LITTLE ROCK, Ark. — Industry representatives and those that regulate or work with them gathered here last week to discuss the Clean Power Plan and its implications — primarily near-term uncertainty — for the industry.
Regional compliance or state-by-state? Mass based or rate based? Comply or resist?
One certainty, as FERC Commissioner Colette Honorable joked, is that the Clean Power Plan is “a job-security act for lawyers.”
Nancy Lange (Minn PUC), Andy Kellen (WPPI), Scott Weaver (AEP), Sandy Byrd (AECC) and Pam Kiely (EDF) at the Great Plains CPP Seminar.
More seriously, Honorable said, “I do believe it’s important to hear from all the parties.”
Three panels of industry insiders did just that during a seminar organized by the Great Plains Institute and the Bipartisan Policy Center, focused on the Clean Power Plan’s impact on the midcontinent states.
“It was a very useful day. We spent time on the same issues we’re thinking about right now in Iowa,” said Amy Christensen, an administrative law judge with the Iowa Utilities Board. “We’re living and breathing this right now. It’s helpful to hear other speakers talk about the same issues.”
‘Common Currency’
Ted Thomas, chairman of the Arkansas Public Service Commission, told RTO Insider he was particularly struck by comments from PJM Senior Economic Policy Advisor Paul Sotkiewicz on the rate- vs. mass-based issue and use of gas plants.
A rate-based plan caps the emissions of a state’s power fleet based on an average (CO2 tons/MWh). A mass-based plan caps the total tons of carbon the power sector can emit each year.
“With a mass-based program … you can bring in new gas units and set aside the allowances,” Sotkiewicz explained.
“The thing to me that needs more study is [Sotkiewicz’] thought that mass-based is more accommodating than rate-based, because you can’t use new gas units to manage down your rates,” Thomas said. “The rate[-based] stuff is so complicated. With mass, it’s just tons of emissions. You already have a common currency.”
“Under an emissions-rate regime, new gas [units] can’t be brought in. So why go with an emissions rate if you’re a coal-heavy state?” asked MISO’s Kari Bennett. “With mass-based, you can retire older units and bring in newer ones. It’s easier to facilitate load growth with mass-based approaches.”
Nancy Lange of the Minnesota Public Utilities Commission took a different viewpoint. “I don’t know of any states that have done enough analysis to show one [mass- or rate-based] is more preferable than the other,” she said.
Both MISO and SPP say the mass-based approach would make regional compliance, with trading of emission credits, easier to administer, helping coal-reliant states. SPP released a study in July that indicated a state-by-state compliance approach could result in nearly 40% higher costs than a regional approach.
“The prudent thing is to look at regional compliance,” Honorable said, citing the SPP study.
Costs
“If we’re going to be retiring a significant portion of the nation’s coal fleet, the only substantial winner will be natural gas,” said the Arkansas Electric Cooperative Corp.’s Sandy Byrd, vice president of public affairs and member services. “If there’s going to be a dash for gas, we’ll be building more combined cycles, transmission infrastructure … there will be a huge cost coming that wouldn’t be without the CPP. We need to ensure the consumers know it’s going to happen.”
Jim Hunter, representing the International Brotherhood of Electrical Workers, agreed with Byrd. “We’re betting on gas,” he said, “but when the price goes up — and it will — the price of electricity is going up, too.”
Leakage
The panels also discussed “leakage” and its implications on adding new generation.
The Clean Power Plan covers generators that began construction on or before Jan. 8, 2014. Plants built after then are subject to EPA’s new source performance standard, which limits carbon emissions to 1,000 lbs/MWh for new baseload gas-fired units, versus the 771-pound limit for existing gas plants.
For a state that adopted rate-based compliance but shifts added new plants, the mass-based limit would no longer be equal to the original emission-rate limit.
“It’s a fuzzy concept, as described by the EPA,” said Scott Weaver, manager of strategic analysis for American Electric Power. “I think it’s flawed. The [emission] rates for [new] gas units are less stringent, so you’re shifting emissions from existing units to new units.”
States must decide whether to pursue rate-based or mass-based plans by September 2016. (States can also ask for a two-year extension at that time.)
States that decide not to comply with the Clean Power Plan or submit inadequate plans will be subject to a federal plan.
“State plans make a lot of sense,” Lange said. “It’s important to have the flexibility of a state plan, given states want the control and to maintain flexibility on how a state should comply with the rule.”
LITTLE ROCK, Ark. — MISO’s Board of Directors voted last week to switch to a quarterly meeting schedule from its current every-other-month calendar, a change likely to also be adopted by the Advisory Committee.
The changes are the first to result from the RTO’s stakeholder process redesign, which is also expected to result in a reduction in the number of committees.
The board voted unanimously Thursday to switch to four open board meetings, with two strategic planning meetings scheduled in the summer and fall.
“The idea of going to four meetings is to get all of our obligations met. I think it’ll be a really productive way to move forward,” MISO CEO John Bear said.
Too Few?
However, board member Michael Evans said that the quarterly meeting schedule could be too little given the multitude of issues facing MISO.
“We’ve got a lot of balls in the air, a lot of moving parts,” Evans said. “If you miss one [meeting] it means you’re six months in between meetings. I’m concerned about losing the relationships between board meetings and losing continuity on the issues. I think we ought to let that percolate a little bit.”
Board member Thomas Rainwater said less frequent meetings would challenge the board to do more work between meetings and put the onus on the board members to work harder individually. He added that he couldn’t urge the Advisory Committee to meet less if he wasn’t willing to apply that to the board.
“I’m pleased to see the diversity of opinion on the board. I can be persuaded either way. I look at this as four governance meetings … and two really deep dive strategic meetings,” Rainwater said.
Despite Evans’ concerns, the new schedule passed without objection.
The board’s vote came a day after the Advisory Committee discussed — but took no action on — making a similar change.
Advisory Committee Chairman Gary Mathis said the committee should follow the board’s meeting schedule.
“We should continue meeting this way, face-to-face whenever the board meets,” he said. “If the board is considering changing their schedule, then we should follow suit. I think it’s important to match those up. As they go, we should go too.”
Streamlining the Organizational Chart
The Advisory Committee also discussed the stakeholder redesign. At the third redesign workshop in September, stakeholders tentatively identified eight committees that would be eliminated, with their duties assigned to other panels (see organizational chart). MISO’s straw proposal called for eliminating 10 committees.
Board members suggested that stakeholders’ simplified redesign might be in need of further simplification.
Board Chairman Judy Walsh urged the stakeholder process redesign team to combine some of their six desired outcomes. “If you have more than three priorities, you have none at all,” Walsh said.
Rainwater echoed Walsh’s advice to focus on three top priorities. “Let’s start with some small victories,” he said.
Board member Baljit “Bal” Dail asked that the stakeholder planning team respect the role of the board versus the role of management in creating the organizational model. He said sometimes stakeholders bring “hot topic” issues before the board that are better handled by MISO management.
“The board takes a ‘noses in, fingers out’ approach,” Dail told them.
Michigan Public Service Commissioner Sally Talberg said more discussion was needed on whether stakeholders should focus on high-level issues versus specifics that can quickly become complex and warrant multiple meetings. She added that MISO’s 2,000-page Tariff can lead to “endless tinkering.”
MISO stakeholders will develop final recommendations at a fourth workshop Nov. 3. The final proposal for redesign will go before the Advisory Committee on Dec. 9.
LITTLE ROCK, Ark. — MISO is cool and collected heading into the winter, staff told the Markets Committee of the Board of Directors on Wednesday.
Todd Ramey, vice president for system operations and market services, said the RTO has 146 GW of capacity available to serve the estimated winter peak of 104 GW.
The RTO was able to meet its all-time winter peak of 109.3 GW during the polar vortex on Jan 6, 2014, without directing any demand reductions.
Since then, MISO has taken steps to improve gas-electric coordination and provide more transparency on fuel supplies.
Ramey said MISO is looking into putting other winter readiness measures into place, including emergency pricing and seasonal assessments of resource adequacy. Last year, MISO won FERC approval to create two capability products to manage short-term variations in load. MISO hopes to implement the products in 2016.
WASHINGTON — MISO officials asked FERC staff last week to trust in its stakeholder process and not force capacity market changes that could increase exports, while the RTO’s Market Monitor and other critics called for the commission to force reforms.
FERC staff’s daylong technical conference on MISO’s capacity market — called in response to complaints by Illinois officials, industrial energy users and a consumer group — was dominated by technical discussions on zonal boundaries, capacity import limits and reference levels. But MISO’s stakeholder process also came under scrutiny.
MISO Market Monitor David Patton suggested only a FERC order would prompt the RTO to switch from a vertical to a sloped demand curve.
“For any change that involves large economic value, the stakeholder process can bog down,” Patton said. “And that’s definitely the case with the sloped demand curve.”
Patton suggested a FERC mandate — such as its 2014 order requiring a sloped curve in ISO-NE — might be necessary to prompt change.
“That reorients the stakeholders’ discussion. Folks who were obstructionist become part of the process of discussing how to implement something that would be effective and produce reasonable outcomes,” he said. “So while there is a stakeholder process [on capacity issues], the most important issues are not part of those discussions.”
‘Robust Stakeholder Process’
Patton’s comments came after MISO officials Renuka Chatterjee, executive director of interconnection planning and resource adequacy, and Jeff Bladen, executive director of market design, asked the commission to exercise caution.
Bladen said the commission shouldn’t take any actions that increase the number of MISO-based generators selling capacity into PJM.
Chatterjee said the RTO already plans to make two changes before its 2016 Planning Resource Auction. She asked the commission to allow MISO’s “robust stakeholder process” to develop long-term solutions.
That brought a retort from Tyson Slocum, director of Public Citizen’s Energy Program, who said the RTO’s stakeholder process “is heavily dominated by a few interests and … not reflective of broader stakeholders.”
The commission announced the technical conference Oct. 1 in response to complaints by Public Citizen, Illinois Attorney General Lisa Madigan, Southwestern Electric Cooperative and Illinois industrial energy consumers over MISO’s 2015 PRA in April. The auction saw a nine-fold price increase in Zone 4, which comprises much of Illinois.
FERC said the conference would help it “determine what further action, if any, may be appropriate” to address the complaints (EL15-70, et al).
At the same time, FERC announced a non-public investigation into “whether market manipulation or other potential violations of commission orders, rules and regulations occurred before or during the auction” (IN15-10). (See FERC Launches Probe into MISO Capacity Auction.)
Public Citizen called for an investigation in May into whether Dynegy improperly withheld capacity in Zone 4, an allegation the company has denied. Public Citizen also alleged that MISO brushed aside recommendations by its staff that Zones 4 and 5 be merged due to their concerns about Dynegy’s growing share of capacity in Zone 4 after the company acquired four generators there from Ameren.
Madigan’s complaint said that Dynegy’s increased generation portfolio in Zone 4 made it a “pivotal supplier” in the zone. Madigan also complained that in approving the Dynegy acquisition, FERC declined to look at its effect on competition and prices in Zone 4 and instead only considered a competitive analysis of MISO as a whole.
Lost Opportunity Costs
The April auction saw prices in Zone 4 clear at $150/MW-day, compared with just $16.75 a year earlier.
Dynegy said the results were consistent with its opportunity costs, which Patton had calculated at $155.79/MW-day, reflecting its ability to sell capacity into PJM. The company noted that a PJM Incremental Auction cleared at $163/MW-day less than a month before MISO’s auction. (See Dynegy: No Evidence of Misconduct in Auction.)
MISO relies on the estimated opportunity cost of exporting capacity to a neighboring region in setting the initial “reference level” — a benchmark it uses for identifying economic withholding.
In a complaint June 30, the Illinois Industrial Energy Consumers argued that PJM’s capacity costs should be not be used in setting the reference level because PJM can only accommodate a limited amount of uncommitted MISO capacity (EL15-82).
Representing the industrials, attorney Robert Weishaar told the hearing that the method MISO uses to calculate lost opportunity costs should be changed, saying the RTO’s current practice doesn’t comply with FERC’s requirement, “which is they must be legitimate and verifiable.”
Weishaar said the reference level should be set to zero pending MISO’s development of a new standard that is compliant.
“The other option is for the commission to get very prescriptive about how the LOC provisions of the Tariff should be applied to take into account such things as whether there is excess capacity within the zone; what is the available transfer capacity; what are realistic options for selling into neighboring regions,” he said.
In response to questions from staff, Patton opposed the use of a zero reference level. Patton and consultant Roy Shanker, speaking on behalf of the Electric Power Supply Association, also opposed using estimated going-forward costs by resource type in setting the reference level.
“It’s a suspension of reality,” Shanker said. “You should definitely not do it.”
Weishaar said MISO also should reflect counterflows in the calculation of local clearing requirements.
He said the two changes should be made in time for the 2016 PRA. “What we’ve learned today is that there is a high-level imprecision in the existing Tariff provisions and that some change needs to be made on both of those issues. Our view is both of those issues need to be addressed in the next six to eight months.”
Henry D. Jones, executive vice president and chief commercial officer for Dynegy, joined Patton in calling for MISO to adopt a sloped demand curve.
“The vertical demand curve construct suggests that any megawatts over the planning reserve margin receive zero capacity dollars,” he said. “… Any capacity that’s not going to clear is going to be an [independent power producer] in Zone 4 and that’s not a sustainable model in terms of a capital investment in existing assets or attracting investment for new build.”
Patton said MISO’s current method separates “the representation of demand from reliability,” making it impossible to “get a market outcome that is going to produce just and reasonable prices.”
Under current rules, the last megawatt needed to meet the requirements is “worth a ton. You go one megawatt further, that megawatt is worth nothing. But if you do any sort of loss-of-load expectation — any conventional reliability analysis — it would tell you those two megawatts are delivering almost the same reliability value,” Patton said.
Jones acknowledged that such a change would face opposition from MISO’s traditionally regulated states. “I think it’s a fight worth having,” he said.
Jones also said that while MISO’s traditionally regulated states can ensure construction of new generation, Illinois — a retail choice state that does not use integrated resource planning — could find itself deserted.
“The concern we have is that over a very short period of time assets will retire or become less reliable in Southern Illinois and they will be replaced in surrounding states in [the] regulated rate base. And the southern part of Illinois will wake up with less capacity and an aging coal and nuclear fleet that’s being replaced in other states, where jobs and tax base are being shifted.”
Jones also argued that MISO should implement a minimum offer price rule (MOPR) and change its auction schedule. “It’s truly nonsensical to imagine that people can plan with an auction that occurs eight weeks before the planning year,” he said. “We need more lead time if we’re going to be thoughtful about this and provide incentive for capital expenditure and/or new build. There needs to be a longer runway for that.”
‘Swiss Cheese’ Effect
In addition to reiterating his call for a change in the demand curve, Patton said MISO also needs to “rationalize how capacity is delivered in real time.” He said MISO is being hampered by PJM’s requirement that capacity resources serving it from outside its footprint be pseudo-tied.
The PJM requirement is “creating effectively a Swiss cheese effect, where they’re taking dispatch control over units that are critical to control constraints that they don’t see in their model — and that demonstrably harms reliability,” he said.
Patton said PJM’s requirement should be replaced with operating procedures in which MISO guarantees delivery of the energy PJM has purchased “so that they [PJM] have what they need without having to effectively reconfigure the RTOs in ways that are really hard to undo from an efficiency standpoint.”
The change would help PJM’s reliability as well, Patton said.
“If MISO’s delivering energy on a firm basis, they’ll dispatch around constraints, whereas [under current procedures] a particular resource — if it hits a constraint — may have to be curtailed.”
Patton wasn’t optimistic that the two RTOs would reach agreement any time soon, however. “It’s going to take time, if my experience is a guide. To get PJM and MISO to agree on something takes a long time.”
MISO: Changes Planned
MISO’s Chatterjee said the RTO expects to make changes in time for the 2016 PRA regarding how it treats generation retirements and suspensions and how it allocates zonal deliverability benefits.
She said MISO staff will be attending a Nov. 19 conference with the Illinois Commerce Commission to hear more about the state’s concerns.
“’What problem are we trying to solve?’ is an important question to ask ourselves,” she said.
Slocum
Bladen said FERC should not eliminate MISO’s opportunity cost provisions, which he said would mean that generators could “capture the opportunity cost in PJM — or the equivalent value of the opportunity in PJM — only by exporting to PJM.”
FERC will take post-hearing comments until Nov. 4. It has set no timeline for possible actions resulting from the inquiry.
In the meantime, MISO’s executive team is withholding comments on the issue, Clair Moeller told stakeholders at its Oct. 20 Informational Forum.
“What you’ll see [MISO] do is take a breath. We think it’s prudent for us to wait to see how FERC’s action on the section 206 complaints play out,” said Moeller, MISO executive vice president of transmission and technology.
Criticism of FERC Response
Public Citizen’s Slocum said he was frustrated that the conference, which was run by staff from FERC’s offices of General Counsel, Energy Market Regulation and Energy Policy and Innovation, failed to resolve some factual issues. (Commissioner Cheryl LaFleur attended part of the afternoon session.)
“The technical conference structure does not appear to be resolving these disputes effectively,” Slocum said. “This morning on the first panel, I [heard] a number of folks from MISO and Dr. Patton say, ‘I didn’t have that table in front of me,’ ‘I don’t have that data,’ ‘I didn’t bring those numbers,’ ‘I don’t have the specific numbers,’ ‘I don’t have the numbers,’ in response to repeated questions from FERC staff on subjects that were given to us ahead of time.”
“What this shows is that this is not an adequate structure to resolve these disputed claims,” he said. “The only adequate structure is an evidentiary hearing, which multiple parties called for.”
The R.E. Ginna nuclear plant and Rochester Gas & Electric have reached an agreement to provide a financial lifeline for the plant through March 2017, 18 months earlier than originally proposed.
The plant’s owner states in an analysis included in the filing that the plant will not be financially viable when the agreement ends.
Under a joint proposal filed late Wednesday with the New York Public Service Commission and FERC, the new reliability support services agreement would end March 31, 2017 (14-E-0270) (ER15-1047). An earlier agreement between Exelon subsidiary Constellation Energy Nuclear Group and RG&E — which was ordered by the PSC but rejected by FERC — ran until Sept. 30, 2018.
Payments to Ginna would not start until FERC approves the agreement, the settlement says.
Ginna’s Market Prospects Dim
The agreement calls for RG&E to apply up to $110 million in existing customer credits toward the costs of the RSSA. Ratepayers will be on the hook for a $2.25 million monthly surcharge beginning Jan. 1, 2016, through at least June 30, 2017. If the customer credits are insufficient to cover the cost of the agreement, the surcharge will continue until the balance is paid off.
Those payments may continue after the plant is shut down.
“Based upon my review of Ginna’s projected operating costs for the 18-month period starting after the RSSA expires and my calculation of how much market prices must increase before Ginna’s re-entry into the market would become economic, it appears highly unlikely that there will be an incentive for Ginna to return to the market after RSSA termination,” Jeanne M. Jones, vice president of nuclear finance for Exelon and CFO of CENG, wrote in an affidavit.
The plant’s prospects are dim because forecasted market prices are lower than a baseline the company set in a 2014 analysis, and insufficient to cover the plant’s operating costs, Jones said. The conclusion of the RSSA also coincides with the need for an 18-month refueling, further weakening the plant’s financial outlook.
The new RSSA retains financial disincentives in the earlier agreement to prevent the plant from toggling between the RSSA and market payments. This mechanism, the capital recovery balance, required Ginna to pay back a portion of RSSA earnings if it reentered the market. In the new agreement, this $20.1 million would have to be repaid in two years, down from the original six or seven years.
The settlement also calls for commissioning a new reliability study by NYISO to determine if RG&E’s proposed transmission alternative is adequate to replace Ginna. A 2014 RG&E-NYISO study concluded the plant would be needed to maintain reliability into 2018.
However, RG&E changed its planning proposal from its Rochester area reliability plan (RARP) to the Ginna retirement transmission alternative (GRTA), which will be completed sooner. The RARP is a $250 million project that includes new transmission lines and new and rebuilt substations, intended to address bottlenecks, with only some components applicable to the loss of Ginna. That project will be phased in, with its completion date extended from 2018 to 2020.
The GRTA is a $150 million project that was devised to access power from other sources and includes some elements of the RARP. It diverts some of the equipment originally intended for the larger project and is expected to be completed before the RSSA expires, RG&E spokesman John Carroll said.
An Improved Deal
The agreement has been endorsed by PSC staff, the New York Utility Intervention Unit and several intervenors. Entergy Nuclear and NRG Energy, which opposed the earlier agreement, said they will not oppose it. Environmental groups oppose the deal while acknowledging it is an improvement over the original proposal.
“The proposed agreement fails to protect consumers and the environment on two accounts. First, the burden for RG&E’s bad planning is being put completely on customers,” said the Alliance for a Green Economy and Citizens’ Environmental Coalition. “Even though RG&E had ample warning since early 2013 of Ginna’s financial challenges, the utility did nothing for a year and half to get alternatives lined up to replace Ginna. The utility’s failure to act proactively will now cost its customers millions of dollars a year, yet RG&E’s shareholders will pay nothing toward the costs of the subsidy.
“Second, the agreement contains no commitments from Constellation in regards to responsibly decommissioning the Ginna reactor. Since closure is imminent, it’s critically important for New York’s leadership to get an agreement from the owners that it will begin an immediate, careful and thorough decommissioning process upon shutting down Ginna,” the groups continued.
The PSC and FERC said decommissioning is outside the scope of this proceeding.
Ratepayers will see slightly higher bills than they have been paying. An average customer would see a monthly increase of $2.20, Carroll said. However, customers have already been paying an extra $1.85 since Sept. 1 under a PSC order that authorized a surcharge to mitigate rate compression. In effect, the average customer will pay an additional 35 cents per month. (See NYPSC Approves 5.2% Ginna Rate Surcharge.)
The earlier agreement called for payments to the plant of $17.5 million per month, subject to some adjustments. FERC rejected that agreement in part and directed settlement proceedings that culminated in this week’s agreement. The new agreement would pay Ginna $15.4 million per month.
Other terms of the agreement include:
Ginna’s share of revenues from sales into the NYISO energy and capacity markets would be doubled to 30% from the current 15%.
The settlement cap for Ginna’s full cost of service has been set at $510 million, with a floor of $425 million.
Ginna will not seek a reliability-must-run agreement from FERC.
Ginna spokesman Maria Hudson said the plant owners are still looking for a long-term solution.
“While we are pleased that the negotiated RSSA will allow Ginna to continue powering the grid and the local economy until 2017, it’s only a temporary solution to a long-term problem,” she said. “Single-unit nuclear facilities like Ginna face significant economic challenges brought on by poor market conditions and a lack of energy policies that properly value the clean and reliable energy that nuclear provides.”
If the latest ISO and RG&E reliability study shows Ginna’s energy is needed beyond 2017, it will bid in to the state’s capacity auction in 2017.
Market participants in New York are concerned that their proprietary information might not be adequately protected as NYISO plans to bring the RTO’s reporting system for renewable energy generation into compliance with state law.
The New York State Energy Research and Development Authority (NYSERDA), which procures clean energy, was required by a 2012 law to develop the Generating Attribute Tracking System to ensure compliance with the state’s renewable portfolio standard.
Generators’ representatives raised concerns Wednesday when the NYISO Business Issues Committee discussed a proposed change in the ISO’s code of conduct that states the information would be confidential and that market participants will be notified of any requests for confidential data or any decision to disclose it.
The discussion came as New York Assemblyman James Brennan is petitioning the Public Service Commission to force disclosure of bidding information from power generators that they say is proprietary and threatens to disrupt the market if not protected. The PSC and the secretary of the state’s Department of Public Service last year dismissed a similar request under the state’s Freedom of Information Law. (See NYPSC Chair Zibelman Acknowledges Costs Concerns.)
Market participants fear that if the proprietary information from the traditional generators is disclosed, by either the PSC or by the courts following any legal action that the assemblyman may initiate, GATS information would be released as well.
“There’s a lot of concern about the release of information that everybody agrees is confidential,” said Howard Fromer, who represents PSEG Long Island.
NYISO would provide data on megawatts produced and consumed and on import and export transactions. No financial data on settlements and revenue would be included.
No trading is available in the self-contained New York renewable energy market, which officials said Gov. Andrew Cuomo wants to change. Renewable energy certificates (RECs) are traded in the neighboring jurisdictions of ISO-NE and PJM.
NYISO is negotiating an agreement with NYSERDA’s vendor, APX, which will keep data confidential except for identified purposes, NYISO said. APX runs several REC registries, including those in Michigan, North Carolina and New England.
Peter Keane, NYSERDA’s deputy general counsel, said that since the New York portfolio standard was set in 2004, only one request for private information has been made. That involved a dispute over lease payments between a property owner and the owner of wind turbines at the owner’s site. The dispute was resolved before a decision had to be made on the release of the information.
The proposed code of conduct change moves to the ISO’s Management Committee at the end of the month. GATS is expected to be publicly available in March.
The PJM Board of Managers last week directed staff to seek FERC approval for a package of rule changes related to financial transmission rights (FTRs) and auction revenue rights (ARRs) after the Members Committee nearly reached consensus on the proposal.
“In making this decision, the board took into account the near two-thirds consensus achieved through the stakeholder process,” PJM said in a release. “It also considered the need to address the equity issues associated with the current rules by which the transmission system is planned to ensure future feasibility of Stage 1A ARRs and revenue inadequacy is allocated among holders of both positively and negatively valued FTRs.”
The RTO said the filing would be made shortly, and FERC would be asked to take action by the end of the year to provide adequate notice prior to the 2016 annual ARR allocation and FTR auction.
The rule changes, proposed by Old Dominion Electric Cooperative, would redesign the FTR and ARR processes, combining recommendations from PJM and the Independent Market Monitor.
In August, the MC fell just short of a sector-weighted consensus on the proposal, which was backed by most members of the End Use Customer, Transmission Owner and Electric Distributor sectors but won support of only one-third of the Generation Owner and Other Supplier sectors. (See ODEC Seeks Last-Ditch Vote on Deadlocked FTR/ARR Issue.)
The plan contains three elements.
One, drawn from a PJM staff proposal regarding the Stage 1A 10-year process, escalates the current ARR results using a zonal load forecast growth rate of +1.5%. The other two elements change the method of reporting the monthly payout ratio so that any negative target allocations are included as revenue, slightly increasing the reported payout ratio. It also treats each FTR individually, eliminating the netting of positively and negatively valued FTR positions in a portfolio prior to determining positively valued FTR payout ratios.
LITTLE ROCK, Ark. — Lubbock Power & Light’s recent announcement it was planning to take 400 MW of SPP load and join ERCOT hung heavy over the Strategic Planning Committee last week as it tried to determine what to do next.
Golden Spread Electric Cooperative’s Mike Wise, the SPC chair, teed up the issue by asking whether SPP staff should conduct a transmission study of the area to determine whether LP&L’s departure would result in stranded investment.
“Transmission is built for and paid for by everybody,” Wise said. “Will there be transmission infrastructure out there that wouldn’t be needed if LP&L leaves?”
“I can tell you no facilities were built just for Lubbock,” said Bill Grant of Xcel Energy, which currently provides all of the city’s energy (forecast to be 626 MW in 2019) through its Southwestern Public Service subsidiary.
Effective June 1, 2019, when LP&L will also begin receiving power as a member of ERCOT, Xcel will provide only 170 MW of Lubbock’s needs.
“What led to this, and what can we do about it? Will this be the first time or the last time it happens?” Grant asked.
SPP Director Harry Skilton echoed Grant, expressing a need to “understand [LP&L’s] motivation and whether we should be doing something to alleviate whatever incentive they had for moving.”
“Prices in the ERCOT area are lower than SPP’s. We can debate whether that’s temporary or not,” said Carl Monroe, SPP’s executive vice president and COO. “The second issue is we have a capacity-margin requirement, and ERCOT doesn’t.”
“Load will come and go. Businesses move from one location to another,” said Dogwood Energy’s Rob Janssen. “Let’s face it … ERCOT built transmission lines in West Texas that overlap with SPP’s, so some customers in the area have a choice as to which system to be on.”
Monroe said SPP has no withdrawal fees to discourage load from leaving the RTO. “The only withdrawal provisions we have today are for withdrawn transmission, not load.”
SPP Vice President of Engineering Lanny Nickell said SPP could run studies of the areas. He also said SPS, which has owned the transmission interconnection with LP&L since 1983, could also request re-evaluations of notifications-to-construct to determine whether planned projects are still needed.
Asked whether any projects with NTCs in the area might be affected by the withdrawal of LP&L’s load, Nickell said he “was not aware of any projects directly impacted by Lubbock leaving.”
Grant said Xcel has identified a couple of impacts on its radar screen, and it will “take a closer look when the projects get close to breaking ground.” But he cautioned that the committee might be getting ahead of itself, pointing out LP&L has only announced its intent to join ERCOT and that the Texas grid still must conduct a feasibility study.
“We’ll know when the studies are done … we’ll know way before June ’18,” he said, referring to LP&L and ERCOT’s final decision date. “We’ll know in time what we need to reflect in our own models.”
In the meantime, SPS has filed a Freedom of Information Act request to obtain LP&L’s feasibility study, Grant said.
“We have no idea what numbers they came up with, or how they came up with the numbers, or whether they’re feasible,” he said.
The New York Public Service Commission on Thursday temporarily lifted caps on the amount of net-metered solar energy that can be permitted on a utility system. The move was prompted by a July petition from Orange and Rockland Utilities seeking to suspend its net-metered installations because it had applications for interconnections that exceeded the limit it can accommodate under current state rules.
While the petition came from ORU, the commission ruled that all six investor-owned utilities in New York must file tariff revisions to the rules governing their net-metering caps by Oct. 30, which will become effective Nov. 6.
Under the state’s 6% cap, ORU said it would reach its 62-MW limit in the “near future” and should immediately be allowed to suspend interconnections at that time.
The commission, however, rejected ORU’s proposal for a “buy-all, sell-all” solution whereby a distributed-generation customer would sell all its generation output at a wholesale rate and purchase all the electricity it needs at the retail rate.
The PSC said the ceiling would float upward to accommodate all new applications until the commission can answer a key question: How much are distributed energy resources worth? That answer is expected by the end of next year, under New York’s Reforming the Energy Vision initiative (15-E-0407).
“Rather than engaging in another effort to arrive at the proper level of the ceiling that would anticipate perfect coordination with the implementation of REV, the ceilings shall be allowed to float in the interim until the calculation … affecting valuation of DER is decided,” the commission wrote. “That is, utilities shall accept all interconnection applications and continue to interconnect net metered generation without measuring the DG capacity against an artificially set ceiling level.”
The order said state law gave the commission discretion to adjust the caps in the current scenario. It also said momentum to attain the state’s clean energy goals need not be interrupted now. “The pace of development should be set by the NY-Sun program and other policies for promoting net metered generation, not by the level of the ceilings,” the order said. NY-Sun is Gov. Andrew Cuomo’s effort to spend $1 billion by 2023 to install 3 GW of solar generation.
Much of the commission’s discussion centered on whether lifting the cap may create a “gold rush” for residents who want to install rooftop solar.
To Commissioner Diane Burman, who opposed the move, the interim approach will entice potential customers to rush into the interconnection queue to reserve a place and be grandfathered into the system at the time the PSC determines what the cap ultimately should be.
“I don’t see what we’re doing today as helpful over the long term,” she said.
Commission Chair Audrey Zibelman said setting a higher hard cap now would have a similar negative effect, with residents hurrying to reserve a place in the queue before they are cut off when a utility’s limit is reached, creating a stop-and-go scenario for the industry.
“We have a burgeoning solar industry, and we must not allow the caps to become a barrier,” she said.
This is the second time in less than a year the commission has had to address the cap when a utility approached its limit. Last December the commission doubled the statewide cap from 3% to 6% when environmentalists and Central Hudson Gas & Electric petitioned regulators for an increase. (See New York Doubles Solar Net Metering Cap to 6%.)
MISO’s latest Order 1000 compliance filing — which revises the developer selection process and outlines a pro forma selected developer agreement (SDA) — has drawn criticism from developers and transmission owners seeking additional changes (ER15-2657).
MISO’s proposed Tariff changes, filed Sept. 16, include relaxing deadlines and participation requirements for the annual transmission developer qualification process to allow for “broader participation” in the competitive developer qualification and selection model. MISO prequalified 35 developers to bid on competitive transmission projects in 2014. This year, the RTO added 13 more developers.
Transource Energy, however, said that the changes to the selection process unreasonably grant MISO too much authority in transmission projects and their cost. The company said that under the revisions, MISO is allowed to unilaterally terminate developers’ SDAs and force them to bear the costs. Transource also accused the RTO of ignoring its feedback in the stakeholder process.
Similarly, Xcel Energy said that some of the changes “inappropriately expand the role of MISO.” For example, the company said, selected developers would be required to self-report any “potential violations” of federal or state law to MISO.
In a joint filing, International Transmission Co., Michigan Electric Transmission and ITC Midwest took issue with the requirement that developers submit projected revenue requirement information. This provision “could negatively impact an existing transmission owner’s ability to submit competitive bids because two developers with the same estimated costs will calculate different revenue requirements if one developer already has [a] plant in service in MISO.”
Little Rock-based Republic Transmission accused MISO of overlooking its duty to protect ratepayers in the interest of saving money for the RTO. The company said MISO ignored suggestions from stakeholders and provisions designed to cap or minimize the costs of projects in CAISO and PJM.
“MISO does not propose to ‘improve’ its developer selection process in a manner that protects MISO ratepayers by shifting its current minimal selection focus on cost to more heavily rely on the cost components of bids,” asserted Republic Transmission in its protest filing. “Much work remains in MISO for ratepayers to benefit from Order No. 1000.”
MISO seeks to implement the changes by Nov. 16, with the aim of posting its first competitive transmission project for bidding in January. Technically, MISO’s compliance obligations to meet Order 1000 ended on March 31, but the RTO elected to keep working with transmission owners and non-incumbent developers to refine Tariff language and develop a binding selected developer agreement.
“These enhancements and clarifications reflect MISO’s experience and discussions with stakeholders during the first year of the prequalification process as well as lessons learned from observing the processes of other RTOs,” MISO said.
MISO’s competitive transmission developer selection process has been the subject of four rounds of FERC compliance filings and, according to the RTO, 16 months of consultation with stakeholders. The RTO said it will make another compliance filing next month addressing other areas needing improvement.
