This post was originally featured on the America’s Power Plan blog. To view more Q&As, go to APP’s “Ask the Experts” page, or check out APP’s monthly newsletters, which include previous Q&As and much more.
By Sonia Aggarwal, Eric Gimon, and the experts of America’s Power Plan
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: We are trying to support clean “non-transmission alternatives” for our system, but they don’t fit easily with our transmission planning process. Do you have any suggestions?
A: Innovative technologists and entrepreneurs have opened up many new options to use in a portfolio of resources that can keep the grid in balance. Clean distributed energy resources like energy efficiency, demand response, energy storage, and distributed generation can be used alongside transmission and distribution to provide vital grid services, such as avoiding capacity shortages in transmission-constrained load pockets or providing voltage support where it is needed most. But outdated regulatory processes have led to these “non-transmission alternatives” (NTAs) being undervalued and underused.
Historically, the primary venue for stakeholders to influence resource decisions was during integrated resource planning proceedings before state PUCs. Demand-side resources have typically been accounted for as reductions to load rather than as cost-competitive alternatives to supply-side resources like transmission and utility-scale generation. As a consequence, the value of NTAs has been steeply discounted. Updating these regulatory processes and methods for evaluating alternatives is the easiest way to enable NTAs to compete, although occasionally a carve-out or specific pilot program might be necessary to open the spigot.
Taking a closer look at the New England Independent System Operator (ISO-NE) illustrates how this systemic bias against NTAs connects to the transmission planning process. Traditionally, ISO-NE has studied long term reliability and grid security using a deterministic methodology that assumes certain load profiles and generation availability. That deterministic transmission planning process remained disconnected from the resource adequacy assessments in ISO-NE, which use a probabilistic, competitive approach. Market participants bid into the power markets under the resource adequacy framework to ensure sufficient resources to meet load, allowing demand-side resources to participate, but in effect separately from the assumptions that were used to determine necessary transmission investments. Different planning horizons also confound the issue in ISO-NE: transmission planning uses ten years while resource adequacy uses 3½. Since ISO-NE does not forecast resource adequacy beyond 3 ½ years, it keeps distributed resources constant over the 3½ to 10 year horizon. By holding those numbers constant, ISO-NE substantially underestimates the potential for distributed resources.
This highlights a central challenge in using competitive markets to select for resources in an infrastructure-heavy system reliant on the laws of physics. It also sheds light on the way that transmission planning pre-selects for the kinds of resources that are easy to model (centralized, dispatchable plants) as opposed to demand-side resources that may be more probabilistic in nature (think: planners may not have sufficient experience with demand response aggregated across many different distributed actors) or resources that show up in the hard-to-model distribution system. Compounding this, NTAs most often cannot recover costs for transmission-level services, due in part to state versus federal jurisdictional issues, though some states are forming agreements on cost allocation. The recent decision on FERC Order 745 regarding payment for demand response in power markets may create further challenges. So, even in the cases when NTAs are cheaper and more reliable, simply allowing them to compete on equal footing with traditional supply-side resources may not be enough to overcome the planning bias.
Thankfully, both New England and California are experimenting with solutions to enable NTAs to compete more equitably with transmission, but it’s still too early to tell which options will be most effective. ISO-NE has developed a white paper on Aligning Markets and Planning, in part to address how best to integrate NTAs into the planning process. To test these ideas, one pilot in Vermont and New Hampshire divided the region into subareas and examined supply-side resources and demand-side resources separately. Results showed that all reliability constraints could be met in all scenarios by a total of 1935 MW of supply-side resources or 1760 MW of demand-side resources. As a result, ISO-NE was able to defer or avoid $265.4 million in transmission expenditures.
Since then, ISO-NE has also created (and chairs) the Distributed Generation Forecast Working Group, which is an open stakeholder group that provides data and feedback on forecasting future levels of distributed generation in New England. Forecasts are currently based on state policy goals and funding for solar. Despite taking these important steps forward, ISO-NE has not yet analyzed the potential for hybrid solutions—with both demand- and supply-side resources replacing some transmission upgrades, while keeping the highest value (least cost) transmission upgrades that are most difficult to replace with NTAs. This type of transmission modeling could connect quite effectively with an integrated distribution planning process like the one we discussed in the first question in Energy Experts Unplugged Volume 6 and in Integrated Distribution Planning: A Path to Sustaining Growth.
Meanwhile, California is taking a somewhat different tack: the California PUC recently consulted with stakeholders and then decided to order procurement of fewer centralized resources than was requested by the California Independent System Operator (CAISO), and has instead called for procurement of more distributed resources. Still, the state is struggling with how to fairly compare these different kinds of resources as part of the procurement portfolio. The CAISO continues to consider these topics carefully, having released a paper considering NTAs last September, and following it up in December with a demand response and energy efficiency roadmap that describes a “load-reshaping path” for dealing with future system requirements.
Taking yet another approach to this challenge, PJM is considering using Requests for Proposals (RFPs) for specific reliability issues that need to be resolved, allowing NTAs to bid in alongside transmission and distribution solutions. The first RFP-for-reliability tested in PJM was the “Artificial Island” RFP, in which PJM was looking for solutions to a generation pocket created by two nuclear stations, so it was not well-suited to NTAs. That first RFP-for-reliability received 26 proposals that took about nine months to review, indicating that the RFP model appears to be working well for PJM. Moving forward, PJM is likely to issue similar RFPs to solve load pocket issues, which would be more appropriate for NTAs to bid into alongside traditional transmission solutions.
These kinds of pilots and changes to procurement practices or market mechanisms are all important first steps, alongside a consideration of possible updates that could align planning and market practices to support NTAs as part of a portfolio with transmission. Changing the way that utilities are financially rewarded for delivering grid services could also make a big difference here — New York (see the first question in Energy Experts Unplugged Volume 7), California, and Hawaii are all exploring possibilities along those lines.
For more information, the Interstate Renewable Energy Council, the Regulatory Assistance Project, the Sustainable FERC Project, and the Clean Coalition continue to consider these issues from a non-governmental perspective. Aligning Power Markets to Deliver Value, Policy Implications of Decentralization, and Supporting Generation on Both Sides of the Meter each provide more perspective on this question as well.
Q: How can we better engage mass-market customers to see better results from new rate structures or demand-side management programs?
A: Customer engagement has somewhat of a different flavor than the usual things that regulators and utility engineers think about. Contemplating customer engagement leads quickly to the intersection of economics, technology, and behavioral science. Several annual meetings have been organized to highlight relevant work in these areas: the National Town Meeting on Demand Response and Smart Grid and the Behavior, Energy, and Climate Change conference are two of the best, and they both post many of their presentations online.
The first thing to note is that it pays to simply choose the right name for a program. Peter Cappers from Lawrence Berkeley National Lab gave a rundown of the results of the stimulus-funded Smart Grid Investment Grants’ consumer behavior studies at last year’s National Town Meeting. He reported that many utilities believed that words like “critical,” “emergency,” “auto,” and “events” would help to induce participation in new types of rates, but focus groups and other research efforts showed that such terms were considered reactionary and thus ineffective at driving participation. Customers were more willing to take up offers that included terms like “control,” “choice,” and “sense.” Many utilities have found focus groups and surveys to provide vital feedback on marketing methods to attract customer interest in participating in innovative rate structures.
Once the naming is down, the Smart Grid Consumer Collaborative has some great advice (backed up with clear case studies) for other core ingredients for successful consumer engagement: educate customers before deployment, anticipate and answer questions before customers ask them, facilitate community engagement, communicate ways to shift usage off-peak, deploy a user-friendly web portal, offer user-friendly smart grid enabled technology, and create authentic customer testimonials.
The details of program structure can also play a major role in determining whether a customer engagement campaign is successful. For example, there appears to be a significant divide in effectiveness between opt-in programs and default programs. A pilot study in the Sacramento Municipal Utility District (SMUD) showed a high acceptance rate for opt-in rate plans with time-of-use (TOU) or critical peak pricing (CPP). And, when given a choice, consumers prefer TOU over CPP. But when the rate plans were implemented as the default (rather than allowing customers to opt-in), the majority of customers perceived the plans as fair, and the program resulted in more demand-side resources available to grid operators. Studies show that opt-in programs produce greater average load reductions per customer, while default plans provide greater aggregate load reductions. Given these findings, SMUD executives are considering rolling out default TOU pricing for all residential customers starting in 2018.
Q: I am getting questions about the costs and benefits of our state Renewable Portfolio Standard. What are some good resources to turn to? What is the national trend?
A: It is difficult to evaluate the costs and benefits of a Renewable Portfolio Standard (RPS), and any analysis depends heavily on the assumptions, methodology, and the particular state context. There is no uniformly accepted methodology as yet. Still, a recent study from the National Renewable Energy Lab and Lawrence Berkeley National Lab gives an excellent state-by-state review of costs and benefits. The labs’ analysis reflects the state of the art in our understanding while making it clear that further research is needed.
The analysis suggests that costs are not very high, and are likely outweighed by economic, health and environmental benefits. Specifically, RPS compliance costs came to less than one percent of retail electricity rates on average across the US. In restructured markets, costs ranged from 0.1-3.8 percent of retail rates. Vertically-integrated states (not including California) saw everything from a net benefit of 0.2 percent to a net cost of 3.5 percent of retail rates. For the eight states in which utilities assess a direct RPS surcharge to customers, they ranged from $0.50/month to $4/month.
While these costs stand relatively low on their own, it is important to note that these estimates often do not consider the broader social benefits of renewable energy deployment. Quantifying these benefits can be even trickier than quantifying the costs, but most experts agree there is substantial value in reducing pollution, saving water, diversifying fuel sources, stabilizing electricity prices, and driving broader economic development.
The labs’ report identifies eight studies that assess the societal benefits of the RPS, and they find the benefits to be in the range of $0.004 to $0.023 per kilowatt-hour. Macroeconomic analyses suggest the benefits range from $0.022 to $0.03 per kilowatt-hour. In addition, the competition from renewable energy depresses wholesale prices, yielding benefits on the order of $0.002 to $0.05 per kilowatt-hour. Even given these analyses, it is clear from the studies that not all societal benefits have been analyzed.
It bears repeating that all of these numbers rely heavily on the assumptions, methodologies, and the particular state context. Nonetheless, a casual look at the available analyses of RPSs seems to suggest that benefits outweigh costs. Clearly, there is plenty of room for debate and more studies and approaches would be useful.
Still, the relatively wide range of estimates also exposes an excellent opportunity: there is plenty of room for good policy and regulation to drive better implementation of renewable standards. Moreover, the steep drop in price for renewable generation should help further reduce costs or even drive them into negative territory, as long as integration costs for variable generation can be maintained at the relatively low levels seen today.
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Thank you to Ake Almgren, Allison Clements, Stephanie Wang, and Rory Christian for their input for this piece. The authors are responsible for its final content.