Who needs a NOPR? Seven ways to make wholesale power markets more reliable
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Nov 8, 2017
The Department of Energy wants the Federal Energy Regulatory Commission to provide cost recovery to coal and nuclear plants they say provide critical resilience and reliability services to the grid.
But preserving that baseload generation is not likely to enhance those grid attributes, recent analysis argues. A better approach, according to a new report, is to increase the flexibility of the grid by promoting a greater penetration of variable generation and distributed energy resources (DERs).
“A Roadmap For Finding Flexibility In Wholesale Markets” from consultancy Energy Innovation (EI) details seven of the lowest cost ways to make grids more flexible and reliable. New variable generation and DERs will mean increased operational challenges, but grid operators say they are already beginning to put many of the report’s recommendations into practice.
The DOE’s Notice of Proposed Rulemaking, issued at the end of September, asks FERC to provide full cost recovery to power generators that have 90 days of fuel supply onsite.
DOE argues these generators offer reliability attributes that are not properly compensated in wholesale power markets, but the proposal has inspired a widespread backlash in the power sector. From gas generators to renewable energy developers, virtually every stakeholder that would not directly benefit from the NOPR has called for major changes or an outright rejection.
One of the most prominent critiques came from a bipartisan group of eight former FERC regulators who expressed concern that the NOPR would unravel wholesale power markets if enacted.
“The subsidized resources would inevitably drive out the unsubsidized resources, and the subsidies would inevitably raise prices to customers,” they wrote. “Investor confidence would evaporate and markets would tend to collapse. This loss of faith in markets would thereby undermine reliability.”
In their comments at the commission, the former regulators argue DOE has failed to show that reliability or resilience are currently lacking on the U.S. power grid. Fuel supply issues have been an “insignificant cause” of customer outages, they wrote, while a “more robust transmission and distribution system will add resilience in all markets.”
Those comments align with a recent analysis from the Rhodium Group. Last month the consultancy noted that from 2012 to 2016, only “0.00007% of customer-hours” were lost to outages caused by fuel shortages, and most of those came from a single coal generator.
The Energy Innovation report picks up on those themes of grid resilience to advocate for greater power system flexibility.
Already today, grid operators must deal with supply variability caused by nuclear plant maintenance and unpredictable fossil fuel plant outages, researchers note. They could similarly deal with more variability from renewable resources and DERs, the authors argue, though more rapid response flexibility services may need to be developed.
That could pose a challenge to transmission system operators (TSOs), which often lack the visibility or control of DERs on the distribution system, the EI report adds. The flexibility supplied today by natural gas plants with 15-minute response may be inadequate “because you’re increasing the unknown,” report co-author Robbie Orvis said.
With adequate fast response flexibility, TSOs can aggregate dispatchable demand-side resources, which might be anything from “advanced vehicle charging to electric water heaters,” to “act as a giant battery,” EI reports.
But this type of flexibility does not demand federal cost recovery, Orvis said. It can be achieved by “market-based mechanisms” that allow utilities to use DERs to balance supply and demand.
The EI paper defines flexibility as “the ability to respond over various time frames — from seconds to seasons — to changes in supply, demand, and net load.”
The paper argues TSOs must begin by modifying existing market rules and products “to accommodate new technologies and capitalize on their differences.” Properly structured incentives will both put “latent” system flexibility to work and drive investment in “new flexible resources.”
For example, the flexibility offered by fast-ramping natural gas is a latent resource that is “not priced in a way that rewards its flexible attributes,” Orvis said. In addition, energy storage is a new resource that will require changes to existing market rules to be fully valued.
MISO Market Services Division Executive Director Jeff Bladen said such changes are detailed in MISO’s August Roadmap Update. It reports two major market rule innovations — one that compensates fast-ramping resources and another that compensates fast-start resources.
For decades every TSO has had explicit prices for regulation services and there are ongoing initiatives to add inertial response and frequency response, he added.
But arguments for mechanisms to value energy storage’s capability to deliver “virtual inertia” fail to recognize one thing, Bladen said. Systems have more inertia than they need “at virtually no cost from coal and nuclear plants and creating a price for something that would be zero is a waste of time.”
It is not, however, a waste of time to “consider it as a future need,” Bladen acknowledged. That is why MISO’s stakeholders named a “storage resource category” as the TSO’s first priority in the Roadmap Update.
NYISO spokesperson Michael Jamison concurred. NYISO’s stakeholder process is also working on new flexibility products “to help balance the expected addition of large amounts of renewable resources.”
ERCOT Communications Manager Robbie Searcy emailed that the Texas market provides only out-of-market valuation for ancillary services. But flexibility characteristics such as response time are considered in that valuation, she said.
Orvis said every TSO allows some degree of self-scheduling outside of economic dispatch that impedes flexibility. Generators may, because of contractual obligations or the high cost of ramping down, be willing “to run their plants regardless of the price of electricity,” he said.
If they are dispatching at any price, they are not responsive to market prices.
“All generators participating in wholesale markets should be required to participate in economic dispatch,” he said. The market’s resulting wider resource base would provide more flexibility.
MISO effectively limited the consequences of self-scheduling through its dispatchable intermittent resource, Orvis said. It allows grid operators to curtail resources based on price, which optimizes market performance.
Bladen said the right prices minimize self-scheduling. He objected to required economic dispatch because it violates generators’ property rights. “But if they get the right signal about the value of their generation, they will make the best decision.”
Southwest Power Pool spokesperson Meghan Sever said the grid operator is working on market rules and incentives for flexibility, including “quick start resources” and “stored energy resources.” To minimize self-scheduling, it is working on dispatchable day-ahead imports and exports and toward new real-time market rules, she added.
EI’s third proposed solution for increased system flexibility is to preserve negative pricing in energy markets because it maintains efficient, cost-effective dispatch.
Negative pricing most commonly occurs when it is more expensive for an inflexible coal plant or nuclear plant to ramp down than to pay off-takers to take their generation. On rarer occasions, renewable projects may pay to generate, to earn out-of-market incentives.
NYISO’s Jamison, SPP’s Sever and ERCOT’s Searcy all said their systems have no initiatives to change existing rules that allow negative pricing.
But not all operators agree on the merits of negative pricing.
PJM argued in a recent paper that negative pricing can, in a market driven by “flattening supply curves and low demand,” put “financial stress on all units — particularly large units with high capital costs.”
The regional transmission organization filed with FERC in support of the DOE’s call for out-of-market compensation to baseload generation with onsite fuel storage. It sees negative offers as “the result of resources collecting production subsidies.”
Like EI, MISO’s Bladen sees negative prices as “an efficient tool to signal when resources are needed and when they are not.”
EI argues a fourth solution is coordinating natural gas and electricity markets. If natural gas plant operators are allowed to submit supply orders after transmission system operators post day-ahead generator requirements, they can more cost-effectively match fuel costs to market demands.
Historically, “power plants had to guess how much of their output would clear in the day-ahead electricity market and purchase an equivalent amount of gas,” EI reports. FERC’s recent Order 809 eased this dilemma. But most TSOs offer “only a 30-minute window for plant operators to receive their day-ahead commitments and submit purchase orders for gas.”
In addition, CAISO and SPP “still post their day-ahead commitments after the nomination deadline for gas purchases,” EI noted. Only NYISO’s three-hour window “provides market participants with a reasonable amount of time to estimate and submit gas purchase orders.”
Orvis said these timing misalignments prevent resources from responding to market price signals. There should be “at least a one-hour window,” he told Utility Dive. The larger challenge is “we have an electricity market that runs every five minutes and a gas market that runs two or three times a day, which is a clear mismatch,” he added.
NYISO’s Jamison said allowing generators “to update their costs to reflect changes in natural gas costs daily and hourly” is “highly desired in other market areas.”
Generators in CAISO now use forecasts and estimates to work around the timing mismatch described by Orvis, according to CAISO spokesperson Steven Greenlee. California’s system operator is “continuously looking into enhancements for the day ahead market,” he added.
Sever said SPP “has made some enhancements in this area and continues to work to identify additional needs and improvements to allow for improved coordination.”
The fifth of EI’s proposed solutions is to minimize restrictions on resource participation. All the TSOs are working toward similar new rules and products that open market participation to a greater diversity of resource sizes and locations, MISO’s Bladen said. Much depends on the penetration of DERs and variable energy resources (VERs) on each system.
“Addressing relatively arbitrary resource restrictions can tap into a significant amount of flexibility that is available today but going unused,” EI argues.
Orvis said overcoming barriers that prevent smaller, more modular, more nimble resources to participate in markets will open a “really big” opportunity. “If we really want to harness the full set of flexibility on the demand side, we have to tackle some of those barriers. But it’s not a single rule change, it’s a category of rule changes,” he added.
MISO’s Bladen said TSOs are now updating their technology platforms to allow those advances. “The bulk power system is modeled digitally by each system operator but was not designed to dispatch DER, so we would not know if we create a distribution network disturbance,” he said. “A number of system operators, led by New York and California, are working on resolving these constraints.”
Jurisdictional conflicts make it more likely that TSOs would coordinate with distribution system operators (DSOs) “to support their use of DER,” Bladen added. “The relevant questions, which are still very much unanswered, are when technology platforms will be able to accommodate DER and how the jurisdictional issues will be sorted out.”
Orvis combined EI’s sixth and seventh solutions. They are defining, valuing and pricing flexibility services so all existing and new resources can be bid into and compensated by the market.
New products should be focused on the market’s needs, EI argues. That should lead to compensation for products that take advantage of a resource’s unique qualities to meet a need, “providing additional flexibility at the lowest cost.”
Energy storage can provide regulation services more efficiently than traditional thermal generators and should be able to compete against them, even though it is “energy-limited,” the report adds. Most TSO rules, however, tend to create barriers for newer technologies like storage.
NYISO’s Jamison and SPP’s Sever agreed. The market should “determine value through pricing,” Sever said.
Orvis said new demands to meet the challenge of DERs and VERs are becoming increasingly evident. Fast ramping is needed when the sun goes down where solar penetration is high. Frequency response is needed where traditional spinning generators are being shuttered.
“The best way to identify necessary new services and procure them is through markets,” he said.
Source:
https://www.utilitydive.com/news/who-needs-a-nopr-seven-ways-to-make-wholesale-power-markets-more-reliable/510062/
