates dramatically.

Right on Time

Other innovative companies are trying different variations of programs and pricing offerings.  The Sacramento Municipal Utility District (SMUD) is looking to become the first utility to have a default time-of-use (TOU) rate after running a successful pilot that showed that customers preferred TOU structures to their standard flat rate.  The guiding principles of Oklahoma Gas and Electric (OG&E) for DR include voluntary participation for customers and no DLC by the utility, relying completely on customer empowerment.  OG&E believes that pairing dynamic pricing with technological devices will achieve these goals.  The province of Ontario, Canada has instituted default TOU pricing for customers with smart meters since 2005, the only area in North America to do so.  A traditional DLC program already existed in the province, and now the plan is to combine the control ability of the DLC with TOU pricing to help customers respond to price variations.  Massachusetts is set to become the first U.S. state to mandate default critical peak pricing (CPP) based on a recent order by the Department of Public Utilities.

All of these developments and other innovative programs are covered in Navigant Research’s new report, Residential Demand Response.  The report discusses industry trends around the world and provides 10-year forecasts of sites, capacity, and revenue, including breakouts between DLC and dynamic pricing.  Over time, all these different pilot projects will blossom into full-blown programs and expand into other jurisdictions, creating a truly responsive demand side of the energy equation.

 

New York Details Its Energy Vision

— August 27, 2014

The New York State Public Service Commission (PSC) has released its latest straw proposal on its Reforming the Energy Vision (REV) proceeding.  It includes recommendations that incumbent utilities take on the central Distributed System Platform (DSP) role, at least in the short term.  This was one of the most controversial issues in the REV plan, with the potential for the utilities to be stripped of many of their responsibilities by the PSC and replaced by a new independent entity.  PSC staff decided to stick with the utilities – partly for substantive reasons, partly out of expediency.

The paper includes a table comparing the roles of a utility versus a DSP, exhibiting a great deal of overlap.  So the utilities can breathe a major sigh of relief with that recommendation, knowing that they will maintain many pivotal duties.  But the paper does point out that utilities do not currently have all of the capabilities and competencies needed to successfully operate the DSP and will need to hire new staff with different skill sets, as outlined in my earlier blog on utility hiring trends.

Seeking Alignment

Also noteworthy, from the standpoint of demand response (DR) and distributed energy resources (DER), is the recommendation that all utilities be required to develop DR tariffs, including fees for storage and energy efficiency.  PSC staffers are wary about the potential effects of the pending U.S. Circuit Court case on Federal Energy Regulatory Commission Order 745 on DR compensation, which could complicate DR participation in wholesale markets like the New York Independent System Operator (NYISO).  On the other hand, the report is rather light on recommendations for expanding time-of-use rate structures, which may also encourage increased DR participation.

Addressing the concern about a lack of coordination between retail and wholesale markets, the report states that market rules allowing DER participation in both markets must be aligned to ensure that DER interaction is efficient and properly valued.  The PSC argues that this goal can be accomplished with DSPs acting as aggregators in NYISO programs.  That’s a threatening statement to the third-party DR aggregators that would not want the utility/ DSP to compete with them in the wholesale markets.

Are Smart Meters Necessary?

From the consumer perspective, the report references a recent survey of residential electricity customers in New York that found that, although few customers say they are knowledgeable about their electricity usage, many place a high value on easy access to information regarding their energy use, the price of electricity, and methods for controlling their energy costs.  This indicates the potential for substantial increases in residential customer adoption of home energy management and DER products.

Notably absent from the REV plan is a recommendation regarding advanced metering infrastructure (AMI).  Electricity cost and rate increases are sticky political issues in New York currently, and PSC staff did not highlight AMI as a requirement for achieving REV goals.  The only reference to AMI actually speaks to how to avoid it: “To the extent that the cost of advanced metering equipment presents a barrier to customer adoption of DER programs or time variant pricing, utilities and market participants should consider alternatives to AMI technologies to enable program delivery.”  In other words, the report acknowledges that AMI functionality may be useful for REV purposes, but doesn’t say how that functionality can or should be achieved.

Comments on the straw proposal are sure to be plentiful from all sides.  I view this plan as less aggressive than the original REV paper, but ultimately, it is more achievable in the short term – which may help build momentum for the longer-term transformation.

 

Emissions Plan Powers Energy Efficiency

— June 2, 2014

President Obama has finally unveiled the long-awaited draft carbon emissions regulations on existing power plants.  The goal of the Clean Power Plan Proposed Rule is to reduce carbon emissions from the power sector by 30% by 2030.  While most of the focus is on how this rule will affect coal power plants, it has huge ramifications for the demand-side management and renewable energy sides of the equation, as well.

This is the first time that the U.S. Environmental Protection Agency (EPA) will allow “outside the fence” solutions for such a major regulation.  Instead of requiring unit-specific actions to reduce emissions, regulators will allow each state the ability to submit its own compliance plan by June 2016.  States can choose from a menu of four sets of measures, or building blocks, that the EPA has identified as being eligible for Best System of Emission Reduction (BSER) status:

  • Make fossil fuel power plants more efficient
  • Use more low-emitting power sources (such as natural gas)
  • Use more zero- and low-emitting power sources (renewables and nuclear)
  • Use electricity more efficiently, with a goal of an annual increase of 1.5% in demand-side energy efficiency

Have It Your Way

In addition, states have the option to convert their emissions rate-based goals to emissions mass-based goals in order to set up cap and trade-based systems.  The agency also made it clear that states can develop their own individual plans or collaborate to develop multistate plans, including existing programs, such as the Regional Greenhouse Gas Initiative (RGGI), or new ones.  Finally, the EPA stated that states that have already invested in energy efficiency programs will be able to build on these programs during the compliance period to help make progress toward meeting their goals.

The draft rule is extremely accommodating to energy efficiency.  For states that have existing energy efficiency programs, this presents a new avenue to provide value and expand their reach.  For states that have yet to develop energy efficiency programs, or for those states (mostly out west) that have the highest emissions reductions goals, this rule can act as a jump-start for energy efficiency.  It also provides a roadmap to attain emissions cuts in ways that are more cost-effective than strictly targeting power plants and that have the smallest economic impacts – possibly even economic benefits.

There is still some ambiguity about how solutions like demand response and smart grids will be applied under the plan, but that can be hammered out through comments and negotiations prior to the final rule in 2015.  This is just the beginning of what will be a long, arduous, and likely litigious process – but the opening salvo certainly bodes well for clean demand-side resources.

 

A Dark Day for Demand Response

— May 27, 2014

Two announcements came out late on Friday, May 23 that will have a big impact on the future of demand response (DR).  First, the U.S. Court of Appeals published its decision to overturn the controversial Federal Energy Regulatory Commission (FERC) Order 745 on Demand Response Compensation.  Second, PJM Interconnection, which operates the largest DR market in the world, released results for its 2017-2018 capacity auction.  It reported a drop of more than 10% from last year’s auction and 25% from its peak in the auction 2 years ago.  Depending on your interpretation, these two events could be seen as mild setbacks for DR or major impediments to future growth.

FERC Order 745, which came out 3 years ago, said that DR payments should be the same as those to generators in the wholesale energy markets.  A number of generator and utility groups appealed the ruling and have been waiting for a year to hear from the court.  In a 2-1 decision, the court didn’t necessarily disagree with the order, but determined that DR in the energy markets is a retail product rather than a wholesale one.  This means that the FERC had overstepped its jurisdiction.  On the simplest level, the decision could also mean that independent system operators (ISOs) and regional transmission operators (RTOs) will have to revisit the way they pay DR aggregators for the energy conserved by DR customers.

Death Blow

The bigger question is whether the court’s ruling will be interpreted to mean that all wholesale DR market participation is outlawed, including capacity and ancillary markets.  If so, that would be the death blow to DR in ISO/RTO markets.  It would also destroy the main business model of DR aggregators like EnerNOC and Constellation Energy, the largest wholesale DR players.  Individual states and utilities would have to step in to fill the void to create programs and payment mechanisms for DR to continue at a reasonable level, which would be tenuous and time-consuming.  Other regions of the world that are looking to emulate or learn from the U.S. DR model will take note and may reevaluate their plans.

The recent PJM auction results add to a continuing decline in DR capacity in the northeastern ISO/RTO capacity markets.  Despite the fact that capacity prices in the eastern PJM territory stayed relatively flat from the prior year and the price in the western PJM area doubled, DR declined in both zones.  The bulk of the reduction, however, came from the East.  Some specific utility territories in the West did see increases, like Commonwealth Edison in Chicago and Allegheny Power Systems in Pennsylvania and West Virginia, but the American Transmission Systems, Inc. territory in Ohio was nearly cut in half, outweighing those gains.

Headed Down

EnerNOC publicly released its auction results, stating that received capacity payments for 2017-2018 total $185 million for approximately 4,000 MW, compared to $140 million and 4,400 MW in the prior auction.  So while capacity dropped, value increased due to the higher prices in the West.  The overall 2,000 MW reduction in DR in the last auction was written off by some in the DR community as an anomaly due to depressed prices from a glut of imports from Midcontinent Independent System Operator (MISO).  Now that these results are in, it is clear that DR is in a structural decline.  With further rule changes in the works making DR participation more restrictive, there are headwinds to turning that pattern around.

May 23, 2014 may be etched in the history books for DR depending on the ultimate outcomes.  In any case, it made for interesting fodder at Memorial Day barbecues for those in the industry.

 

Blog Articles

Most Recent

By Date

Tags

Clean Transportation, Electric Vehicles, Energy Storage, Policy & Regulation, Renewable Energy, Smart Energy Practice, Smart Energy Program, Smart Grid Practice, Smart Transportation Practice, Utility Innovations

By Author


{"userID":"","pageName":"Brett Feldman","path":"\/author\/bfeldman","date":"9\/17\/2014"}