This is the next edition in a monthly series of short answers to some of the questions we’re hearing from public utilities commissions, market operators, utilities, legislators, and other energy decision-makers. Click here to see the answers from last month.  Submit your question today by emailing APP [at] energyinnovation [dot] org.

Q: I’ve heard about New York’s vision for a new kind of distribution utility, can you tell me more?

A: The New York Public Service Commission recently put out an ambitious call to action in Reforming the Energy Vision, a proposal to fundamentally alter the way that New York’s utilities are regulated, modifying their structures and financial incentives to integrate new technologies, take advantage of competition, and accelerate efficiency and clean energy.  The regulatory model will move away from cost of service toward a more outcome-oriented form of regulation.  The plan for New York’s reform also includes substantial rate reforms, with a longer timeline between rate cases that can give the utilities more space to innovate. The vision highlights demand-side resources as a major tool to manage New York’s electricity system.

Superstorm Sandy set off a series of discussions in New York about the need for a more resilient power grid, opening the door for this historic docket.  Regulators have also recognized this kind of utility restructuring as a way to address ongoing frustration with a system that has excess supply that sits idle most of the time, waiting to meet retail peak demand (which reaches 75 percent over average load during some times of the year).  Despite using existing assets only 60 percent of the time on average, the system still suffers from bottle necks.  New York is likely to face extreme weather events more frequently, yet the power system has been increasingly dependent on gas to meet its growing peak, despite huge unexploited opportunities for demand-side management.  With demand flat, growing self-generation via rooftop solar, volatility in natural gas supply and price, and more variable generation entering the system, New York is looking for a solution that will empower the economy with a more reliable, resilient, efficient, and clean electricity supply. 

This new docket highlights emerging opportunities to address challenges that currently face power systems around the country.  New technologies and industries are now enabling a fundamental change in the way distribution utilities serve their customers, giving them the opportunity to become system optimizers rather than unit dispatchers.  These technologies improve the utility’s capacity to diagnose faults, re-route power flows, and provide real-time system awareness and control.  Information technology makes it easier for customers to manage their electricity demand, while costs are dropping for distributed energy resources like rooftop solar, storage, combined heat and power, and building management systems.  At the same time that all these changes are happening at the distribution level, New York can take advantage of existing resources: its Independent System Operator is designed to manage the interface with the bulk power market; NYSERDA provides a strong R&D capacity; and the new Green Bank has opened up financing resources.  All of these factors add up to allow the Public Service Commission to question two assumptions behind the traditional regulatory model: 1) that customers have little or no role to play in addressing system needs, except in times of emergency, and 2) that centralized generation and bulk transmission is invariably the most cost effective set-up, due to economies of scale.

Reforming the Energy Vision proposes a new approach in which demand management can be used not as a last resort but rather as a cost effective, primary tool to manage distribution system flows, shape system load, and enable customers to choose cleaner, more resilient power options.  This approach rests on the premise that it is technically feasible to fully integrate energy-consuming equipment, distributed generation, and storage into the management architecture of the electric grid.  They don’t intend to replace central generation, but rather to complement it in the most efficient manner, and to provide business opportunities to a new class of energy service providers.

The “Distributed System Platform Provider” (DSPP) is at the core of New York’s vision.  This transformed distribution utility will provide the interface between individual customers, new energy service businesses that aggregate customers, and the bulk power system.  The DSPP will actively coordinate customer activities so that the service area places more efficient demands on the bulk system, at the same time as it reduces the need for expensive investments in the distribution system by taking advantage of distributed resources.  The DSPP will create markets, tariffs, and operational systems to enable new energy service businesses to make money by providing value to the utility system and thus to all customers.  Resources provided could include energy efficiency, predictive demand management, demand response, distributed generation, building management systems, microgrids, and more. 


In order to bring into existence the new DSPPs, New York’s regulators acknowledge that the current regulatory paradigm must be revised.  The commission staff recommends a pragmatic approach, in which the transition to a DSPP model occurs through incremental steps that are guided by a clear set of long-term goals and objectives.  They place an emphasis on developing platforms that support innovation while providing the appropriate level of protections to consumers.  By focusing on these long-term goals and objectives, they aim to lay out risk and reward mechanisms that enable innovation without selecting the winning technology or products.

America’s Power Plan has been coordinating with New York’s commission staff on these topics since last fall, and many elements of this vision align well with the ideas put forward in papers like Rethinking Policy to Deliver a Clean Energy Future, Utility and Regulatory Models for the Modern Era, and Policy Implications of Decentralization, which are all cited in the docket amongst other papers from America’s Power Plan.  Also cited is an important paper from the Advanced Energy Economy Institute, which put forth ideas from a working group that included every utility in New York, as well as several advanced energy companies.  The commission in New York has also tapped two more partners of America’s Power Plan, the Rocky Mountain Institute and the Regulatory Assistance Project, as formal advisors on this docket.


Q: I’ve heard that it’s not worth it to add more renewables to reduce carbon emissions given the inflexible fossil fuel plants in our current fleet, considering the extra firming and power plant cycling renewables will induce, is that true?

A: The short answer is no – the emissions benefits from increasing renewables far outweigh the penalties from operating the rest of the system differently.  But this was a big enough question to warrant some important engineering studies.

Increasing shares of variable resources like wind and solar can cause fossil-fueled plants to ramp up and down more frequently.  Because some plants—especially many baseload coal plants—were not designed for this type of cyclic operation, this new way of operating the plants can cause increased maintenance costs.  Some have asserted that this change in the way fossil plants are operated may also cause more incremental emissions than the wind and solar additions reduce.  But, to the contrary, detailed engineering studies have found that the emissions reductions from wind and solar far outweigh emissions imposed by variability-induced cycling. 

The National Renewable Energy Laboratory recently conducted a study involving a detailed operational analysis of the Western Interconnection to examine the effects of running the current fossil fleet differently to balance increased levels of variability at higher shares of wind and solar.  The study focused on the wear-and-tear costs and emissions impacts from ramping fossil-fueled plants up and down to balance supply variability.  With scenarios looking at 33% wind and solar, the average fossil-fueled plant saw cycling costs increase by $0.47–$1.28/MWh of fossil-fueled generation, compared to operational costs of $34.50/MWh for coal or $50.80/MWh for conventional combined cycle natural gas (according to EIA’s Annual Energy Outlook 2013).  The analysis showed that cycling impacts on CO2 emissions were negligible.

On the other side of the country, PJM studied the impact of increasing shares of renewables (up to 30%) on emissions.  That analysis also found that increased cycling of fossil resources would occur, but the penalty against the large carbon emissions reductions from fuel switching would not be significant.  A 30% reduction in energy generated from fossil plants was matched by a 29% drop in carbon emissions.  The small difference originated from the cycling to follow variable load.

In addition to examining the effects on CO2 emissions, both NREL and PJM’s studies also looked at other pollutants like NOx and SOx.  Here, increased cycling had a slightly larger effect on overall emissions, but not always in the way one might expect.  For example, a heavy wind scenario for the NREL study showed an even better emissions reduction than expected.  Coal plants account for the vast majority of NOx and SOx emissions, so the study’s results depend heavily on how renewables impact coal generators specifically.  Overall, though, the answer is still the same: direct pollution reduction benefits from increasing the share of renewables far outweigh any possible penalty that might come from operational changes.  Similarly, we expect that the reduction of wholesale electricity rates driven by renewables will likely be far more significant for fossil plant economics than the extra O&M costs from cycling-induced wear and tear.


Finally, it is our estimation that neither of these studies fully considered demand-side solutions to increased supply-side variability.  Resources like demand response and targeted energy efficiency programs can effectively balance predictable variability, and when deployed at scale, they can reduce the need to cycle traditional fossil fueled plants.


Q: If I opened up a market for a capacity or ancillary service product with previously un-monetized characteristics (e.g., minimum ramp time in kW/hr, minimum CO2/kWh standard, etc.), how do I know any new technologies show up? 

A: In any market, of course, there are no guarantees that new entrants will come in with more efficient solutions.  The product being tendered needs to be clearly defined and realistically scoped.  There also needs to be attractive – more than marginal – economic potential and enough assurances of stability and protection from incumbent market power to justify investment risk.  Another important element for success is to focus on the outcome you want, not on pre-conceived notions about what technologies might achieve it. 

Let’s take the example of new markets (or products) for peak management, fast regulation, flexibility, or ramping.  One might anticipate that those system needs would be met at least-cost by new, quickly adjustable gas plants or by traditional pumped-hydro storage.  But the truth is that there are a whole host of potential technologies that could bid into a market that values this kind of flexibility.  Here are two examples.

First, turbine inlet air chilling technology with thermal energy storage from TAS provides an excellent means of providing extra ramping and generating capacity on a hot summer day.  If a combined cycle gas turbine is rated at 500 megawatts (MW), it means that the turbine produces 500 MW when the outside temperature is 59°F.  But, as the outside temperature increases, the power output decreases – i.e., it’s less efficient at higher temperatures.  Specifically, that “500 MW” turbine might only be able to produce 425 MW on a 95°F day.  That’s a problem for the parts of the country where peak demand happens on hot summer days.  On those 95°F days, grid operators are looking for whatever power they can possibly dispatch to meet demand, but they’re down 75 MW from the rated capacity of that plant.  But the drop in combined cycle gas plant output that happens as temperatures increase is matched by a symmetrical increase in output as temperatures decrease.  For example, if you cool the turbine’s inlet air temperature down to 48°F, the same “500 MW” plant (which is really only producing 425 MW at 95°F) now produces around 520 MW.  That amounts to about a 95 MW flexibility opportunity. 

A generator equipped with turbine inlet air chilling technology with thermal energy storage from companies like TAS or Stellar can buy power from the grid at cheaper wholesale rates in the middle of the night (often times when there is inflexible baseload power or excess wind that might otherwise be curtailed) and use that electricity to run water through a chiller.  They can then store that water in an insulated water tank, and use it later to chill the air entering the turbine during the hottest part of the day.  If the difference in temperature between day and night is large enough, it is even sometimes possible to get more energy out of the more efficient gas turbine than they used to chill the water the night before. 

It costs somewhere between $200-250/kilowatt (kW) to deploy this inlet air chilling system if it is designed into the gas plant from the beginning, and it costs $300-450/kW to retrofit an old gas plant with this inlet air chilling system.  For comparison, a new simple-cycle peaker costs around $900/kW.  Given these numbers, it’s obvious which peak management technology is more cost effective from a system-wide perspective.  Yet many regulatory barriers still exist for this type of non-obvious solution.

For the second example, imagine a large corporate campus with 500 electric vehicles (EVs) charging at a maximum of 10 kW each.  Because the cars don’t need to be full until the end of the work-day, that’s as much as 5 MW of potential regulation or ancillary services that grid operators can call on anytime within an eight hour window during the day.  Timing the charging near sunset on an early spring day could mitigate up to 5 MW of ramping need by “shrinking the belly” of the famous California duck curve.  If the EVs are used for “regulation up,” their batteries never need to be discharged, and these services could be provided to the grid while causing very little wear-and-tear on the batteries.

Now imagine 100 campuses on the same program, providing 500 MW of fast-responding ancillary services.  Part of the value here is in the statistical magic of large numbers: with 50,000 EVs at play and only a few drivers likely to leave work early or opt-out of the program any given day, the aggregate resource can be very predictable and can provide an even more reliable product than a fast ramping gas turbine subject to occasional outages.  A managed fleet of EVs could be cheaper, more responsive to needs, more elastic in its response to bulk prices, more reliable and less volatile in price than the alternatives.  

Yet this kind of resource currently has trouble participating in a market because of barriers like arcane procurement rules or overly-stringent and counter-productive metering requirements.  Rules that were designed around large plants may not work for these kinds of distributed resources.  For example, paperwork for adding one 10 kW EV “generator” may take up to a month to complete, while an EV “power plant” is likely to contain many of these 10 kW generators, and is likely to add new increments quite often.  The administrative burden of having to apply for market participation in series may prevent these kinds of power plants from coming online.

These are just two examples of unexpected resources that could provide great system benefits if they were allowed—or more easily able—to participate in power markets.  It is possible to design wholesale markets (or market products) efficiently by clearly defining the measurable parameters and services the grid needs, and then allowing all kinds of technology to bid in to meet those parameters.  As described in Aligning Power Markets to Deliver Value, by allowing all resources (including both supply-side and demand-side) to bid, we can get the flexibility we need to move toward a more diverse generation portfolio with less pollution at a lower cost.


This post was written by Sonia Aggarwal and Eric Gimon.

Thank you to Willett Kempton, Greg Brinkman, Rudy Stegemoeller, and Kelsey Southerland for their input for this piece. The authors are responsible for its final content.


  • Our nation’s electricity system is undergoing a rapid transformation. Market forces, driven by public demand for cleaner, more efficient energy, and technological innovation are redefining America’s power sector. These trends will change the electricity system and utility businesses at their core. But our century-old legal, economic, and regulatory structures are thwarting innovation. More than 150 top energy experts from academia, industry, and non-profits have joined America’s Power Plan, a project designed to tackle the tough questions and provide a vehicle for policymakers at the state and local levels to address these challenges and make informed decisions about the future of our nation's power system.

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Our nation’s electricity system is undergoing a rapid transformation. Market forces, driven by public demand for cleaner, more efficient energy, and technological innovation are redefining America’s power sector. These trends will change the electricity system and utility businesses at their core. But our century-old legal, economic, and regulatory structures are thwarting innovation. More than 150 top energy experts from academia, industry, and non-profits have joined America’s Power Plan, a project designed to tackle the tough questions and provide a vehicle for policymakers at the state and local levels to address these challenges and make informed decisions about the future of our nation's power system.

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