AUSTIN, Texas — Potomac Economics’ David Patton told ERCOT’s Board of Directors last week that while the ISO’s market performed “competitively” in 2016, there’s still room for improvement.
Delivering an overview of his firm’s recent State of the Market report for the Texas grid operator, Patton said more efficiencies would be gained by improving the market’s price formation and, more important, real-time co-optimization of energy and ancillary services. Potomac Economics, ERCOT’s Independent Market Monitor, filed its most recent market report with the Public Utility Commission of Texas in May. (See “IMM Offers Additional Suggestions to Improve Markets,” ERCOT Briefs.)
“Co-optimization is our highest priority recommendation,” Patton said, noting that he has been making that same recommendation since ERCOT’s nodal market was developed last decade.
“Co-optimizing energy and ancillary services is one thing you can do to lower costs the most, and to ensure efficient pricing in real time,” he continued. “More importantly, co-optimization allows for efficient shortage pricing. With sustained shortages, there’s going to be a lot of revenue generated and lots of costs generated. Having a system where you are confident the use of resources has been maximized and the dispatch has been optimized, the shortages you’re pricing are real shortages, not an artifact of some dysfunction where you can’t get all the ramping capability of all your resources efficiently.”
Patton called real-time co-optimization a “more elegant process” than ERCOT’s current practice of “producing adders to try and mimic what a co-optimized system would do.” He said jointly optimizing the energy and reserve markets would allow shortage pricing under the operating reserve demand curve (ORDC) — which sets real-time energy prices reflecting the expected value of lost load — to be more accurate. The real-time market would determine every five minutes whether a shortage of either energy or reserves exists and set prices accordingly. Currently, capacity providing responsive or regulating reserves are not available to be converted into energy.
“Instead of producing an adder, you are allocating megawatts between products to manage constraints and satisfy load and reserve requirements,” he said. “When the system runs out of resources and can’t manage the reserve requirements, the marginal cost of the last megawatt of reserves you can’t satisfy will set the ancillary service price and be embedded in the energy price. If you’re in a transmission shortage and you’ve ramped what you can ramp, but you can’t get the flow beneath the limit, it will optimally establish congestion prices that reflect that transmission shortage.”
2016 ERCOT State of the Market Report
A co-optimized market would benefit ERCOT’s smaller qualified scheduling entities (QSEs) when they are allocated ancillary services, Patton said. QSEs with large portfolios can move reserves between generating units at lower costs, he noted.
“Co-optimization, with that full information in an optimal fashion throughout all of ERCOT … would allow the ancillary services to be optimized, because shortages of ancillary services set our shortage pricing,” he said. “Having confidence that’s done efficiently is important.”
The PUC has created a project to “assess price-formation rules in ERCOT’s energy-only market” (Docket 47199) and is planning a workshop for further discussion. The ISO is working on a report to be filed with the commission by July 14.
“We will be engaged in that with everyone else,” promised ERCOT CEO Bill Magness.
CAISO is kicking off an initiative that will consolidate proposed changes to the Western Energy Imbalance Market (EIM), including allowing third-party transmission providers to receive congestion revenue when they make capacity available between EIM balancing authority areas.
Stakeholders will discuss the proposals in a call later this month, and the changes will be submitted to the EIM Governing Body in October and the CAISO Board of Governors in November.
“The ISO is committed to providing ample opportunity for stakeholder input into our market design, policy development and implementation activities,” CAISO said in a June 13 issue paper that outlines the new proposals.
The initiative contains two other proposals in addition to the third-party transmission measure, including one that addresses monetary charges related to bilateral market schedule changes and another that provides for more equitable sharing of benefits when an EIM transfer wheels through an EIM balancing authority area.
CAISO said the proposal to allow third-party transmission owners to make available unused capacity for use in the imbalance markets would benefit market participants by increasing transfer capacity, while the transmission provider would receive congestion revenue. EIM entities can currently collect congestion revenue through an offset, but that functionality is not extended to third parties.
The ISO is also investigating whether it can use its current wheeling function to manage bilateral schedule changes originating within or moving across the EIM footprint. Under current practice, schedule changes made after hourly base schedules are submitted are exposed to real-time imbalance settlement payments that are not known ahead of time.
“This will allow market participants with potential bilateral transactions to express a bid price at which the balanced source/sink pair would result in a schedule change,” CAISO said.
Additionally, CAISO said it wants to explore whether balancing authority areas through which power is wheeled should share in benefits when energy transfers occur. EIM energy transfers through balancing areas are exempt from wheeling charges, and the market rule changes would allow the source, wheel-through and sink balancing areas to share in revenue recovery.
“In this case, analysis would need to be completed to determine the magnitude of net wheeling across the [balancing authority] and the cost associated with the wheeling that is not covered by the existing congestion rent settlement,” CAISO said. “This will likely vary per each EIM entity.”
Stakeholders will discuss the proposals in a June 20 call, with comments due on June 30 and a straw proposal to be posted July 27. More meetings are scheduled for August and September, with the board due to review a proposal in early November.
| CAISO
The CAISO-run EIM is designed to better balance supply and demand across the West by making more electricity resources available in real time. It began operating in November 2014 and now includes participants in Arizona, California, Idaho, Nevada, Oregon, Utah, Washington and Wyoming.
Planning reserve margins across most of the U.S. are expected to be adequate for a hotter-than-normal summer, with only ISO-NE barely missing its NERC target, FERC said in its annual summer reliability report released Thursday.
The report analyzed reference levels and margins for all U.S. RTOs and ISOs, as well as NERC’s SERC Reliability, Florida Reliability Coordinating Council and Western Electricity Coordinating Council regions.
ISO-NE is expected to come in just shy of its 15.1% target with a 14.88% reserve margin. FERC staff said tight supply conditions could develop as a result of about 700 MW of new resources not coming online as expected.
“ISO-NE may be required to rely on additional imports from neighboring regions as well as implementing operating procedures to maintain reliability during possible periods of supply deficiencies,” the report said.
While ERCOT’s reserve margin is also tight, the ISO expects to have sufficient capacity to meet peak summer demand, with only a few local areas in southern and western Texas at risk of reliability issues, partially because of strong load growth.
NERC data show total U.S. generating capacity has risen by about 1% since last summer, matching a comparable increase in load. This comes despite the retirement of about 10 GW of combined coal- and natural gas-fired capacity over the last year.
This summer will see an additional 20 GW of new capacity, mostly from wind and solar resources, FERC staff said. NERC anticipates that total wind capacity will be up 8% over last year to 82 GW. The only new nonrenewable resources: 2 GW of gas-fired capacity in the Eastern Interconnection.
“The growing importance of renewable resources has continued in recent years, as both wind and solar capacity continue to expand,” FERC staff said. “Grid operators are pursuing operational solutions to better integrate wind and solar resources as part of their operational and planning activities.”
Staff noted the near record-high levels of snowpack in the West, particularly California, which could boost reliance on hydropower to mitigate any possible natural gas constraints stemming from the restrictions on the Aliso Canyon storage facility.
“While the restrictions on Aliso Canyon did not pose any major issues during the 2016 summer, the limited availability of the Aliso Canyon natural gas storage facility in Southern California may pose a risk to gas and electric reliability this summer if hotter-than-normal weather conditions and unplanned gas pipeline outages materialize,” the report said.
The National Oceanic and Atmospheric Administration is forecasting above-normal summer temperatures for most of the continental U.S., with the entire East Coast most likely to see an increase over the average.
CARMEL, Ind. — MISO will publish a guide describing its cost estimation process for competitive transmission projects by August, according to RTO staff.
“We’re going to really document how we create our cost estimates,” Alex Monn, MISO senior substation design engineer, said during a June 13 Planning Subcommittee meeting.
The RTO has also changed some aspects of its original cost estimation proposal based on stakeholder input.
With the emergence of competition to build transmission under FERC Order 1000, MISO had to begin providing cost estimates for competitive projects in order to protect the confidentiality of developers’ bids. The RTO wants to put a more transparent process in place before the next competitive project is opened to bidding. (See “MISO Seeks to Improve Tx Cost Estimates,” MISO Planning Subcommittee Briefs.)
MISO plans to release both a planning-level cost estimate process and a more final scoping-level one. Stakeholders will review the RTO’s procedures on an annual basis, with the first review scheduled for January 2018.
“We’re going to make this a yearly cycle,” Monn said.
Stakeholders generally agreed on MISO’s new 20% project cost contingency allotment, up from an earlier 15% allowance: “Twenty percent is where everyone landed, so that seems like a good estimate for us,” Monn said.
However, MISO will keep overhead project cost allocation at 10% of the total project cost despite some stakeholder discord.
“In talking to stakeholders, everyone had a different basket of overhead costs,” Monn said. He said MISO staff still believe 10% is the most reasonable figure.
MISO transmission design engineer Devang Joshi said the RTO has increased its planning-level cost estimate for transmission line length to the straight distance between substations plus an additional 30% of the length. Stakeholders asked for more leeway after the RTO originally proposed a straight-line length plus a 20% adder. For scoping-level cost estimates, MISO will create a “reasonable proxy route for the purposes of determining a line length.”
The RTO has also simplified terrain and grading project cost impacts into three categories apiece. Terrain types include flat lands with light vegetation, forested areas and wetlands, with each represented by cost per acre and mile instead of MISO’s originally proposed terrain multiplier. Grading types are identified as “typical” (with the land being less than 30% sloped), “rough” (30 to 50% slopes) or “mountainous” (greater than 50% slopes).
At stakeholder request, the RTO has also added a cost estimate for constructing access roads to substation construction sites, but it reduced transformer cost to a simple unit cost of the transformer instead of a “turnkey” cost that would have provided for other construction materials.
BOLTON LANDING, N.Y. — NYISO said Tuesday that it declared a major emergency on May 21 during the hour beginning 5 p.m. after the loss of 1,000 MW of generation in ISO-NE caused the Central East interface flow to exceed its voltage collapse limit.
It was the second major emergency declaration in a month after one in April, also stemming from interface flow problems. NYISO had last declared a major emergency in July 2016.
Wes Yeomans, NYISO vice president of operations, presented the ISO’s May 2017 operations report during a June 13 Management Committee. The report showed that last month’s peak load of 25,578 MW occurred May 18 and that the month saw more than nine hours of thunderstorm alerts.
The grid operator reported that Lower Hudson Valley installed capacity (ICAP) prices for June fell by 27 cents month over month to $10.01/kW-month, while New York City was down by 33 cents to $10.24. Both declines stemmed from increases in generator unforced capacity available and a decrease in unoffered megawatts. The New York Control Area ICAP price meanwhile increased by $2.17 to $3.89, primarily because of reduced imports and increased exports.
Natural Gas down a Penny from April, up 76% from 2016
In his CEO/COO report to the Management Committee, NYISO COO Rick Gonzales noted that the ISO’s May average year-to-date monthly energy cost of $36.54/MWh represented a 22% increase from May 2016. The average locational-based marginal price for May was $31.74/MWh, compared with $23.31/MWh a year earlier.
| NYISO
May natural gas prices on the Transco Z6 pipeline serving New York City were down a penny from the prior month to $2.80/MMBtu but up 76.5% year over year. The grid operator’s average daily sendout was 383 GWh/day in May, compared with 377 in April and 397 in May 2016.
May distillate prices were down compared to the previous month but up 7.4% year on year. Total uplift costs were higher than in April, while costs per megawatt-hour fell. The local reliability share for uplift was 24 cents/MWh, up from 20 cents/MWh in April, and the statewide share was -13 cents/MWh, down from -8 cents/MWh.
New Testing Requirement for Automatic Swap Dual-Fuel Units
The Management Committee approved revisions to NYISO’s Market Services Tariff as described in the “Zone J Dual Fuel Testing Tariff Revisions” and recommended that the Board of Directors authorize filing the revisions under Section 205 of the Federal Power Act.
The New York State Reliability Council Rule G2 R4 requires combined cycle units in Zone J (New York City) that can automatically swap fuel type to test that capability during each capability period. NYISO is updating its Services Tariff Section 4.1.9 and Ancillary Services Manual Section 8 to comply with the rule.
AUSTIN, Texas — ERCOT’s Board of Directors on Tuesday approved the Far West Texas transmission project, which will result in the construction of two 345-kV lines southwest of Odessa, Texas.
The project would have received unanimous approval but for the abstention of American Electric Power, which will build the project, along with Oncor and Lower Colorado River Authority Transmission. The ISO’s Technical Advisory Committee unanimously approved the project in May. (See “Far West Texas Project Gets TAC’s OK,” ERCOT Technical Advisory Committee Briefs.)
| ERCOT
The $336 million project is designed to address the region’s continued load growth, which has averaged 8% since 2010. Increased oil and natural gas exploration in the Permian Basin and a jump in generation projects — mostly solar — are behind the numbers. ERCOT said peak electricity demand in the area has jumped from 22 MW in 2010 to more than 200 MW in 2016 and is projected to exceed 500 MW by 2021.
“We continue to see a tremendous amount of load growth in West Texas,” said Jeff Billo, ERCOT’s senior manager of transmission planning.
One 85-mile line would run between the Riverton and Moss switching stations, with a second circuit added to the existing 16-mile 345-kV line between Moss and the Odessa line. A second 68-mile 345-kV line will connect the Solstice and Bakersfield substations.
The project is expected to be completed within five years, pending approval from the Public Utility Commission of Texas.
Oncor and AEP initially proposed the project to ERCOT’s Regional Planning Group in April 2016. Staff reviewed 40 different alternatives and lowered the cost to $336 million after settling on the most cost-effective of four options: two separate double-circuit 345-kV lines — each with one circuit in place, substation expansions and other transmission elements. ERCOT concluded the upgrades “meet the reliability criteria in the most cost-effective manner and have multiple expansion paths to accommodate future load growth.”
In a departure from previous years, the 2017 Organization of MISO States-MISO resource adequacy survey suggests the RTO will have sufficient capacity to meet near-term planning requirements.
The annual results show the RTO will have 2.7 to 4.8 GW of excess resources from 2018 to 2022, translating into a 16 to 22% reserve margin — “sufficiently” above the 15.8% planning reserve margin requirement, according to MISO.
“The MISO region will have ample electricity-generating resources to meet expected demand while also maintaining an adequate supply of reserves for the next five years,” the RTO said in a statement. “The results show an improved resource adequacy outlook compared to last year.”
MISO Executive Director of Strategy Shawn McFarlane said this year’s range represents a 2 GW increase over the range predicted by last year’s survey.
“For the first time in the survey, we show adequate capacity resources,” he said during a special June 16 conference call to discuss results.
More than 96% of MISO’s load responded to the survey, according to the RTO. “We’re glad to see another high participation rate,” said OMS president and Indiana Utility Regulatory Commissioner Angela Weber.
The rosier results can be attributed to lower demand forecasts and a lukewarm growth rate of 0.5%, down from 0.8% in 2016, the RTO said. Its forecasted 2018 summer peak of 125.1 GW is down 2.5 GW from predictions made earlier in the year, it said. (See MISO Slims Summer Reserve Prediction.)
Changes to the way the RTO counts megawatts available as capacity might have also boosted the results. Weighted averages in this year’s survey included a 35% share of projects in the definitive planning phase of the interconnection queue, a change made to address stakeholder concerns that the survey was producing overly conservative capacity forecasts. (See OMS-MISO Survey Moves Ahead with New Calculation.)
Weber said the process of the survey and results continue to improve.
“Capturing resource adequacy for a moment in time remains an important tool,” she added.
Last year’s survey forecasted that the RTO would exceed its then-projected 15.2% reserve requirement by 0.9 GW — or 0.7% above the 2017 requirement — and that it could face a capacity shortfall by 2018 under a worst-case scenario. (See OMS-MISO Survey: Generation Shortfall Possible.) The 2015 survey concluded that a shortfall could occur by 2020.
| 2017 OMS MISO Survey Results
This year’s results show that two zones still face capacity shortfalls in 2018, but MISO said that “load-serving entities in these areas should be able to reliably acquire capacity from outside their zones to meet these needs.” Zone 5 in Missouri is expected to have a 0.3-GW shortfall, while Zone 7 in Lower Michigan could come up short by 0.7 to 1 GW. Shortfalls in both areas are predicted to persist into 2022. All other local resource zones are expected to have surpluses ranging anywhere from 0.4 to 1.6 GW in 2018 and 0.2 to 1.5 GW by 2022, except Indiana and Kentucky’s Zone 6, which has the potential for either a 0.7 surplus or a 0.4 shortfall by 2022.
Zone 4 in Southern Illinois showed the greatest improvement: Its 1.6-GW forecasted deficit became a 0.7-GW surplus in this year’s survey after MISO reduced load, added 0.4 GW of new resources and factored in the increased availability of existing resources in the zone.
“Several units at 1.8 GW that were previously expected to retire were determined to serve MISO load at the committed level,” McFarlane said of Zone 4.
Minnesota, Wisconsin and the Dakotas’ Zone 1 was limited to 600 MW in exports in 2018 due to a capacity export limit. Exports from MISO South’s Zones 8, 9 and 10 were limited to 1.2 GW because of the continued MISO South-to-Midwest constraint from the use of SPP’s transmission.
Some stakeholders asked how MISO predicted capacity import and export limits, given that the RTO does not calculate limits more than a year in advance. Laura Rauch, MISO manager of resource adequacy coordination, responded that MISO does estimate out-year import and export limits, but added that export limits only have a “minimal” impact on survey results.
MISO predicts when new transmission will relieve constraints, and the Zone 1 transmission constraint that limits exports to 600 MW is expected to disappear by 2022, Rauch said.
Xcel Energy’s Randy Oye asked MISO to provide more detail about how it determines future export limits and transmission constraints, a subject McFarlane said would be discussed at a July 12 Resource Adequacy Subcommittee meeting addressing the zonal breakdown of survey results.
An unforeseen demand increase could affect survey results “unless balanced by policy or market forces.” He warned that results are “highly sensitive” to the same load forecasts largely responsible for the excesses shown in the survey.
“We appreciate continued collaboration with the Organization of MISO States to provide this outlook on supply and demand in the MISO region,” CEO John Bear said. “This forward-looking view informs and enables collective actions by states and MISO members to ensure continued resource adequacy.”
PJM’s Independent Market Monitor said last week that it has rejected fuel-cost policies for 11% of generating units for the review period ending May 15.
The Monitor said 22 of the 479 power supplier fuel-cost policies it evaluated — less than 5% of the policies, but representing 11% of units — failed to meet its standards for being algorithmic, verifiable and systematic.
Sellers must go through the process again starting June 15, when PJM’s annual review period begins. The annual review runs through Nov. 1.
The policies are important because sellers will be penalized if they choose to offer into PJM’s markets without them.
“Before you put an offer into Market Gateway, you need to have an approved fuel-cost policy,” PJM’s Jeff Schmitt said.
‘Ask Bob’
The initial review was the culmination of a long and often contentious coordination between the RTO and Monitor to get every market seller who must source fuel to submit a policy explaining how it developed the fuel costs included in its cost-based offers. PJM approved all offers submitted.
“We don’t actually agree with PJM that all of the policies that PJM agreed to were consistent with the Tariff,” Bowring said. There were several of the issues that caused his team to fail policies, including submission of unsupported cost adders and reliance on internal estimates.
“That’s what we refer to as ‘Ask Bob.’ So you go down the hall and ask your trader,” Bowring said, noting that the “probably 80%” of gas-fired units that used that method two years ago was “reduced dramatically.”
Some of the explanations shocked stakeholders.
“Someone for real submitted a gas hub that was not in any way, shape or form physically related to the unit that they were submitting it for and didn’t give an explanation as to why?” EnerNOC’s Katie Guerry asked. “You’re saying that someone submitted it without any sort of attempt at explaining it to you, knowing who you are?”
“Precisely,” Bowring responded. “Believe me, we understand all the nuance and subtleties about how it could be.”
The ongoing fuel-cost policy requirements have created fatigue among some stakeholders. During last week’s Market Implementation Committee meeting, Gabel Associates’ Mike Borgatti reconstructed the timeline.
“By May 15, we had to get our fuel-cost policies approved to resubmit them by June 15 to maybe get them approved again by Nov. 1, right?” he asked.
Sellers are required by June 15 to submit updated policies to PJM or confirm that their current policies remain compliant. The Monitor will make its determination on policy reviews by Aug. 1, which is also the deadline for sellers to provide policies and sample emissions, variable operations and maintenance calculations to PJM. The Monitor plans to have a fuel-cost policy template incorporating hourly offers available this week, and PJM expects to have its templates ready June 30.
PJM will make its determination on polices by Nov. 1. Schmitt said that review will capture any changes to ensure the policies allow for intraday offers.
“It’s not that we’re trying to recreate work. We just want to make sure that we’re good to go going forward for the winter,” he explained.
With the implementation of FERC Order 825, sellers will be able to update offers hourly to adjust for changing market and supply conditions.
“We know this process is not easy,” said Joel Romero Luna, who is part of Bowring’s team at Monitoring Analytics. “I’ll be surprised if anyone submits by June 15 a policy that captures hourly offers, so it’s my expectation that we’ll work through it, and hopefully we’ll get something acceptable by Nov. 1.”
Online Systems
Going forward, PJM and the Monitor will be using online systems for the process. The Monitor will require all market participants to use a new section on its Member Information Reporting Application (MIRA) for reporting cost-based offer data as of June 30.
The new “Cost Offer Assumptions” module was brought online June 12 with the expectation of having all market sellers transitioned by the end of June. The Monitor uses the inputs to verify sellers’ cost-based offers. Participants will need to verify that the data is correct because “incorrect or incomplete data in MIRA may trigger an evaluation of cost-based offers for potential penalties under Schedule 2 of the Operating Agreement,” the Monitor said.
PJM will also be using “a tool” to track policies, which Schmitt said could be MIRA — although that isn’t assured.
Bowring said one of his frustrations is securing PJM’s commitment on the topic.
“My read of what PJM has been telling us is that they don’t intend to rely on MIRA, but I’m not quite sure why. It’s going to cost them at least millions of dollars in order to replace it on their side,” he said. “Until PJM tells us they’re going to rely on it, we’re not making changes to make it work more smoothly for PJM.”
CAISO finalized a set of updates to its proposed policies on demand response and distributed generation, saying there is strong stakeholder support for the new rules to be presented to the Board of Governors in July.
An incremental approach would be best as CAISO learns from the changes stemming from the policies and their influence on generation resources and grid operations, the ISO said in a draft final proposal on “Energy Storage and Distributed Energy Resources (ESDER) Phase 2.”
“The ISO will continue collaborating with stakeholders on the remaining ESDER 2 topics in a phased policy approach that is appropriate in a rapidly evolving market environment that currently does not have a clear end state,” CAISO said.
The board next month will review finalized proposals for alternative baselines, distinguishing between charging power and station power for energy storage resources, and changes to the threshold price for DR, among others.
For DR, a baseline analysis working group developed enhancements to the method whereby proxy DR resources are evaluated. The ISO has finalized the alternative baselines, which are designed to improve the accuracy of DR performance calculations. CAISO said there has been “overwhelming” support for the alternative baseline proposal.
| CAISO
The ISO currently relies on a “10-in-10” baseline methodology that works well for many large commercial and industrial customers but not for all customer types, leading to the development of a new approach.
Using the 10-in-10 methodology, the ISO calculates a baseline by examining the 45 days prior to a trade date and finding 10 “like” days in which no DR was required. It then uses hourly average meter data to create a baseline representing a typical load profile, and the resource is paid for reducing usage below the baseline.
Under the new proposal, baselines for residential resources would be based on a four-day weather match that estimates what electricity use would have been in the absence of DR dispatch under similar weather and on similar days, using a control group of similar users.
Commercial baselines would be based on the 10-in-10 method with a 20% adjustment cap, an average of the previous five days and a control group. Baselines are adjusted using actual load data in the hours preceding a DR event to better reflect variables that might not appear in the historical data.
The stakeholder process showed that station power is a retail issue, CAISO said, and listing specific functions for wholesale and retail functions is not the best approach.
“The CAISO believes that it is prudent to simplify the definition of station power to energy for operating the electrical equipment of an energy resource subject to a retail tariff, as defined by the local regulatory authority,” CAISO said. This definition would be consistent across regulatory authorities and avoid conflicts if the California Public Utilities Commission changed its definition of station power.
The ISO is also proposing to expand the list of gas price indices available for use in the calculation of DR benefits. This allows the DR “net benefits test” to recognize Energy Imbalance Market (EIM) entities outside of the state that want to participate as DR in the CAISO market.
The policy issues discovered in the process will affect the EIM if DR or distributed energy resources are used. The EIM Governing Body will review the proposal on July 13 in its advisory role.
CARROLL, N.H. — New England regulators and market participants expressed optimism last week that they will find a way for wholesale markets to coexist with state energy policies, warning of dire consequences if they fail.
In a discussion Monday at the 70th Annual Symposium of the New England Conference of Public Utilities Commissioners (NECPUC), panelists discussed the proposals that have arisen from the New England Power Pool’s Integrating Markets and Public Policy Process (IMAPP).
Angela O’Connor, chair of the Massachusetts Department of Public Utilities, said IMAPP has been successful, although it has not yet resulted in a solution. At the FERC technical conference in May, she said, “New England appeared well ahead of other parts of the country in looking at solutions and trying to understand each other’s priorities.”
New England states are set to procure more than 3,600 MW of nameplate renewable generation, including Massachusetts’ requirement that its electric distribution companies solicit long-term contracts for approximately 1,200 MW of clean energy generation and 1,600 MW of offshore wind.
“The bottom line is, if New England does not find a way to harmonize markets and the requirements of state laws, it creates the risk that consumers will have to pay twice for resources — once through the regional markets, and again as the result of the requirements of the state laws,” O’Connor said. “For those who go to work every day thinking about consumers, that outcome is absolutely unacceptable and would most likely lead to the end of the competitive markets as we know them today.”
Tom Kaslow, chair of NEPOOL’s Participants Committee, said “collaboration is the cornerstone” of the power pool, adding that he hoped New England would develop a solution rather than leaving it “to be solved by the courts.”
“We are all in this together,” he said during lunch remarks Tuesday. “We either make this market work together or we don’t succeed.”
Although it is the Participants Committee that will ultimately determine whether to support proposals brought before it, Kaslow stressed his personal commitment to the regional efforts. “I will not accept failure, at least during my tenure as chair.”
ISO-NE CEO Gordon van Welie said the RTO is working overtime on the issue in order to reach agreement on a proposal that could be submitted to FERC in time for the February 2019 capacity auction.
“We definitely put ourselves in the ‘urgent’ camp,” he said. “These contracts that the states are intending to sign are probably going to happen during the next 12 months or so. In 2018, we expect resources that are winning these [requests for proposals] are going to want to enter the capacity market in the following cycle. And the qualification process for that 2019 auction will commence in 2018. And so we ideally would like to have a rule set that can deal with that prior to the start of qualification in 2018.”
Because of the RTO’s minimum offer price rule (MOPR), resources receiving a power purchase agreement may have their prices reset to a higher level in the capacity auction, with the result that they likely would not clear. “And so that has an unfortunate consequence if the states are going to go ahead and contract for these resources anyway, which is you ultimately end up overbuilding the system,” van Welie said.
But allowing subsidized resources to participate in the auction without mitigation would drive capacity prices down, he said.
“I often get a lot of eye-rolling back at the ISO when I go back to the market design people and say we need a design that will make six states happy [along with] 460 market participants and it needs to be approved by the FERC,” van Welie said. “If we did nothing and we just rely on the status quo to exist, I think we’d end up creating investor uncertainty in the market because of the litigation that will result,” he continued. “It’s a very fragile premise, an investment incentive, and it can unwind extremely quickly. So we believe it is important for us to have a solution in place that will give the marketplace confidence that we can deal with this.”
The Competitive Auctions with Subsidized Policy Resources (CASPR) proposal, developed by the RTO and Market Monitor David Patton, would provide financial incentives for existing, high-cost capacity resources to transfer their capacity obligations to subsidized new resources and permanently exit the capacity market. It would involve a two-stage, two-settlement process with a substitution auction occurring immediately after the primary auction.
The plan would “accommodate the subsidized resources into the capacity market over time and also preserve competitive capacity pricing for unsubsidized resources,” van Welie said. “The key idea here is to coordinate the entry of subsidized capacity resources with the exit of unsubsidized resources … over time.”
A second proposal, a “Dynamic Clean Energy Market” backed by the Conservation Law Foundation, NextEra Energy Resources and Brookfield Renewable, would use forward capacity auctions to procure clean energy attributes unbundled from energy. Charles River Associates consultant Robert Stoddard briefed NECPUC on the proposal, which he helped design.
ISO-NE says CASPR falls into the “accommodation” category as a project that can be implemented relatively quickly. The Clean Energy Market is an “achieve” proposal that attempts to incorporate state policy into wholesale markets; it will take more time to evaluate to determine how it would work with the Forward Capacity Market and the MOPR, the RTO says.
‘Intriguing’ Proposals
“Both proposals are intriguing,” O’Connor said. “You’ll not be surprised that I have more questions than answers at this point.”
O’Connor said she was concerned that the RTO’s proposal would eliminate the annual 200-MW MOPR exemption for renewable resources. She noted the exemption has been supported by the six New England states and the RTO and approved by FERC despite opposition by some conventional generators. “I do question the notion of eliminating the one mechanism that gives me the certainty I need,” she said. “That said … CASPR has some tremendous advantages. We all know there are tradeoffs in these sorts of discussions.”
She suggested combining CASPR and the exemption might “increase the likelihood that CASPR will actually meet its objectives and really give the states the certainty … that we’re going to need.”
O’Connor also said she liked that the Clean Energy Market proposal “seeks to be mindful of the fact that states are responsible for executing their state laws.”
“The CLF, NextEra and Brookfield proposal, like many of the longer-term ‘achieve-style’ proposals are complex and raise questions for states about authority and other matters. They also require a significant investment of time and money to develop and implement.”
She said the New England States Committee on Electricity (NESCOE) is conducting analyses of the proposals, which will be released this fall.
IMAPP Chair William Fowler, president of Sigma Consultants, told NECPUC that 100 to 150 people attended each of the nine IMAPP meetings thus far. He said the next meeting of the group will be in September.
Stoddard and Mark Vannoy, chair of the Maine Public Utilities Commission, said integrated resource planning has moved from public utility commissions to legislatures.
“When legislators say now we want some biomass, or now we want some Massachusetts solar, they’re really getting back into integrated resource planning, so there’s tension about economic efficiency and other priorities,” Stoddard said.
Maine’s Concerns
“That’s the reality of the political economy in which we live,” agreed Vannoy. “There’s this insatiable appetite and I don’t expect that to change at the legislatures. The technology will change, but the desire to direct outcomes is not going to change. When we come to a multistate RTO, that’s where it becomes difficult because we have multiple states looking at a whole new set of complexities.”
The use of tailored mitigation strategies has been only partially successful in preventing the socialization of other states’ public policy decisions, Vannoy said. “It’s not an effective long-term approach … because it doesn’t provide regulatory certainty for market participants.”
Vannoy also expressed concern about the CLF proposal, saying incorporating incentives for clean energy into the RTO Tariff “might be a jurisdictional bridge too far.”
Environmental legislation in New England is often the result of compromises between policy goals of reducing greenhouse gasses and economic goals of creating and retaining jobs, he noted.
For example, Maine legislators last year approved spending $13.4 million in taxpayer funds to supplement the price that in-state biomass generators get from selling their power in the wholesale market, a subsidy projected to save almost 300 jobs. The legislation was coupled with the idea of “keeping people cutting wood, and is being judged on the basis of an economic result, while Vermont Tier II [distributed renewable generation] talks about connecting generation facilities of 5 MW or less to sub-transmission or distribution systems.”
Noting that Maine is the only New England state whose manufacturing load is greater than its residential demand, Vannoy said a carbon adder would make the state less competitive than other regions. Owners of large manufacturing operations such as Bath Iron Works and Texas Instruments have complained about the state’s high rates. Any rate increase would raise the risk of manufacturers of moving their operations to a Southern or Western state with cheaper power and higher carbon intensity, he said. “You’re not going to solve the carbon issue by shifting [manufacturing] to other parts of the country.”
Fuel Security
Van Welie also addressed concerns over fuel security, acknowledging that the CASPR proposal could accelerate the retirement of 6,000 MW of older, at-risk steam generators. The RTO needs about 22,000 MW to meet its winter peak, but its dependence on gas-fired generation is limited by pipeline constraints.
“When you look at what’s actually running those winter days, it’s a lot of oil, and historically we’ve had a lot of coal we used to use for winter reliability,” he said. “And so that begs the question: Where’s the energy going to come from in the future to maintain reliability in the winter?”
Van Welie said the RTO is seeking to quantify the risk through analyses that model what the system will look like in 2025 under sensitivities that consider higher and lower levels of retirements, LNG imports and renewables. (See Study: New Resources Could ‘Crowd Out’ Old in ISO-NE.)
Van Welie noted that the RTO’s out-of-market winter reliability program will end in winter 2017/18, with the region relying on its Pay-for-Performance initiative in the future.
“The question is, will the Pay-for-Performance mechanism, together with the stop-loss provisions inherent in that mechanism, be sufficient to drive the level of forward fuel arrangements that we require to get through winter with the pipeline constraints?”
