Years in the making, a settlement between PJM and transmission owners over the RTO’s procedure for allocating the costs of major transmission projects is receiving criticism from stakeholders that say they weren’t invited to the table.
The case has dragged on for nearly a decade, with FERC’s orders on how to allocate costs for transmission projects at or above 500 kV twice being remanded by the 7th U.S. Circuit Court of Appeals back to the commission.
PJM’s “postage-stamp” cost allocation for the projects was challenged by the RTO’s Midwestern utilities. The method billed all PJM utilities in proportion to their load, regardless of where the projects were located.
The commission had originally approved the postage-stamp method in 2007 and attempted to justify it in its order on remand. The court, however, ruled that FERC had again failed to show how a western utility would benefit as much as an eastern utility from new transmission facilities in the east. (See FERC Orders Proceedings to Decide PJM’s Postage-Stamp Cost Allocation.)
In June, after more than a year of negotiations, a large majority of stakeholders submitted to FERC a settlement that created a cost allocation formula for projects approved prior to Feb. 1, 2013, when PJM abandoned the postage-stamp method (EL05-121).
“The overwhelming majority of the PJM transmission owners and all of the state regulatory authorities that have actively participated in this proceeding are either settling parties or have agreed not to oppose the settlement,” the filing reads.
The agreement would require collecting fees from customers on the eastern side of PJM’s territory and distributing them to customers on the western side. For projects that have been or will be completed, the settlement assigns 50% of costs on a load-ratio-share basis and the remaining 50% under the solution-based distribution factor (DFAX) methodology — the same method used for regional 500-kV projects approved since 2013.
Abandoned or canceled projects would be assigned using the violation-based DFAX method. The charges would be retroactive to Jan. 1, 2016.
Retroactive Issues
The settlement didn’t sit well with Direct Energy and the Retail Energy Supply Association, which argued they were neither invited to participate in the settlement talks through the PJM stakeholder process nor informed that they’d be expected to pay for the result.
On Monday, RESA appealed the denial of a previous motion to intervene in the case. In the appeal, the group stated that the settlement would require its members to pay their allocated share retroactively, “even if the customers who should be billed for the amounts have migrated to another supplier.”
Under deregulation, customers of the load-serving entities that make up RESA’s membership can switch companies quickly, so LSEs aren’t able to pass along retroactive charges to those who’ve left in the interim, the group said.
The denial, written by Acting Chief Administrative Law Judge Carmen A. Cintron, called RESA “a party that is uninformed of the delicate and complex negotiations that transpired in its absence.”
“When entities wait unreasonably long to seek intervention, [FERC] has stated that they ‘assumed the risk that the parties would settle the case in a manner not to their liking.’ Such is the situation that RESA’s delayed request has created for itself,” Cintron wrote.
RESA said it only became aware of the proceedings by reading the published settlement and that its suggested changes would “create minimal, if any, disruptions.”
“This is not a situation where an intervenor seeks to scuttle a settlement,” RESA said.
The group suggested two options to solve the issue: change the date for when charges should go into effect to sometime in the future, or put the burden of recovering the costs on electric distribution companies.
RESA is “hopeful” its new arguments will allow it to intervene, spokesman Bryan Lee said.
Marji Philips of Direct Energy said her company estimates the settlement will cost eastern ratepayers about $287 million.
“The LSEs are going to wind up having to pay for these costs that everybody agreed should be rate-based, and the calculation when it was originally done was done incorrectly,” she said.
Comments Pro and Con
Direct Energy and RESA are not alone in their opposition to the settlement. Linden VFT, which owns merchant transmission facilities, said it would not receive benefits in the settlement commensurate with the costs it would incur. In filed comments, Linden said the solutions-based DFAX method is “unduly prejudicial” to companies like itself.
But many stakeholders filed comments in support of the settlement.
“Pennsylvania’s ratepayers have been unfairly burdened, since 2007, with an excessive portion of those costs associated with the transmission projects encompassed by the settlement,” the state’s Public Utility Commission said. “The settlement agreement resolves those inequities and establishes a more reasonable and equitable cost allocation for both previously incurred costs as well as costs yet to be recovered.”
The PJM Board of Managers has suspended the controversial Artificial Island transmission project pending a “comprehensive” staff analysis to be completed by February, at which time it will decide a course of action, CEO Andy Ott said in a letter to stakeholders Friday.
“It has become evident to all involved that the projected costs to resolve the problems at Artificial Island have increased significantly. PJM has been examining alternatives in an attempt to offset some of the increases,” Ott wrote. “In addition, questions have arisen about whether the currently proposed solution would perform as intended without further expense. Because of these concerns, PJM has come to the conclusion that a pause in the project is necessary before any new financial obligations are incurred by the project developers.
“In light of the current uncertainties around the changing scope and configuration of the project, it is imperative that we understand the basis for any alternatives that may exist to manage the operational issues at Artificial Island.”
Salem and Hope Creek Nuclear Reactors on Artificial Island Source: Wikipedia
This is the second time the board has overturned the stability project — PJM’s first competitive solicitation under Order 1000.
Initially, PJM planners recommended awarding the work to Public Service Electric and Gas, but the board reopened bidding to finalists following protests from spurned bidders, state officials and others. (See PJM Board Puts the Brakes on Artificial Island Selection.)
PSE&G, one of three entities eventually designated to build a 230-kV transmission line from the New Jersey nuclear complex under the Delaware River to Delaware, said Friday it was “committed to working with PJM and will provide PJM with any information and support they request.”
LS Power’s Northeast Transmission Development, picked to construct the transmission line, said Friday it was “disappointed” by the board’s action.
“The modeling errors in question do not relate to Northeast Transmission’s designated portion of the Artificial Island project and Northeast Transmission was not involved [in] the associated modeling activities,” it said. “Northeast Transmission was surprised by the PJM board’s decision, as Northeast Transmission had received no indication prior to the announcement from PJM on Aug. 5 that PJM had any concerns with PJM’s or PSE&G’s modeling of the system protection and control upgrades.”
Pepco Holdings Inc., chosen to work with PSE&G on the project, did not immediately respond to requests for comment.
The board approved the stability fix for the complex that houses the Salem and Hope Creek nuclear generators last summer. But in April, PJM revealed that PSE&G’s portion of the project — which the RTO initially pegged at $137 million — had nearly doubled to $272 million once the transmission owner completed a detailed analysis. (See Artificial Island Cost Increase Could Lead to Rebid.)
“PJM conducted a preliminary estimate regarding the interconnection to Salem,” a PSE&G spokeswoman said Friday. “We then conducted a detailed, design-level analysis of the interconnection to Salem. We had not previously prepared a detailed estimate for Salem because our proposal would have terminated in Hope Creek.” (See PSE&G Defends Artificial Island Cost Increase.)
The sticker shock prompted PJM planners to consider other alternatives, including terminating the line at Hope Creek.
“However, in reviewing this alternative, an issue arose related to one of the other components of the project: that is, whether proposed system protection and control upgrades would perform as intended,” Steve Herling, PJM’s vice president for planning, said in a letter to stakeholders Friday. “Specifically, PSE&G identified an error related to the modeling of circuit breaker clearing times associated with those upgrades. The effect would be a reduction in the margin of stability provided by those upgrades, regardless of any alternatives to the transmission solution under review, requiring further steps and expense to correct.”
In an informational filing with FERC submitted Friday, PJM said, “By virtue of this suspension, all designated entities are placed on notice to cease incurring any new financial obligations on the Artificial Island project until PJM completes its analysis and the PJM board has made a subsequent determination based on that analysis.”
Neither of the letters PJM sent out Friday mentioned the cost allocation controversy.
Delaware Gov. Jack Markell released a statement commending the PJM board for its action.
“This decision is one that the state of Delaware welcomes,” he said. “The project as it was proposed would have placed an unjust burden on the state, resulting in higher electric rates for our consumers and businesses. I hope that upon further review, a more equitable solution can be identified.”
Bob Howatt, executive director of the Delaware Public Service Commission, said the agency was still analyzing the board’s decision.
“It seems like the political and economic concerns may have succeeded in stopping what has been called the most efficient and cost-effective solution because PJM and FERC have failed to address the cost allocation issue,” he said, adding that the decision seemed “totally unfair” to LS Power.
Howatt said he worried what effect the suspension would have on the desire of independent transmission companies to participate in the Order 1000 process.
“If I were an independent transmission company, why would I waste a lot of time on a project that could get overturned?” he said. “I just see it chilling the competitive transmission market that FERC has been attempting to create.”
Exelon announced Tuesday it has purchased the James A. FitzPatrick nuclear plant for $110 million from Entergy.
Officials from both companies were joined by Gov. Andrew Cuomo at the plant’s gates to announce the deal, which is subject to regulatory approval.
“We are pleased to have reached an agreement for the continued operation of FitzPatrick,” Exelon CEO Chris Crane said in a statement. “We look forward to bringing FitzPatrick’s highly skilled team of professionals into the Exelon Generation nuclear program, and to continue delivering to New York the environmental, economic and grid reliability benefits of this important energy asset.”
Entergy executives had reiterated last week that the company did not intend to continue operating the troubled plant in upstate New York beyond January 2017.
“There are no plans to continue to run the plant under Entergy ownership,” Bill Mohl, president of Entergy Wholesale Commodities, told analysts during the corporation’s second-quarter earnings call Aug. 2.
Fitzpatrick Nuclear Plant Source: Entergy
The company had announced plans to shut down both FitzPatrick and the Pilgrim nuclear plant in Massachusetts, but it recently said it had opened negotiations with Exelon over FitzPatrick. (See Entergy in Talks to Sell FitzPatrick to Exelon.)
Mohl told analysts if Entergy and Exelon are able to gain regulatory approvals for the transaction, refueling activities would begin in January. Otherwise, the decommissioning process would begin instead.
“We’ve made a commitment to reduce the size of the EWC footprint,” Mohl said. “If we’re unable to reach commercial agreements with Exelon or we’re not able to achieve those regulatory approvals, we’ll begin the regular decommissioning process and stay on the same path that we have previously been on.”
New York’s Public Service Commission on Aug. 1 unanimously approved 12-year subsidies for the state’s nuclear power plants on Lake Ontario, which have been buffeted by market forces. (See New York Adopts Clean Energy Standard, Nuclear Subsidy.)
Entergy reported second-quarter net income of $572.6 million ($3.11/share). That beat analyst expectations of $1.05/share, as polled by Thomson Reuters.
Revenue dropped to $2.46 billion, from $2.71 billion in the second quarter of 2015. The company said its March purchase of a 1,980-MW natural gas plant in southern Arkansas helped support revenue during the quarter.
Company shares, up 18.9% this year before the earnings announcement, have dropped 94 cents since, closing at $80.33 on Aug. 3.
AUSTIN, Texas — ERCOT’s Technical Advisory Committee last week rejected a request to allow economic dispatch of reliability-must-run (RMR) units over the objections of the ISO’s Independent Market Monitor and several of its Houston-area market participants.
NRG Texas drafted nodal protocol revision request 784, which addresses how RMR units are priced and dispatched, about the same time as ERCOT made its recent decision to extend into 2018 an RMR contract for NRG’s Greens Bayou Unit 5 near Houston.
The contract requires ERCOT to pay $3,185/hour for the duration of the agreement and an incentive factor of as much as 10% to reserve the 371-MW gas-fired unit’s capacity during summer months through June 2018. (See “Board Expands Greens Bayou RMR Contract to 2018,” ERCOT Board of Directors Briefs.)
NRG’s request would allow security constrained economic dispatch of RMR units to relieve transmission congestion after all other capacity available for transmission congestion relief had been exhausted.
Market Monitor Beth Garza supported the proposal, which she said would increase the dispatch price of RMR units, allowing other market units to be dispatched to resolve the constraint first.
In ERCOT’s energy-only market, an RMR agreement results from either a poorly designed evaluation process — which mistakenly identifies a resource as needed — or a failure of the market to provide sufficient revenue to justify continued operation of a needed resource, she said.
“Should the failure be in the RMR designation process, the resource is unlikely to be deployed and its energy offer price will be immaterial,” Garza said. “However, if the failure is in the market signal to units in this constrained area, the unit is likely to be deployed and the energy offer price will matter.”
Bill Barnes, NRG Energy’s director of regulatory affairs, said the request underscores the importance of sending the right price signals in the ERCOT market.
“We’re spending $60 million on an RMR contract for the months of June, July, August and September,” he said. “When you look at the State of the Market report for 2015, the real-time congestion rent for three of the major north-of-Houston constraints is $5 million. We’re spending $60 million to solve a $5 million problem. There are legitimate situations where the market solves the problem in a cheaper way. The boogeyman that is high prices gets pummeled by the boogeyman that is RMR.”
As drafted, NPRR784 would only apply when generator offers are mitigated because there is inadequate competition. RMR units are currently subject to the same offer mitigation as other units in such a situation, with Greens Bayou Unit 5 likely being offered at around $50-60/MWh. When there is adequate competition, RMR units are offered at $9,000/MWh under either the status quo or the NPRR.
The revision request would instead require all RMR units to be offered at the highest possible price that would still allow SCED to dispatch the unit for congestion. In Greens Bayou’s case, the estimates are as high as $700/MWh.
The NPRR failed to gain the Protocol Revisions Subcommittee’s endorsement during a roll-call vote July 14, but NRG appealed to the TAC. The revision request eventually fell short of the necessary two-thirds approval, with 54% positive votes and four abstentions.
NRG on Friday filed another appeal with the Board of Directors, which will consider the proposal at its Aug. 9 meeting.
“How do you prevent future RMR? By sending the right price signals,” Barnes said. “The presence of the RMR is evidence the market signal has failed. 784 addresses the most important RMR issue: How do you send the right price signal? It’s not a perfect solution, but is it better than what we have today? We believe the answer is yes.”
Garza supported Barnes’ position, although she also said she is a “huge believer” in ERCOT’s stakeholder process and “what this room can do.”
“Our position has been the objective of the RMR should be the price should be reflective of the unit not being there, but we should have the energy available to resolve the constraint,” Garza said. “It is absolutely a shortage condition. If that situation did not exist, Greens Bayou would be on the way to the scrap heap right now.
“I’m sympathetic to the argument that, ‘Gosh darn it, we spent $60 million on this unit, why can’t we use it?’” Garza said. “However, believe it or not, those are sunk costs … that don’t change if you resolve this situation. When you’re talking about resources necessary to resolve a transmission constraint, there are two factors: the offer price or mitigated offer cap, and the shift factor of the unit on that constraint — the effectiveness of that unit to relieve the constraint.”
“We generally agree with the IMM … but we disagree that 784 as a one-off is the solution,” said Energy Future Holdings’ Amanda Frazier, chair of the PRS. “We’re concerned [NPRR784] is reactionary. It doesn’t address whether Houston prices are high enough to allow RMR. If we pass this, we’re paying for incorrect price signals.”
Katie Coleman, with the Texas Industrial Energy Consumers group, represented the PRS position, arguing NRG’s proposal is punitive to loads, encourages unit retirements by providing scarcity pricing in non-scarcity conditions and prevents the RMR unit from solving other constraints beyond a single transmission line.
“We have concerns about requiring loads to also pay $600-800/MWh to use that unit for the very purpose it was placed under an RMR contract,” she said. “We have concerns about the incentive this creates for a generating company with a fleet of units in a certain area to retire units and get high pricing for its other units. [NPRR784] would require Greens Bayou to be priced at the highest possible price to solve, which would preclude it from solving other constraints in area.”
Noting that the revision request has been classified as urgent, Coleman said that electric retailers are concerned its requested September implementation timeline does not provide enough lead time for Greens Bayou and other generators in the area.
Coleman also noted customers are paying for Greens Bayou only until the Houston Import Project goes into service as early as 2018, when it is expected to solve the region’s congestion issues.
“This NPRR is sending a price signal too late to matter,” Citigroup Energy’s Eric Goff said. “The fact the contract exists is interfering with what would happen had the unit been allowed to retire. It gets to the point of whether there’s a weird incentive here.”
“If you’re a load outside of Houston, I have no idea why you’re not outraged,” Barnes said. “If the load in Houston has a small load-ratio share, I can understand why you would want someone else to solve your problem. We’re an energy-only market. Price signal is everything.”
Shortly after the TAC meeting concluded Thursday, ERCOT posted answers to questions it received from its request for proposals for must-run alternatives to the Greens Bayou RMR contract. (See ERCOT Seeks Alternatives to Houston-Area RMR Unit.)
Committee Discusses July 7 System Outage
ERCOT staff shared its analysis of the July 7 outage of its Energy Management System. The outage lasted 102 minutes and resulted in corrupted data being passed to downstream systems, including settlements and reports. Market participants said they saw a perceived drop-off in load and generation, but their primary complaints were around a lack of information coming from the ISO.
“When these things are occurring, I know ERCOT is scrambling to recover and get the grid stable again,” Barnes said. “From a market perspective, it was pure chaos. Market notices should be crystal clear about what is happening.”
“We just knew something was wrong because of operation notices,” Goff said. “Knowing the extent of the outage would be beneficial to the market.”
“We want to share with you the information we definitively know as quickly as possible,” said Kenan Ögelman, ERCOT’s vice president of commercial operations. “The tension we’re trying to balance is how long to hold information back until we can be sure” it’s accurate information.
The problem began at 11:41 a.m., when an operator mistakenly loaded test data into the active system, which corrupted data in the emergency system’s network model. Between 11:59 a.m. and 12:16 p.m., the market’s qualified scheduling entities were instructed to assume constant frequency control. By 1:23 p.m., the data had been corrected and verified, and operations returned to normal.
Corrected prices were posted for the affected SCED intervals, and staff said that it is continuing to evaluate alternatives that may affect subsequent settlements.
Barnes was successful with a second NPRR, dealing with ERCOT’s price-correction process following a SCED failure. NPRR696, which Barnes drafted on behalf of NRG subsidiary Reliant Energy Retail Services, passed with 72% of the vote.
“When the SCED system is not running, inputs grow stale. When it starts back up, things don’t make sense,” Barnes said. “It comes down to whether you believe the last best price, or whatever it spits out.”
NPRR696 establishes a price-correction policy that uses the last good price for settlement until ERCOT no longer requires manual action to stabilize the system. Barnes said that correcting prices for settlement intervals corresponding to the active watch period would give market participants transparency to known prices that reflect the last good SCED execution.
“This policy would extend that last good price for another 15 minutes,” Barnes said. “It could be the last high price or the last low price.”
The TAC unanimously endorsed six other NPRRs, a system-change request (SCR) and revisions to the Nodal Operating Guide (NOGRR), the Planning Guide (PGRR), the Retail Market Guide (RMGRR) and the Resource Registration Glossary (RRGRR).
NPRR738: Excludes from performance calculations intervals when an emergency response service generator is unable to meet its obligations because of transmission/distribution service provider (TDSP) outages.
NPRR747: Proposes new definitions related to voltage profiles, defines various entities’ responsibilities related to voltage support and clarifies that the interconnecting transmission service provider or its designated agent may modify a generation resource’s voltage set point.
NPRR767: Changes the eligibility check for the startup portion of the reliability unit commitment make-whole payment. Resources with lead times longer than six hours may submit a settlement dispute to have their resource-specific startup times considered when determining eligibility for startup costs included in the make-whole payment calculation.
NPRR770: Adds visibility and situational awareness to the market by posting the aggregate number of telemetered resources and their statuses to the ancillary service capacity monitor.
NPRR771: Clarifies that TDSPs must ensure an electric service identifier has been created in ERCOT systems before initiating electric service at a premises, avoiding related transactional, billing and out-of-sync issues.
NPRR774: Removes duplicate language regarding the calculation of seasonal transmission-loss factors.
NOGRR155: Clarifies voltage ride-through performance requirements for all generation resources immediately following a fault, stipulating that they must remain online and connected to the transmission system, and also maintain real power.
PGRR046: Aligns the planning guides with NERC’s TPL-007-1 reliability standard related to geomagnetic disturbances by specifying a process for developing geomagnetically induced system models.
RMGRR138: Removes the requirement for retail electric providers serving pre-pay customers to provide a weekly list of electric service identifiers to Oncor, replacing it with the requirement to provide the prepay list upon Oncor’s request.
RRGRR009: Adds three categories of data: voltage limits for resources’ substation transmission level equipment; geomagnetically induced currents and the presence of blocking devices to allow for the study of any vulnerability attributed to geomagnetic disturbances; and a most limiting single element (MLSE) allowing a resource entity to identify an MLSE on lines it doesn’t own.
SCR789: Updates the Network Model Management System topology processor to add a software tool commonly used by transmission-planning entities in ERCOT.
NASHVILLE, Tenn. — Regulators and utility officials commiserated over the difficulty in overcoming public opposition to large energy infrastructure projects during a panel discussion at the National Association of Regulatory Utility Commissioners summer conference last week. About 1,000 people attended.
Iowa Utilities Board member Libby Jacobs, who moderated the session, said she had become the target of vitriol following her vote in June approving the Dakota Access Pipeline, which will carry crude oil from North Dakota’s Bakken field through South Dakota and Iowa to Illinois. The week before the NARUC meeting, an activist group staged a street theater performance outside IUB offices called “In Bed with the Bakken,” in which one protester portrayed Gov. Terry Branstad bottle-feeding an oil pipe.
“I’m also very familiar with the anti-infrastructure protesters,” offered FERC Commissioner Cheryl LaFleur from the audience, referring to the monthly protests at FERC open meetings.
Opposition to infrastructure projects has been a challenge “since I’ve been in the industry,” she continued. “But I sense something different happening.
“I’m a little concerned … with the growing thought out there that maybe we don’t need any infrastructure at all,” LaFleur said. “‘We’re just going to close what we have and replace it with everything distributed.’”
Jacobs, a former corporate communications executive, said protesters have benefited from social media as an organizing tool.
Aakash Chandarana, regional vice president of rates and regulatory affairs for Xcel Energy’s Northern States Power, said utilities need to do a better job of educating their customers.
“Often times we as a utility are trying to talk to our customers at the most intense period in our relationship — either through storms or during a rate case or something like that. … We have to approach our customers at a period of time where maybe there isn’t as much emotion.”
Robert Kenney, vice president of state regulatory relations for Pacific Gas and Electric, agreed. “I’m not sure that utilities or regulators have done [a good] job in helping customers understand why certain investments need to be made,” he said.
He lamented the utility’s decision, announced in June, to retire the Diablo Canyon nuclear plant when its current operating licenses expire in 2024 and 2025, noting it “has been a source of greenhouse gas-free energy for the last 30-some odd years.” (See PG&E to Shut Down Diablo Canyon, California’s Last Nuclear Plant.)
“The political climate in California was such that being able to relicense that beyond 2024 and 2025 made it a huge challenge,” Kenney continued. “I say that as an example of the fact that we have technologies that will allow us to meet climate goals but then you have conflicting political goals that prohibit the running of nuclear generating facilities.”
Exelon CEO Talks Capital Allocations, New Products
NARUC President Travis Kavulla conducted an interview with Exelon CEO Chris Crane that touched on subjects from capital allocations and new utility products to the struggles of its nuclear generation fleet and cybersecurity.
Kavulla asked Crane whether Exelon, which now operates in five states and D.C. following its acquisition of Pepco Holdings Inc., favors states with higher returns on equity in determining where to allocate capital.
Crane said each of the company’s six utilities maintains its own balance sheet and cash flow and that the company makes investments based on reliability requirements.
“It does at times require equity infusion from the parent. PHI right now, and for the next five years, will have equity infusions … on an annual basis.
“We don’t find that as a conflict,” Crane said. “We’ve never had to make a decision that a dollar goes into one jurisdiction versus another … there is enough capital and our balance sheets are strong.”
Crane said Exelon’s decisions on what “utility of the future” products to offer is based on “understanding what is a trend and what is a fad.”
“We have to differentiate. Technology is changing faster than it ever has in our industry,” Crane said. “We have to watch what the consumer wants versus what the commercial side wants to sell.”
Commercial Customers Will Go it Alone to Meet Sustainability Goals
Commercial customers would like utilities’ help in meeting their sustainability goals but “will pursue their goals with or without” them, according to the Critical Consumer Issues Forum’s latest report released last week.
More than 80 state regulators, consumer advocates and utility representatives took part in meetings that resulted in the report, developing “consensus principles,” such as providing flexibility to consumers seeking new technologies and products while protecting nonparticipating consumers from cost shifts.
To be responsive to customers, Arizona Public Service will initiate some innovative projects without getting regulatory approval first, said Barbara Lockwood, vice president of regulation.
“We have taken the approach that there are some projects that we’re going to embark on and we’re not going to ask the commission [in advance]. We’re going to go do it and then we’re going to ask for recovery of those costs. We’re taking some risk that we never took in the past,” she said.
Lockwood cited a 25-MW microgrid the utility is building with the U.S. Navy at Marine Corps Air Station Yuma. The microgrid’s diesel generator can provide peak power to APS customers during normal operating conditions and is large enough to power all base operations during a grid disturbance. “We didn’t seek preapproval for that project,” Lockwood said. “It was important to move quickly.”
Federal-State Battle over Plains & Eastern Transmission Line
Jordan Wimpy, an attorney representing landowners opposed to Clean Line Energy Partners’ Plains & Eastern transmission line, said he is likely to file a court challenge seeking to block the Department of Energy’s record of decision supporting the project. “We are prepared to file and we are moving in that direction,” Wimpy said.
The department said in March that it would partner with Clean Line on the $2.5 billion, 700-mile HVDC transmission project, which would deliver 4,000 MW of wind power from the Oklahoma Panhandle to MISO and the Tennessee Valley Authority. The department acted after Clean Line was unable to win approval from Arkansas regulators. (See DOE Agrees to Join Clean Line’s Plains & Eastern Project.)
Mark Bridgers, a principal with Continuum Capital, a Raleigh, N.C., investment banking advisory firm, presented a forecast indicating utilities need to add 50,000 new transmission and distribution workers. By 2018, Bridgers said, all of New England, much of the Mid-Atlantic and several Western and Midwest states will face shortages in T&D workers.
Bridgers gave a plug to the Underground Construction Workforce Alliance, which is building a coalition of industry associations, unions, suppliers, engineers, contractors and utilities to develop training programs and regulatory approaches to develop the workforce required.
NASHVILLE, Tenn. — PJM’s Capacity Performance rules got little love last week during a panel discussion on the role of states versus markets in procuring electric generation.
Other Eastern RTO capacity markets and New York’s planned nuclear subsidies also came under fire in a discussion at the National Association of Regulatory Utility Commissioners summer conference.
Economist William Hogan, of the Harvard Kennedy School, and Allison Clements, a Natural Resources Defense Council representative to the Sustainable FERC Project, led the criticism of PJM’s Capacity Performance rules.
Clements said the environmental community does not have a preference between wholesale markets and bilateral trading. “But if [markets are] going to exist, we want to make sure that the rules are fair so that clean energy resources can compete to provide services,” she said.
Aside from FERC Order 745, which helped demand response resources enter the wholesale markets, she said, “we haven’t been that successful, and we’ve come to this point where the energy/capacity market construct, at least in the Eastern Interconnect RTOs … [is] broken.”
Clements said PJM’s Capacity Performance rules, which favor baseload generation available 24 hours a day year-round, “locks in this traditional, outdated resource mix view” that favors nuclear energy over renewables and DR, a case NRDC and other environmental groups made last month in asking the D.C. Circuit Court of Appeals to review FERC’s approval of PJM’s rules. (See Clean Energy Advocates Appeal FERC’s Capacity Performance Rulings.)
While CP rules allow summer and winter resources to aggregate a single capacity offer, no aggregate offers were submitted in the first Base Residual Auction with CP for delivery year 2018/19. In the second auction under the new rules in May, only 6% of cleared DR resources qualified as CP, compared with 9% of wind and one-tenth of 1% of solar.
“Because renewables can’t provide baseload Capacity Performance … the capacity they do provide doesn’t get counted, which means that your state policy to encourage clean energy that your customers are paying for isn’t getting full value,” Clements said.
Hogan also was critical of CP and of FERC’s oversight. He said the commission needs to ask the question: “‘Are the changes we’re making in market design going in the right direction?’ And when it’s not, to stand up and face it squarely and don’t succumb to double talk.”
PJM’s CP penalty mechanism means generators could face penalties of $5,000/MWh for shortfalls while the demand side will be seeing prices that are only $500/MWh, Hogan said.
“This can’t make sense,” he said. “You should be able to test these designs against [a] Platonic vision … and where there’s a dramatic difference like that you should be able to ask ‘Why are we doing this? Why are we sending signals to the generators and not to the load when we get into critical capacity situations?’”
Clements said it’s not necessary to abandon capacity markets and go to shortage pricing, as in ERCOT. “I think there’s something in between there,” she said, praising the “flexibility products” being offered in CAISO and MISO.
Jay Morrison, vice president of regulatory issues for the National Rural Electric Cooperative Association, also contended that RTO capacity markets aren’t working.
“Where’s the tangible evidence that they’re failing in their mission?” asked panel moderator and NARUC President Travis Kavulla, noting the new resources that have cleared PJM and other capacity markets.
“My litigation budget,” Morrison quipped. “I could save a lot of money if these markets were working properly.”
But Morrison also challenged Hogan. “There’s no Platonic ideal of a market out there,” he said. “Markets are designed for specific purposes. These markets should be designed to meet the needs that the consumers express through the utilities that serve them, through their politically elected or appointed officials.
“The market should be designed to meet the needs that the consumers want,” he continued. “The consumer shouldn’t be asked to buy the product that the market says is the right product. We need to remember which is the dog and which is the tail.”
Morrison said states have intervened — sometimes running afoul of FERC jurisdiction — “because there are important values that they are trying to pursue … that aren’t important to the market operators and aren’t incorporated into the market design.”
“Yes there are new resources [from capacity markets], but are they the right resources?” Morrison asked. “Yes, there are new resources, but are some of the people investing in them risking that they’re going to pay twice? Both for the resource in which they’re investing and the one that the market operator says they’re supposed to buy.”
RTOs have developed valuable new products for managing system operations but have not responded with the environmental or risk management products sought by consumers and state policymakers, he said. “Those are the kind of products for which bilateral markets are ideally suited,” he said. “And so long as we have the minimum offer price rule [and] buyer-side mitigation, we have trouble accessing those resources.”
The only panelists to offer much support for RTO capacity markets were Michael Haugh, assistant director of analytics for the Ohio Consumers’ Counsel, and Sarah Novosel, senior vice president and managing counsel for Calpine.
Haugh said PJM’s markets have brought new generation to serve Ohio and encourages sharing of resources among states, which reduces costs.
Novosel said her company would prefer capacity markets in all regions. She reserved her criticism for state interventions, such as proposals in Illinois, Connecticut, New Jersey and New York to subsidize nuclear plants. She said New York’s zero-emission credit program for its upstate nuclear fleet is discriminatory, will hurt markets and intrudes on federal jurisdiction, in violation of the U.S. Supreme Court’s ruling in Hughes v. Talen. (See related story, New York Adopts Clean Energy Standard, Nuclear Subsidy.)
“We’re troubled by all of these proposals because all of them, we feel, are going to undermine the wholesale markets, which competitive generators rely on for our revenue,” she said. “And once you start to pull the string and start to unravel these wholesale markets, you’re going to end up with having other generators who rely on the wholesale market needing a subsidy or long-term contract in order for them to also receive sufficient revenue to continue operations. … And by entering long-term contracts, you’re putting the risk back onto the ratepayers.”
Novosel acknowledged that “we don’t have any answers — yet.” But she said she is encouraged by the efforts being taken by RTOs to address the challenges. She cited PJM’s white paper in May and its Aug. 18 Grid 20/20 forum on public policy goals and market efficiency, and the New England Power Pool’s planned stakeholder meeting on Aug. 11 on how to preserve markets while also reducing states’ carbon footprints. “We’ve got a lot of smart people in this industry. We can come together and come up with a solution that works,” she insisted.
The simplest fix for the plight of nuclear generation and the desire for less polluting resources, the panel agreed, was to internalize the cost of carbon into the markets — a no-brainer to economists but a nonstarter for many politicians.
“I just don’t believe that” enacting a carbon tax is impossible, Hogan said, noting that he heard similar warnings before ERCOT’s move to scarcity pricing.
“I’ve been involved in lots of things that were ‘politically impossible’ when we first started talking about them,” he said. “And now they’re old hat and conventional wisdom.”
American Electric Power CEO Nick Akins said last week the Columbus-based energy giant is seeking only a partial “restructuring” of Ohio’s energy market, not full reregulation.
After FERC ruled in April that it would review state actions to guarantee income for some of AEP’s Ohio power plants, Akins had said the company would lobby Ohio lawmakers for reregulation of the state’s electricity market while also considering selling off its Ohio fleet. (See All Eyes on AEP, FirstEnergy with Ohio PPAs in Doubt.)
AEP Dresden Gas Plant in Ohio Source:AEP
Asked during a July 28 call with analysts whether AEP was de-emphasizing “reregulation” of the market, Akins said, “Reregulation just has a larger connotation to it and actually is a much heavier lift to put the entire genie back in the bottle.
“With FERC’s order essentially taking the Ohio [power purchase agreement] proposal approved by the Ohio commission off the table, which I discussed last quarter, AEP is addressing the situation by pursuing restructuring in Ohio,” he said. “Note this is restructuring, not reregulation.”
Akins said state lawmakers and other power generators are discussing the company’s proposed legislation that would transfer its competitive power generation to its AEP Ohio subsidiary. The legislation would also allow AEP to invest in new natural gas and renewable energy power sources.
“The proposed legislation strikes a balance between our ability to invest and maintain generation in the state and the customers’ ability to choose generation suppliers,” Akins said.
AEP has said it won’t build new gas plants in the state and would sell all its Ohio plants if the legislature is unable to come up with a solution. The Public Utilities Commission of Ohio had approved the earlier guaranteed-income proposal after almost two years of debate.
The company reported a quarterly profit of $502 million ($1.02/share), up from $430 million ($0.88/share) a year ago. It reported sales of $3.9 billion, up slightly from $3.8 billion. Akins said AEP’s focus on process improvement, cost discipline and capital allocation “gives us confidence that we can achieve operating earnings within our guidance range of $3.60 to $3.80 per share for 2016.”
AEP stock closed up at $69.30 Friday, an increase of 43 cents since the earnings announcement.
Negotiations with MISO over the exchange of day-ahead firm flow entitlements “are proving to be more difficult than originally expected,” SPP told FERC in its third informational report on the RTOs’ market-to-market coordination (ER13-1864).
The RTO said it continues to review MISO and PJM’s new day-ahead FFE exchange process and collect daily data from MISO. However, “SPP’s experience with the real-time market-to-market coordination procedures and the ensuing negotiations with MISO to try to improve those procedures has reinforced SPP’s belief that it would be premature to implement a day-ahead firm flow entitlement exchange process at this time,” it told the commission. (See “Regions Begin FFE Exchanges,” MISO/PJM Joint and Common Market Meeting Briefs.)
SPP said it was concerned about the potential impacts on its transmission congestion rights markets. “SPP needs to be reasonably certain that the firm flow entitlements being exchanged will result in equitable and efficient operational and settlement outcomes,” it said.
The RTOs have fared little better on implementing interface bus pricing, SPP said. It attended preliminary analysis presentations given by both MISO and PJM and discussed the issue separately with staff members of each RTO. The results, SPP said, make it unsure that the PJM-MISO seam is comparable with SPP and MISO’s.
Instead, SPP said, the RTOs are planning a study that would examine interface consistency, gaming opportunities, equity concerns and flow issues. The study is expected to begin in September and wrap up by the end of the year.
Despite the apparent lack of progress, SPP said it was interested in continuing its analysis of the MISO-PJM processes and working with both RTOs.
SPP’s informational reports were mandated by FERC in a January 2015 order. Reports are due every six months until the RTOs reach an agreement.
WILMINGTON, Del. — PJM needs to increase its fees to cover rising expenses and rebuild its diminishing operating reserve, officials told the Members Committee on Thursday.
Staff presented a first reading on five options for revising the administrative rate used to collect fees from members and market participants.
PJM is looking for member approval to increase the rates to $0.41/MWh of load served, up from the current $0.34/MWh. The options presented include a single change to a $0.41 rate, a 2.5% annual increase starting in 2018 through 2023 or an annual $0.01 increase through 2022. The 2017 rate in all options is $0.36/MWh.
A new method is necessary because PJM has been below its authorized operating reserve of $15 million since 2013. Staff had expected to rebuild the reserve to $17 million in 2015. Instead, it saw the reserve fall to $7 million because of lower-than-expected revenues. Although it trimmed expenses by $10 million below budget, to $273 million, it generated revenues of only $269 million.
PJM has changed the way it charges members and market participants several times over the past 20 years.
Before 1999, the RTO charged members a single formula rate based on load served. From then until May 2006, the RTO moved to multiple formula rates based on both load and market activity.
In 2006, PJM added a rider to cover the cost of the Advanced Control Center (AC2), and in 2011 it decreased service category rates by 3%, citing economies of scale. All proposals assume an early retirement of this rider because the debt attached to it will be paid off in September
The Finance Committee is expected to make a recommendation to the Members Committee and Board of Managers at its meeting Aug. 24.
CFO Suzanne Daugherty said she expected the committee to choose an option calling for a 2.5% annual increase from 2018 through 2023, which would restore the reserve to full funding by the end of 2017 and maintain it through 2026.
PJM will return to the Members Committee in September for an endorsement vote. It will then make a filing with FERC with a target effective date of Jan. 1.
(Editor’s Note: An earlier version of this story incorrectly stated that PJM’s expected administrative rate for 2017 will be $0.37/MWh.)
Grid Remains Strong During Recent Heat Wave
PJM canceled maintenance outages for the first time under Capacity Performance rules as the system experienced seven days of hot weather beginning July 21, Mike Bryson, vice president of operations, told the Markets and Reliability Committee on Thursday.
The peak load for the period — 151,882 MW — occurred July 25. That was the RTO’s 13th-highest ever and the highest since July 2011, when PJM set an all-time record of 165,492 MW.
The daily average LMP for July 25 was almost $36/MWh, Bryson said. Forced outages for the period were less than 13,000 MW.
“The transmission system has been very strong on the voltage side,” he said. During the period, however, two 765/345-kV transformers tripped in different parts of the system, causing local congestion.
The Dumont T2 line in Indiana tripped July 21, and the Cloverdale-Joshua Falls line in Virginia tripped July 26 because of storms, Bryson said.
PJM Moves Toward Order 825 Compliance Filing
The MRC approved a problem statement to begin work on compliance with FERC Order 825, which set new rules for RTO settlement intervals and shortage pricing triggers. Staff will begin work at the Aug. 10 Market Implementation Committee meeting to identify and address potential impacts. (See “Members Prepped for Problem Statement on Settlement Intervals, Shortage Pricing,” PJM Markets and Reliability and Members Committees Briefs.)
The order requires settling transactions in the same time intervals they are scheduled, priced or dispatched, along with aligning shortage pricing to work in the same intervals. While PJM already incorporates shortage pricing, staff realized the current system requires changes to ensure pricing signals aren’t unnecessarily erratic. The RTO’s problem statement goes beyond the requirements of the order to address these issues as well.
The original language of the final key work activity didn’t sit well with some participants, who were concerned it might open the door for revising the demand curves rather than simply adjusting the pricing intervals within them. The language was updated prior to approval to read: “Develop a new set of steps within the demand curves to be implemented in the final rule, if necessary.”
The debate went on for nearly an hour, leading PJM CEO Andy Ott to weigh in and assure members that the point was to avoid wild price fluctuations, not to adjust the overall rate structure.
PJM’s plan is to smooth out the pricing signals over time so they only trigger shortage pricing when it’s a trend.
“The look-ahead engine looks out over time, and it has to see the shortage for a persistent period of time before it will pass the indicator over to the [real-time schedule] engine,” PJM’s Rebecca Carroll said.
PJM has only had one incident of shortage pricing in recent memory, on Jan. 6-7, 2014.
Susan Bruce, who represents the PJM Industrial Customer Coalition, supported the focus on shortage pricing. Under the current demand curves, she said, consumers can be charged higher prices for a whole hour for a shortage that might last only five minutes.
Work on Fuel-Cost Policy Updates Moves Ahead
PJM market analysis manager Jeff Schmitt presented a timeline for the days remaining before the RTO’s Aug. 16 deadline for making a FERC compliance filing on its fuel-cost policy protocols.
The Market Implementation Committee held a special meeting on July 27 and has another scheduled for Aug. 4. Schmitt said he hopes to have the language updated prior to the committee’s regular meeting on Aug. 10. He asked that any additional feedback be sent to him.
In June, FERC ruled that PJM “lacks provisions for sufficient review of cost-based offers and could permit a resource to submit inaccurate cost-based offers.” It ordered PJM to add to its Tariff and Operating Agreement a requirement that generators submit fuel-cost policies that are approved by the RTO prior to submitting cost-based offers, including a penalty structure for those that file inaccurate information (ER16-372).
Feedback from the MIC meetings will be used to update PJM’s Manual 15. Schmitt said PJM has asked for a Dec. 1 effective date but that implementation of the new language will be based on when FERC responds.
MRC Endorses Manual Changes
Members unanimously approved the following manual changes:
Manual 29: Billing. Clarifications and updates are the result of a regular review.
Manual Changes Clarify ‘Physicality’ of Transactions
MRC members endorsed changes to Manual 18 clarifying the rights and responsibilities involved in auction-specific bilateral transactions. (See “Members OK Clarifications to Preserve ‘Physicality’ of Auction-Specific Bilateral Transactions,” PJM Market Implementation Committee Briefs.)
WILMINGTON, Del. — PJM stakeholders rejected a pair of dueling measures Thursday, leaving a new senior task force to decide whether to reconsider a formula key to calculating nonperformance penalties under the new Capacity Performance rules.
The sector-weighted votes capped more than an hour of heated discussion at the Markets and Reliability Committee that included allegations of political maneuvering and a call for one member to be sanctioned for “ad hominem attacks.”
The debate was sparked by the proposed charter of the Underperformance Risk Management Senior Task Force (URMSTF), an item that had been approved by lower committees with little to no discussion, despite months of controversy over the problem statement that created the group. (See PJM Generator Risk Proposal Faces Resistance.)
In recent task force meetings, however, some members had raised the question of whether the RTO was using an unrealistic number in figuring its performance assessment hour (PAH) charge rate. They worried it would artificially lower penalties in the new regime, under which generators are eligible for bonus payments and exposed to financial penalties depending on their performance. Lowering the penalties, some members argued, would weaken generators’ incentive to perform under the new market model.
Thus ensued speculation over whether such a discussion fell within the task force’s scope.
Calpine Offers Problem Statement
Fearing that the issue might be determined to be beyond the group’s mandate, David “Scarp” Scarpignato of Calpine brought a problem statement to the MRC to ensure the formula would be discussed somewhere.
“PJM had suggested that maybe it could be covered under the” task force, Scarp said. “I had indicated that I wasn’t sure that was the group to cover it because they seem intent on reducing the incentives for performance.”
According to the problem statement, informed by data from the Independent Market Monitor, “The current PAH number used in the denominator of the nonperformance charge rate does not reflect the expected number of PAHs as intended. The use of 30 hours is not adequately supported. The average of the RTO-wide PAH in the last three years was 14 hours, including the 30 hours in delivery year 2013-2014 that resulted primarily from January 2014, an outlier year.
“Too low of an expected PAH value avoids confronting capacity resources with the intended nonperformance disincentives under CP philosophy.”
The penalty nonperformance charge rate is the net cost of new entry ($/MW-day) multiplied by 365 days and divided by the 30-hour PAH value. Thus, if the value were reduced from 30 hours to 14, the penalties would more than double.
Scarp said that he had raised this issue at the last task force meeting.
“People talked at least five minutes about what’s in the scope and out of scope with this charter. There were varying opinions. People for the most part wanted to go past managing the risk and talk about the penalties you’d be exposed to. … If the group is looking at risk, it can’t be only one side, to make CP weaker.”
If the task force is limited to hedging risk, he said, its charter might as well be called the “reduce the CP effectiveness proposal.”
Incentives Key to CP
Dan Griffiths, executive director of the Consumer Advocates of PJM States, said it was important to guard performance incentives.
“If the incentives are, in fact, less, we feel like we are losing ground here,” he said. “That’s the only thing [consumers] got out of this — it’s in the interest of consumers to have strong incentives.
“You can’t quintuple the actual rate, but there is a discussion to be had here.”
Mitigating Risk for Generators
On the other side of the debate was Bob O’Connell on behalf of PPGI Fund A/B Development, who authored the problem statement that begat the task force. PPGI is the parent company of Mattawoman Energy, which is building a combined cycle plant near Brandywine, Md., in Prince George’s County.
O’Connell introduced the initiative in October, saying CP allows companies with multiple generators to offset poor performance with over-performing units but does not allow after-the-fact offsets, such as bilateral trades, that could help smaller generators. (See Generators Seek to Reopen PJM Capacity Performance Rules.)
At Thursday’s meeting, he proposed a motion to put off reassessing the PAH charge rate formula until after PJM has submitted an annual informational filing mandated by FERC in approving the charge rate. It was seconded by Jason Cox of Dynegy.
Countered Scarp: “Putting this off into limbo is a terrible thing to do to a fellow stakeholder, and something I have never done.” He accused O’Connell of using “procedural moves to prevent voting on this order” and being “disingenuous,” which elicited a call from O’Connell to have him sanctioned for “ad hominem attacks.” Committee Chair Suzanne Daugherty did not formally act on his request.
Breaking a Rule of Thumb
Indeed, most members prefaced their comments by saying as a rule of thumb, they do not oppose problem statements. It’s highly unusual for them to be rejected.
But after O’Connell’s measure failed with slightly less than 49% approval, members also voted down the Calpine problem statement, which was endorsed by slightly more than 44% of the votes.
Members subsequently approved the task force charter by acclimation.
The votes cut across sector lines, with generators split on the issue but more favoring O’Connell’s motion. The only sector to unanimously support Calpine’s initiative was the End-Use Customers (albeit with one abstention).
Jason Barker of Exelon had provided the “second” needed for a vote on the problem statement.
“The data shows quite strongly that 30 hours … is vastly overstated,” Barker said.
He joined Scarp in criticizing his colleagues for “procedural shenanigans and weak arguments” and encouraged them to put aside politics, saying that no one got everything they wanted out of the CP construct. “Let’s be honest around the table,” he said.
FERC Has Spoken
Some members said they were hesitant to revisit the issue because FERC had approved the charge rate using the 30 PAH hours.
Although the commission approved the 30-hour proposal as a “reasonable approximation of the upper bound” of hours during which PJM is likely to experience emergency actions, it also required the RTO to submit informational filings for five years evaluating the impact of the 30-hour assumption on resource performance. “We also encourage PJM, as it gains more experience under its new capacity construct, to reassess the assumed number of performance assessment hours and file with the commission if it believes a revision is warranted,” the commission said.
Scarp noted that FERC’s order hasn’t stopped stakeholders from questioning other aspects of the ruling, including operating parameters and seasonal capacity. The 30 hours, he said, is an error.
Carl Johnson, of the PJM Public Power Coalition, said, “We do not like to oppose a problem statement — that’s how we got to move forward with the URMSTF and seasonal capacity. But in this particular case, we’re talking about something so specific that FERC gave us a directive on.”
He referenced PJM’s recent experience spending months hammering out consensus on a ramp rate for the CP product, only to have FERC reject it.
“I’m not inclined to use our time on this,” he said. “I don’t want to spend time taking things to them that aren’t going to go anywhere.”
Susan Bruce, of the Industrial Customer Coalition, agreed that the charge rate was a core issue of CP, but she said it was just one and hesitated to approve re-evaluating it without looking at others.
“If you say we can’t talk about those other components, I think it’s a conversation to be had in a vacuum,” she said.
Scarp responded, “If you think that there are other numbers that are incorrect, I’m happy to look at them. I am not redesigning CP in any way. I’m probably one of the few people in the room who has never tried to redesign CP.”
