Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider. The Members Committee does not meet in August.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
PJM Manuals (9:10-9:40)
Members will be asked to endorse the following manual changes:
Manual 12: Balancing Operations. Administrative and conforming updates align with NERC reliability standard BAL-001-02, which went into effect July 1, and with the frequency bias calculation in BAL-003-1.
Manual 14D: Generator Operational Requirements. Changes include updates to the cold weather generation resource preparation section. Amends cold weather testing process effective with winter 2016/17. Generators that cleared as Capacity Performance in the current delivery year will no longer be eligible for compensation for conducting the exercise but may test and receive compensation as a self-scheduled resource. (See “PJM Plans to End Compensation for CP Units Participating in Winter Testing,” PJM Operating Committee Briefs.)
MISO is working to coordinate its generator retirement studies with PJM without changing the RTOs’ Tariffs.
“We’re not going to overhaul the individual Tariffs,” Neil Shah, MISO advisor of seams administration, said during an Aug. 16 meeting of the Planning Subcommittee. “The coordination will align to the extent possible with the Tariffs. We don’t see the need to change anything in the Tariff requirements just yet.”
FERC ordered that MISO coordinate its generator retirement studies with PJM in response to a complaint by Northern Indiana Public Service Co. (EL13-88). (See “MISO Outlines Work Plan for PJM Retirement Coordination,” MISO Planning Subcommittee Briefs.)
Shah said MISO will continue to exchange retirement notification and study information with PJM. “We’ve been doing that before the FERC order came out, so there’s nothing new there,” he said.
MISO is proposing to consult with PJM on how it uses its 30-day window to study generators seeking deactivation for adverse reliability impacts so MISO can consider incorporating those methods in its own reliability impact studies. MISO also wants to exchange study models with PJM as they are updated.
Shah also said MISO plans to use the Interregional Planning Stakeholder Advisory Committee to discuss impacts to the RTOs and analyze upgrades proposed in place of the retiring generator.
Shah said MISO’s suggested approach allows for RTOs to conduct their own studies “with inputs and common assumptions of adjacent system conditions.”
He said MISO will comb through the RTOs’ joint operating agreement to see if any language needs to be revised to include the proposed coordination. MISO is asking for stakeholder feedback on its proposal by Sept. 7 to shape the draft JOA language. Before then, stakeholders will offer opinions on the JOA language at a Nov. 15 Joint Common Meeting. A final filing in the NIPSCO order is due Dec. 15.
Shah said a key difference between the RTOs’ retirement obligations is that PJM cannot force a resource owner to stay online, while MISO can order system support resource agreements.
The RTOs’ retirement timelines are also mismatched. PJM requires 90 days’ notice before retirement while MISO requires twice as long.
Shah also noted that MISO keeps retirement information confidential unless there’s a need for SSR designation while PJM announces retirement notifications.
“That’s not as much of a concern,” Shah said of addressing the confidentiality issue.
Possible MISO-PJM Joint Model in Works
In the NIPSCO ruling, FERC also ordered MISO to explore the potential for a joint regional model with PJM with the same assumptions and criteria to coordinate the two regional transmission planning processes.
MISO started the process at last week’s subcommittee meeting by asking stakeholders to envision what a MISO-PJM joint model would look like.
MISO engineer Adam Solomon said it is possible to model power flow and economic models that contain both MISO and PJM assumptions. However, Solomon said MISO is opposed to creating common assumptions such as production cost models.
“Our approaches are so different that it doesn’t make sense,” he said.
An informational filing on a possible joint model is due Oct. 18. Solomon said MISO isn’t certain of the action it would have to take after that.
“If [FERC] likes our answer, they might require us to incorporate some of the things into our joint operating agreement, but for now, it’s just informational,” he said.
MISO Releases Minimum Requirements for Competitive Tx Projects
MISO released the first revision of Business Practices Manual 029, which governs requirements for competitive transmission projects.
MISO principal adviser Matt Tackett said the Minimum Design Requirements Task Team added minimum normal rating requirements that borrow from current minimum emergency ratings. Tackett also said the manual includes a default table for minimum transmission circuit ampere ratings.
“The biggest trick was coming up with a default table based on typical percentages,” Tackett said.
MISO has also developed what it calls adequacy validation ratings to verify that the circuit conductors specified by developers provide adequate load capacity.
The ratings factor in wind speeds along with ambient temperatures. MISO North assumes an ambient temperature of 35 degrees Celsius in the summer and 0 degrees in the winter; all other MISO regions will use 40 degrees Celsius in the summer and 10 degrees in the winter.
Tackett said BPM 029 will undergo more refinements based on stakeholder feedback before another presentation at the October PSC. It is set to become effective in January.
Meanwhile, Tackett said BPM 020, which guides use of non-transmission alternatives and describes how storage can qualify for interconnection, needs another monthlong round of vetting in the subcommittee before final language is reviewed before the Planning Advisory Committee.
Transfer Limits Range from 1,400 to 4,500 MW in MTEP16 Analysis
MISO senior engineer Scott Goodwin announced preliminary linear thermal limits for MISO’s 2016 Transmission Expansion Plan transfer analysis:
MISO North to SPP has a transfer limit of 3,600 MW;
Two paths from Manitoba Hydro to MISO North have limits of 1,400 MW or greater;
MISO North to PJM Ohio has a limit of 4,000 MW;
Limits from Missouri and Illinois to PJM Ohio range from 2,800 to 3,600 MW depending on different contingencies;
SPP to Southern Co.’s territory has a limit of 4,100 to 4,500 MW depending on different contingencies; and
Michigan is asking for another assessment from MISO, this time to study grid improvements across the state’s peninsulas and Canada.
The latest request, signed by Gov. Rick Snyder, asks MISO to study the reliability and affordability benefits of transmission and generator expansion in the northern part of the RTO’s footprint.
“Since Michigan has some of the highest prices for transmission in the MISO footprint, it makes sense to ask whether, in the long term, we can all spend less while increasing reliability by strengthening our ties to each other and our neighbors,” Snyder said.
The Michigan Agency for Energy (MAE) also joined in on the request.
“Michigan is in the middle of a transformation of our energy infrastructure in both peninsulas, and Ontario’s generation has changed a great deal, including the area just across the Soo,” said Valerie Brader, executive director of the agency, referring to the region encompassing the twin Sault Ste. Marie cities in Michigan and Ontario. “This study will help us identify whether, due to all these changes, there are new opportunities for infrastructure that will make Michigan more adaptable.”
MISO spokesman Jay Hermacinski said the RTO has contacted Michigan officials to discuss the governor’s request and the state’s Aug. 9 call for a reliability analysis that assumes simultaneous outages at the Palisades and Fermi 2 nuclear plants. (See Michigan Asks: Will the Lights Stay on If Nukes Go Dark?)
“At this early stage in the process, it is too soon to comment on the substance of requests or to establish a definitive timeline,” Hermacinski said.
The new request asks the RTO to study:
Connecting Sault Ste. Marie, Ontario, to Michigan’s eastern Upper Peninsula in Zone 2;
Strengthening the connection between the Upper Peninsula and the northern Lower Peninsula in Zone 7 at the Straits of Mackinac down to “the northernmost part of the existing 345-kV transmission line near Gaylord, Mich.”;
Production cost savings, reliability, resource adequacy and power flows assuming a large natural gas plant is built in Otsego or Kalkaska County in the northern Lower Peninsula. Michigan officials say that the area is ripe for a natural gas plant, as pipelines and storage in the area have available capacity, and an adequate transmission network exists.
MISO last completed a study of its northern footprint in 2012, but the connections to Canada were not analyzed, MAE said.
This time, Michigan is asking MISO to work with Ontario’s Independent Electricity System Operator and pointed out that the province’s next Long-Term Energy Plan process begins this summer. Since the 2012 study, the agency said, the area has experienced “significant infrastructure changes” with more to come. The letter points out that “many fundamental characteristics of the Bulk Electric System have evolved over the last five years on both sides of the international border, and change to the system is expected to accelerate within Michigan.”
Ontario ended coal-fired generation in 2014. Nuclear power, now 60% of the province’s generation output, is expected to drop to 40% by 2025. The province expects to add as much as 3,000 MW of capacity between 2021 and 2032. (See Ontario: Clean — and Expensive.)
NV Energy and PacifiCorp returned nearly $95,000 to generation customers after FERC revoked market-based rate authority for Berkshire Hathaway Energy affiliates in four neighboring Western balancing authority areas and imposed cost-based rates.
NV Energy and PacifiCorp refunded $95,000 to generation customers in the PACE, PACW, IPCO, and NWMT areas represented on the map.
The refunds were disclosed in confidential documents released under a Freedom of Information Act request by Clearing Up, an energy newsletter covering the Pacific Northwest.
The documents show that NV Energy refunded $77,073 — with interest — to its customers, which included about $50,000 to Idaho Power, $20,000 to TransAlta Energy Marketing and $5,000 to Shell Energy. PacifiCorp refunded a total of $17,646.10, including nearly $6,900 to Morgan Stanley Capital, $6,100 to Tucson Electric Power and $3,900 to NorthWestern Energy.
The commission restricted Berkshire’s market-based rate authority in June after ruling that the company’s affiliates failed to disprove that they collectively exercise horizontal market power in the PacifiCorp East, PacifiCorp West, Idaho Power and NorthWestern balancing areas (ER10-2475, et al.).
The affiliates failed the indicative “pivotal supplier” and “wholesale market power” screens for initially assessing horizontal market power in the four regions, as well as a more thorough “delivered price test” analysis designed to enable companies to rebut a presumption of market power. (See Berkshire Market-Based Sales Restricted in 4 Western BAAs.)
FERC ordered the Berkshire companies to revise their tariffs for the the four areas and issue refunds for the period between Jan. 9, 2015, and April 9, 2016.
The modest sums involved reflect persistent weakness in regional wholesale electricity prices. A source close to the matter told RTO Insider that many of the sales during the period were transacted below Schedule Q — or cost-based — rates because of market conditions.
The expected future impact of FERC’s ruling got only brief mention in Berkshire’s second-quarter filing with the Securities and Exchange Commission. “The specified [Berkshire] subsidiaries affected in the order do not believe the order will have a material impact on their respective consolidated financial statements,” the company wrote.
Nevertheless, Berkshire last month requested a rehearing on the decision, contending that the commission “did not provide sound reasoning, nor did it show a path to how it arrived at its decision.” (See Berkshire Contests Market-Based Sales Restriction in the West.)
LITTLE ROCK, Ark. — SPP’s engineering staff updated members on the RTO’s current regional and interregional transmission planning studies during an engineering summit last week.
In return, the engineers asked for stakeholders’ input.
“It was very important that we are able to get in the feedback at the front end of the process,” SPP Director of Transmission Planning Antoine Lucas told members, who spent much of the day delving deep into the 2017 Integrated Transmission Planning’s 10-Year Assessment (ITP10). “Most of you will be pleased with” the process.
“As soon as you guys can provide feedback, please do it,” requested SPP’s Juliano Freitas, manager of economic planning.
ITP10
SPP plans to present its final 2017 ITP10 to the Markets and Operations Policy Committee in December.
Staff is using three futures for the study: regional compliance with EPA’s Clean Power Plan; state-level CPP compliance; and a reference case that assumes the CPP will not be implemented.
The two CPP studies will eventually be combined into a single portfolio, with the reference case also moving forward for additional benefit calculations, using multiple model years and costs derived from the RTO’s annual transmission revenue requirement formulas.
Transmission projects would be deemed to satisfy economic needs by meeting up to 25 constraints with greater than $50,000 in annual congestion costs.
SPP will also produce a near-term reliability assessment early next year. Staff is currently working on a needs assessment but doesn’t expect to produce a final portfolio recommendation and report until March.
Adam Bell, SPP’s interregional coordinator, updated members on the status of SPP’s work with three of its interregional partners: MISO, Associated Electric Cooperatives Inc. (AECI) and Southeastern Regional Transmission Planning (SERTP).
SPP and MISO have both voted to pursue a joint study this year, using their regional planning as a starting point. Bell told members they would be able to propose solutions for the final set of needs, currently being developed.
The RTOs are scheduled to meet again Sept. 7. “We want to get this scope approved so we can get this study done,” Bell said.
SPP and AECI are determining the scope of a study of five target areas: potential overloads and voltage issues in northeast Oklahoma and Brookline, Kan.; potential low voltage issues in mid-Missouri and east of Kansas City; and potential upgrades in Wheaton, Kan. They expect to produce a final report and recommendations in January.
Bell said SPP had its annual meeting with SERTP representatives in June. The staffs reviewed their regional plans to “see if anything made sense,” Bell said, adding later, “it’s more coordination than joint planning or joint study.”
“There could be potential here as we move forward,” he said.
A group of Upper Peninsula electric users plans to ask FERC to investigate Wisconsin Electric Power Co. for allegedly falsifying records to increase its revenues under the Presque Isle power plant system support resource agreement.
“The numbers presented by MISO and WEPCo going back to 2014 were inflated, and part of that was falsifying documents,” Todd Chapman, spokesman for Cloverland Electric Cooperative, said Monday.
Chapman said that the organization expects to file a brief later this week or next week detailing the allegations, which were included in Administrative Law Judge Michael Haubner’s initial decision last month saying WEPCo had overcharged ratepayers by $17 million over the SSR (ER14-1242-006, et al.).
Last week, meanwhile, FERC approved nine out of ten SSR process revisions proposed by MISO.
“Evidence shows that the invoice for services was originally executed and sent to WEPCo on Oct. 9, 2014. Then, a WEPCo employee requested the consultant resubmit the invoice with a later date, Oct. 16, 2014,” Haubner said.
Presque Isle Power Plant Source: WEPCo
According to Haubner, the invoice dates were changed after WEPCo learned that a new version of its SSR agreement with MISO would cover costs incurred from MATS upgrades under a revised fixed-cost component. MATS upgrades were ineligible for recovery under the previous SSR agreement.
“This evidence demonstrates that WEPCo changed the date on the consulting services invoice to one day after the replacement SSR agreement became effective. It appears this manipulation was done by WEPCo to include these costs under the later agreement,” Haubner concluded.
WEPCo issued a statement insisting the company was not seeking to recover MATS compliance costs through the SSR payments. “Beyond that, the company will not comment on cases currently being litigated. The issues that are in contention in the initial ALJ decision, including this issue, will be addressed by our future filings in this case,” it said.
Chapman said the $1.4 million worth of back-dated invoices was “carved out” in the judge’s estimated refunds and contributed to Cloverland lowering its expected amount owed to MISO for the Presque Isle SSR to “the neighborhood of $9.8 million,” instead of the original $11.7 million, for 2014.
Chapman said Cloverland is waiting on a larger decision from FERC in order to verify the $9.8 million figure.
Cloverland will be joined in its request for an investigation by mining company Cliffs Natural Resources, Upper Peninsula Power Co., paper producer Verso Corp., the City of Mackinac Island and the Sault Ste. Marie Tribe of Chippewa Indians, Chapman said.
If FERC decides to investigate, a probe from its Office of Enforcement could take years, Chapman said.
“None of that is going to wipe it all out and completely dismiss the amount we owe,” Chapman said, adding that the outcome of a possible investigation “probably” wouldn’t further reduce the amount owed. “If FERC agrees that it was fraudulent, then we’re back to the same lower number,” he said.
MISO Confused by Refund
Meanwhile, MISO complained in an Aug. 16 brief that Haubner’s ruling was inconsistent and confusing.
MISO said Haubner used two “inconsistent” methods to determine variable compensation under the two separate Presque Isle SSR agreements. The RTO also said the judge at times mixed up fixed compensation and clawback values. Finally, MISO said Haubner did not outline a procedure for calculating the total amount owed to ratepayers.
“MISO is unable to determine the amount of refund that should be made by the Wisconsin Electric Power Co.,” the RTO wrote to FERC. It also said it “hoped for an initial decision that would contain internally consistent findings that MISO could implement in its role as Tariff administrator.”
FERC Accepts Changes to MISO SSR Process
In a related order on Aug. 19 (ER16-1758), FERC accepted nine out of ten SSR process revisions proposed by MISO, which affect the execution, filing and compensation of SSR units.
MISO proposed that while it would still file SSR agreement terms and conditions, SSR owners in “all cases” would make separate filings for compensation. MISO previously only had SSR members resort to a FERC filing when it couldn’t agree on compensation.
FERC agreed. “Given that many recent SSR filings have set compensation issues for settlement and hearing procedures, the advantage of requiring that MISO and the market participant undergo preliminary compensation negotiations prior to executing an SSR agreement is limited and outweighed by the administrative burden of conducting such negotiations,” the commission said.
The Michigan Public Service Commission supported MISO’s proposal, saying it would allow customers and regulators to offer input before MISO and SSR owners reach an agreement.
Chapman said it was better that MISO not take generators’ cost numbers at face value. “I think MISO will learn their lesson, but not before this happens again,” he said, referring to future coal plant retirements.
Inappropriate Limit
The order also allows MISO to enforce a 30-day notice period before retirement on forced outage units and units that are pseudo-tied out of the RTO. Pseudo-tied units now also have a 36-month maximum suspension period in a five-year time frame before their interconnection service is pulled. Black start-designated units must now fill out an Attachment Y notice, which triggers a reliability study, before retiring. Finally, all retirements can be made public by MISO once their retirement date passes.
However, FERC rejected MISO’s proposal that a return to service on a retired former SSR would be defined at the point that the unit re-enters the interconnection queue, saying it would “inappropriately limit” situations where a generator would have to refund certain costs. FERC called MISO’s existing Tariff language on refunds “appropriately broad.”
Cliffs-WEC Deal
Chapman blames a Michigan exemption that allows mining companies to choose electricity suppliers for the creation of the disputed SSR. Mining company Cliffs Natural Resources took advantage of the exemption, leaving Presque Isle for an estimated $20 million to $30 million annual savings.
“Nobody thought anything of the exemption at first. At the time, it protected the mines, and Cliffs is the largest employer in Marquette,” he said.
Cloverland now has a new concern, spawned by Cliffs’ announcement last week that it has entered a 20-year power purchase agreement with WEC Energy Group to power its Tilden mine. The contract would result in the construction of two natural gas-fired plants on the Upper Peninsula totaling 170 MW.
He said Upper Peninsula ratepayers would be on the hook if Cliffs should go out of business, as the Upper Peninsula’s transmission network isn’t able to reliably export power to Wisconsin and the Lower Peninsula.
Cliffs CEO Lourenco Goncalves said the new generators are a “strategic energy solution for the Upper Peninsula [that] optimizes affordability and improves reliability for all ratepayers for decades to come.”
The $255 million plan will need to be approved by the Michigan PSC.
The National Energy Marketers Association has asked for a rehearing of New York regulators’ moratorium on the enrollment of low-income customers by energy service companies (98-M-0667).
The New York Public Service Commission last month imposed the moratorium because stakeholders were unable to reach a consensus on reforms. (See NYPSC Declares Moratorium on Low-Income Sign-ups.)
In a petition filed Aug. 15, NEM said regulators violated stakeholders’ due process rights by adopting the moratorium without notice, violated state law and made other procedural errors.
State law “does not grant the commission authority to institute a moratorium on ESCO service to low-income customers,” the petition states.
NEM cites the same procedural mistakes the commission made in its February order attempting to revamp ESCO practices for customers not receiving public assistance. A state Supreme Court justice ruled that the PSC failed to give adequate notice. (See New York ESCO Order Vacated by Court.)
“The July order erroneously concludes that low-income consumers should not be permitted to make their own energy purchasing decisions,” the petition says, calling the PSC’s action “unfounded and [a] paternalistic view of low-income consumers’” shopping decisions.
The petition also asks for a clarification of the order, saying it fails to address how and under what circumstances the moratorium would be lifted.
“Despite the intention expressed that the moratorium be temporary in nature, the order itself provides no detail of the circumstances or timeline under which it will be lifted. NEM recognizes that the resolution of other related proceedings potentially impacts the duration of any moratorium,” NEM wrote. “However, ESCOs should be provided with some guidance and regulatory certainty about the potential duration of the moratorium in order to properly inform their decisions about serving New York state customers.”
INDIANAPOLIS — MISO used its first-ever Market Symposium last week to ask industry leaders how a low-carbon environment will influence the electricity market.
Although the discussions produced few specific suggestions on what new rules should be proposed, there was wide agreement that the markets need to become more flexible to accommodate the increase in renewables and distributed resources. The Department of Energy’s Advanced Research Projects Agency-Energy (ARPA-E) partnered with the RTO in the sold-out event Aug. 18-19.
“We’re basically heading off to a situation where there’s no trail, and we’re going to have to cut through the wilderness for a while,” said Michael J. Curran, chairman of the Markets Committee of the Board of Directors. “This [symposium] is a coming together of the community where we’re going to have to share ideas. … I look forward to cutting the trail together.”
“We have people saying the system cannot do this; the system was not designed for this,” said CEO John Bear, commenting on incorporating distributed resources. “That reminds me of what people used to say about wind. … We can solve these problems. We can look at what we’re doing in the control room.”
MISO’s wind generation has grown exponentially since 2005, when it totaled only 500 MW. A decade-plus later, the RTO has 15 GW of wind.
Gas the ‘New Coal’
Tom Doughty, vice president of customer and state affairs at CAISO, spoke about the challenge of meeting California’s mandate of 50% renewables by 2030.
Doughty said wind and solar will be a “massive element” by then. He also said natural gas has become the “new coal” in California.
“We’re in a race now to meet the mandates and accomplish our state’s objectives,” he said. “But that race must be run carefully to avoid placing additional costs on consumers.”
Eric Schubert, regulatory affairs advisor at BP Energy, said the growing role of natural gas will require investments in firm transport, storage and long-term contracts.
With gas-fired generation having to manage peak loads in the morning before the sun rises high and in the evening before the wind picks up, measures are needed to optimize the use of intermittent resources throughout the day, said Scott Harvey of FTI Consulting.
But time-of-use pricing is not the answer, said Cathy Woollums, senior vice president and chief environmental counsel at Berkshire Hathaway Energy. “How are you going to tell someone not to do their laundry at 10 in the morning or they’re going to pay more?” she said. “We can’t switch overnight to looking at something brand new.”
Paul Mitchell, CEO of Energy Systems Network, said the transition could be eased by Internet-connected devices, which can receive signals to temper energy use when demand is high.
Roles for Energy Storage
Mitchell also touted the “endless” applications of energy storage, which can be integrated into the grid “at all different layers and levels.”
“The markets are going to have to realize that energy storage is not a renewable-based asset like wind and solar,” Mitchell said.
Richard Tabors, co-director of the Massachusetts Institute of Technology’s Utility of the Future Project, said markets will have to be value-driven instead of cost-driven, so that 200 MW in storage will be compensated based on the energy price when it’s consumed. “We’re not quite there yet,” he said.
“I think the trick for storage and renewables is to have really good forecasting in place so you know when to fill the storage and empty the storage,” said Michael Milligan, principal researcher at the National Renewable Energy Laboratory.
Milligan said for wind and solar to be integrated, systems have to be geographically large with very responsive markets — a recognition that has resulted in CAISO expanding beyond state borders with its Energy Imbalance Market.
“It’s my sumo wrestler theory of wind and solar integration,” Milligan said. “You have to be big and you have to be fast.”
Doughty said consumer participation in the grid will continue to rise, and CAISO has responded by rolling out two products allowing consumers to enter their solar generation into the market through aggregators.
“On our … 70,000-MW grid, we have 5,000 MW of solar that’s invisible to us and undispatchable,” he said. “We are very, very much bullish about involving the consumer. Because if we don’t involve them, they can become an unguided missile.
“My electric bill last month was $800,” Doughty continued. “And I don’t have a large home. In California, [highest electric rates are more than] $0.40/kWh. There’s a huge opening for solar. We have a tremendous responsibility to inform customers about their ability to participate in markets.”
BP’s Schubert said as more wind and solar are added, reserves need to be priced efficiently, or else MISO could find itself in a “binary position” where the marginal cost of wind will be $0/MWh then jump to an offer cap once the breeze stops.
“The beauty of pricing is if you price it right, it will all fall into place because everyone has an incentive,” Schubert said.
Several speakers talked about the need to increase research and development.
“The RTO creates value,” said David Sun, chief scientist at The Glarus Group. “It’s an economic platform that allows us to do things we previously could not. But that platform needs to change. It will do well in the future,” but “today we’re not doing enough innovative research. We’re doing embarrassingly little.”
Tim Heidel, program director at ARPA-E, called for a “no-regrets” approach to research and development, in which even failures are celebrated.
“One of the tough technical questions is how do we do that aggregation while respecting the constraints of the market. I think we’ll solve that and I think it’ll work, but there’s a possibility that we uncover another showstopper,” Heidel said. He predicted optimization algorithms will be a large part of distributed resource research.
Terry Oliver, chief technology innovation officer at Bonneville Power Administration, said he does not recommend MISO conduct basic research, but it could use its members to collaborate on narrower research topics. He also said the RTO should “free the data” to researchers and pointed out other sources of harvestable data, such as Nest thermostats.
Mitchell said the regulatory structure needs to expand to reflect the electrification of transportation and the role of microgrids and distributed resources. “Industry needs to be defined far more broadly than just RTOs and utilities,” he said.
Heidel said the scale of change in the electric system is going to be “huge,” pointing out how quickly the industry grew after Thomas Edison built the first central power plant on New York City’s Pearl Street in 1882.
“We’re going through that magnitude of change again,” he said. “Climate change is going to accelerate the rate of this change, and we’re going to be playing catch up for years. We’re going to get our feet wet in R&D again.”
Eleven respondents have submitted proposals for MISO’s Duff-Coleman transmission project, the RTO’s first competitive project under FERC Order 1000.
MISO said Friday that all 11 proposals were judged complete.
“Now that we have finalized our review of the proposals for purposes of completeness, we will begin evaluating the proposals based on the criteria set forth in the MISO Tariff and our Business Practices Manual,” said Priti Patel, MISO North regional executive and executive director of the RTO’s competitive transmission administration.
Ameren Transmission Company of Illinois and PPL TransLink;
Duke-American Transmission Co.;
Edison Transmission;
GridAmerica Holdings;
ITC Midcontinent Development;
Midcontinent MCN, with the Missouri Joint Municipal Electric Utility Commission;
NextEra Energy Transmission Midwest;
Republic Transmission, a subsidiary of LS Power Transmission, with Big Rivers Electric;
Vectren Energy Delivery of Indiana, a unit of Southern Indiana Gas and Electric, and Public Service Enterprise Group;
Transource Energy, a partnership between American Electric Power and Great Plains Energy, with subsidiaries Transource Indiana and Transource Kentucky; and
Xcel Energy Transmission Development.
The request for proposals window on the project opened in January and closed early last month. (See MISO Duff-Coleman RFP Deadline Passes; RTO Reviewing Bids.) The $67.4 million project was approved by the MISO Board of Directors as part of the 2015 MISO Transmission Expansion Plan.
MISO expects to announce its selection no later than Dec. 30. Construction on the pair of substations and the 28.5-mile 345-kV connecting line in Southern Indiana and Western Kentucky is expected to last through 2020, with the line in service by the beginning of 2021.
VALLEY FORGE, Pa. — After PJM’s Craig Glazer started with the food analogies, speakers at Thursday’s Grid 20/20 symposium couldn’t resist serving up a smorgasbord of edible metaphors.
Glazer, vice president of federal government policy, kicked off the conference, “Focus on Public Policy Goals and Market Efficiency,” talking about apples as a stand-in for power. To the laughter of the overflow audience, a slide depicted a grocery store display pricing the fruit to reflect subsidies (49 cents), subject to partial FRR adjustments (58 cents), MOPR’D per PJM rules (60 cents) and cleansed of all subsidies (65 cents).
PJM’s Craig Glazer likened the pricing of apples to MW at Grid 20/20. Image source: PJM
Currently, the recipe for competitive markets doesn’t call for carbon reduction, the preservation of jobs and tax bases, or the retention of uneconomic plants, he said. But these are among the public policy goals that some states are looking to achieve.
“A state could say, ‘Just add my one little ingredient,’” Glazer said. “The result isn’t just the most efficient solution for state A. Everybody gets it. How do we not force it on states B and C, who haven’t authorized us to put that ingredient into the blender?”
Penned amid efforts by money-losing coal-fired generators in Ohio and nuclear generators in Illinois to win state-backed subsidies, the report concluded that PJM’s markets efficiently manage the entry and exit of capacity resources, but they could be hamstrung by policies to protect social, economic or political interests.
The study drew a volley of critical correspondence to the Board of Managers from generators who said it presented a skewed view of the risks and benefits associated with competitive markets as compared with the traditional regulated model. (See Generators Rebut PJM Study on Investment in Competitive Markets.)
The subject incited just as lively of a debate at last week’s forum, which consisted of three panels: defining the problem, discussing traditional responses and studying alternative solutions.
FERC Commissioner Tony Clark, who will be leaving his post next month, delivered the opening remarks. Clark said that integrating public policies into competitive markets has become an increasing challenge for regulators.
“It’s going to be at the core and heart of what FERC is doing over the next several years and what states are going to be doing,” he said. “It’s going to last long past the next six weeks of my tenure, I can guarantee that.”
Although FERC’s job is not “passing philosophical judgement” on state policies, he said, those policies impact the commission’s jurisdiction over wholesale markets.
“We have the responsibility for just and reasonable rates,” he said. “There may be an iterative process where we try to set the boundaries and bumpers around what is permissible and what is not. But it’s not going to be an easy process.”
Even states that share a goal — such as the nine in the Regional Greenhouse Gas Initiative — can have differing ideas of how to reach the objective, said Marc Montalvo, president of Daymark Energy Advisors, who spoke with Glazer on the first panel.
State policies also can have unintended consequences, he said, citing the challenges faced by California and Hawaii, which are chasing ambitious renewable power goals.
“Every last region inside of the country is wrestling with the same issues. We want to make sure we’re doing smart investments, protecting consumers, respecting competitiveness,” he said. “All of us who are working in the markets are trying to figure a way to mix that batter up to make a delicious pancake.”
How Can PJM Markets Change?
The second panel was led by Hung-po Chao, senior director of economics for PJM. Panelists were Independent Market Monitor Joe Bowring; Steve Schleimer, senior vice president of government and regulatory affairs for Calpine; Susan Bruce, an attorney representing the PJM Industrial Customer Coalition; Jim Wilson of Wilson Energy Economics; and Lisa McAlister, deputy general counsel for American Municipal Power.
“The competitive wholesale market was designed to address and ensure reliable supply and an efficient market that includes resource adequacy issues,” Chao started off. “It was not designed to accommodate many other social objectives, like a clean environment. Here the question is: As these policy challenges are upon us, are there things that the PJM electricity markets can change to accommodate positive externalities?”
Playing off of one of Glazer’s analogies, McAlister said that just one kitchen tool — a blender — can’t make every dish.
“Unlike a real competitive market, the current PJM capacity construct is not sufficiently robust to accommodate unforeseen events,” McAlister said. “Adding another tweak to the 24 major adjustments since 2010 will only add another layer of complexity and uncertainty. It is time to look at simpler constructs that would be more resilient in the face of constant change.”
At Thursday’s Markets and Reliability Committee meeting, AMP’s Ed Tatum will be seeking support for an initiative to consider an overhaul of the capacity market. (See related story, Co-ops, Munis Call for Reset of PJM Capacity Model.)
Wilson agreed that changes to the capacity market are needed.
PJM’s changing resource mix is creating a need for flexible capacity, he said. “All of that is valued properly in the energy and ancillary services markets” he said, but not in the capacity market.
Schleimer took a different view, saying that without the capacity market, there would be no independent power producers, and consumers would be shouldering the risk of building generation under state integrated resource plans.
“When you have more apples on hand than you will ever need, costs are always going to be low. You can either have an energy market with scarcity pricing, or you can have a capacity market to allow investors a reasonable opportunity to recover their capital,” he said. “Where do we want to end up 10, 20 years from now? In a world where new investment is only made from rate base?”
“I don’t know if we have a strong view decided on this because it’s such a difficult question and the history of this issue is so important to it,” responded Bruce.
She recalled 1997, when Pennsylvania’s Electricity Generation Choice and Competition Act went into effect. “The ideas of markets and shifting the risk away from customers was something attractive to industrial customers,” she said. “The driver was to reduce cost, reduce risk for customers.”
The Origin of the Markets
Bowring agreed. “The markets have worked very well. You have to remember where restructured markets came from — they’re an alternative to a regime in which public utilities commissions made decisions, many opaque, various policies of many kinds,” he said. “It was a conscious decision to move to markets.”
He said there exist ways aside from subsidies to achieve public policy goals. For example, he said, “If you want to deal with carbon, have a carbon price; don’t subsidize nuclear, have a carbon price.”
“Markets can’t handle the recent attempts to intervene in the market in Ohio on behalf of companies that wanted subsidies in their favor,” Bowring said. “That’s fallen by the wayside for various reasons, but we do need tools to address that type of intervention. We need to continue to react to change. The market has to be flexible, and the market designers have to be flexible.
“The reason we have markets is to provide power to customers at the lowest possible [cost]. We have to be careful not to let other aspects of the debate interfere with that or undermine them. Markets are more fragile than we all think, and they could go away fairly easily.”
Capacity Market at Risk?
The third panel, moderated by Vince Duane, PJM’s senior vice president for law, compliance and external relations, hosted William Berg, vice president of wholesale market development for Exelon; Peter Fuller, vice president of market and regulatory affairs for NRG Energy; Stu Bresler, PJM’s senior vice president of operations and markets; Raymond DePillo, senior director of market development for PSEG Energy Resources and Trade; and John Moore, senior attorney for the Sustainable FERC Project.
Asked if the capacity market is at risk, Bresler said, “I certainly think a do-nothing approach going forward puts the goals of the markets in general at risk. The risk of a do-nothing approach is a detrimental effect on the long-term price signal.”
“Yes, I do think we are putting the capacity market at risk,” DePillo said. “We’re going through what is effectively a fleet transformation. How do we do that in the most effective way possible? We are going to need uneconomic retention,” he said, referring to state initiatives such as New York’s nuclear subsidies.
“The more we attempt to use the capacity market, particularly in isolation, to solve all the blender issues we are facing today, the more distorted it gets,” Berg said.
He advocated a holistic approach. “That starts with an honest conversation about what constitutes a subsidy so onerous it needs to be subject to mitigation,” he said.
For his part, Moore said the Sustainable FERC Project supports a goal of 80% carbon reduction by 2050.
“There are a lot of good state policies that get us a long way that we should protect,” he said. “I wonder if we’re going down the wrong fork in the road adding complexities to the capacity market.”
Bresler introduced an idea for a two-stage capacity auction that would integrate subsidized resources but prevent them from impacting the prices of other generators. Fuller welcomed PJM’s effort to respond to out-of-market state policies but expressed concern that the model would place all of the risk of state policy implementation on resources at the margin, which could defeat the goal of protecting price formation.
The concern, which PJM’s proposal acknowledges, is that resources will bid zero to ensure they clear in stage 1; those that don’t won’t receive any capacity revenue through the second, higher-priced stage, clearing after subsidized units are removed. “It is unclear whether this potential would have any significant impacts on resource offer behavior in the capacity auctions,” PJM said.
Berg wasn’t so sure. “My first thought is if there was ever any doubt that … resources will bid zero, this is it amped up on steroids,” he said.
PJM CEO Andy Ott closed out the session, saying, “I see this issue as fairly large for us.” He added, “It’s no secret that PJM feels strongly about its competitive markets.”
Stakeholders can expect the dialogue to continue, he said.
“Don’t worry,” he reassured the audience. “We’re not going to make a filing tomorrow.”
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
