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.
FERC last week approved a MISO compliance filing regarding its cost allocation method for resources committed for voltage or local reliability (VLR) requirements but required the RTO to make its study process on “commercially significant” voltage problems more transparent (ER12-678-005).
“Although we find that MISO has complied with most of the directives in the June 2014 order, we agree with the protesters that MISO did not adequately comply with other directives; as a result, the Tariff needs further clarification,” FERC wrote.
The ruling originates from two filings MISO made in December 2011. One proposed that the local balancing authority (LBA) area shoulder more of the costs resulting from VLR requirements. The second proposed a mechanism to mitigate the ability of resources needed for voltage support to exercise market power. After holding a technical conference, FERC conditionally accepted the proposals.
In a June 30, 2014, order, the commission put limits on the discretion of transmission owners to determine if a VLR commitment is commercially significant and put more emphasis on stakeholder participation in the determination.
The determination of whether a VLR issue is commercially significant is based on the frequency of occurrence and monetary impact. The costs of those judged commercially significant are spread more broadly among LBAs than those determined to be local.
NRG, TDUs Complain
NRG Energy and four transmission-dependent utilities — Midwest Madison Gas and Electric, Missouri Joint Municipal Electric Utility Commission, Missouri River Energy Services and WPPI Energy — protested last year’s compliance filing, saying MISO should be required to conduct regular meetings with stakeholders and share information used to perform studies.
The commission rejected on procedural grounds NRG’s request that MISO be required to provide the study model. But it agreed with the complainants that MISO had not done enough to make the study process open and transparent.
“We agree with Midwest TDUs that language added by MISO in the compliance filing … would limit the participation in the study process of local BAAs and interested market participants to merely requesting a study. If these requests will be rolled into the quarterly study process that MISO would normally do anyway, it is unclear how MISO’s additional language would provide an open and transparent study process,” the commission said.
It ordered MISO to add new language permitting LBAs and market participants to participate in the studies and request that reoccurring VLR commitments be studied.
It also directed the RTO to hold regular meetings with stakeholders similar to those conducted when identifying system support resources under the Tariff, saying it “will provide more meaningful participation and opportunity to provide feedback.”
“With regard to a market participant’s access to data during the study process, we agree with Midwest TDUs that MISO’s proposal to limit access to such data to those parties that request the study has not been shown to be in compliance with the June 2014 order,” FERC continued.
It required MISO to provide all the assumptions and outputs of the model to any party that is liable for VLR-related charges that signs a non-disclosure agreement.
FERC last week denied multiple requests for rehearing and clarification of its 2014 order that conditionally approved the core Integrated System entities’ SPP membership (ER14-2850).
The November 2014 order approved Western Area Power Administration–Upper Great Plains (WAPA-UGP), Basin Electric Power Cooperative and Heartland Consumers Power District’s membership into SPP, which became official Oct. 1. The order also granted a federal service exemption to WAPA, which allowed the federal agency to become the first such entity to join an RTO.
At the same time, the order established hearing and settlement judge procedures for SPP’s proposed Tariff revisions to allow the entities’ membership.
The 2014 order also set several seams issues for settlement procedures but found the perpetuation of pancaked transmission rates between the Integrated System and MISO and between SPP and MISO to be beyond the proceeding’s scope. FERC also declined to include issues connected to Corn Belt Power Cooperative and Central Power Electric Cooperative, as neither had yet transferred their facilities to SPP (the two co-ops will join the RTO on Jan. 1, 2016).
MISO, Kansas’ State Corporation Commission and Otter Tail Power all filed rehearing requests.
FERC denied the Kansas SCC’s request for a rehearing over WAPA’s federal exemption and claims that it ignored the latter commission’s expert testimony. FERC said its acceptance of the exemption was based on its policy of promoting RTO membership, and that Kansas’ expert testimony used SPP’s analysis as a baseline in doing its own study of the integration’s stakeholder benefits.
The Kansas commission also joined with MISO and Otter Tail in asking for a rehearing on FERC’s acceptance of SPP’s base-plan upgrade and regional cost-sharing proposal. That request was denied, with the commission finding SPP “crafted a reasonable transition proposal for integrating the current SPP and Integrated System transmission systems.”
FERC also denied MISO’s argument that the five-year transition proposal for the MISO-Entergy integration should have served as a model for the SPP-IS proposal. The commission said the MISO-Entergy transition proposal was developed, in part, “to prevent unfair subsidization of [project costs] required to make Entergy’s transmission infrastructure comparable to MISO’s footprint,” and that no parties in the SPP-IS proceeding had alleged deficiencies.
The commission rejected another Kansas commission rehearing request regarding the integrated entities’ responsibility for SPP’s regionally funded legacy facilities. FERC found SPP and the Integrated System “crafted a practical, reciprocal cost allocation approach for facilities in service before the integration date that is consistent with commission precedent.”
The Supreme Court announced yesterday that it will rule on two federal-state jurisdictional cases pitting Maryland regulators against FERC.
The court said it would consider orders by the 4th U.S. Circuit Court of Appeals that upheld lower court rulings throwing out contracts in which generation developers won state-issued subsidies to build plants in the two states.
Competitive Power Ventures and state regulators have argued that the subsidies are legal. The courts ruled with PPL and other plaintiffs in saying the subsidies violated FERC jurisdiction over the wholesale electric market.
The cases revolve around a 660-MW combined-cycle plant in Maryland. CPV won a solicitation from the Maryland Public Service Commission to build a plant in the Southwest MAAC zone. PPL was joined in its challenge of the contract by Calpine, Essential Power and Lakewood Cogeneration.
CPV and the regulators are asking the high court to reinstate the contracts. CPV has gone ahead with its construction plans, despite losing a subsequent ruling by FERC. (See CPV Md. Plant Goes Forward Despite FERC Ruling.)
In Hughes v. PPL EnergyPlus (14-614), the court will consider the following questions:
When a seller offers to build generation and sell wholesale power on a fixed rate contract basis, does the [Federal Power Act] field-preempt a state order directing retail utilities to enter into the contract?
Does FERC’s acceptance of an annual regional capacity auction preempt states from requiring retail utilities to contract at fixed rates with sellers who are willing to commit to sell into the auction on a long-term basis?
In CPV Maryland v. PPL EnergyPlus (14-623), the court will answer two additional questions:
Where, as a result of a state-directed procurement, the contract price to build and operate a power plant is the developer’s bid price, and may result in payments beyond what the developer earns selling the plant’s capacity in the FERC-supervised auction, is the program “field preempted” as a State’s attempt to set interstate wholesale rates?
Is a state-directed contract to support construction of a power plant “conflict preempted” because its long-term pricing structure provides incentives different from the incentives provided by prices generated in the FERC-supervised yearly capacity auction?
The Supreme Court declined to hear two related cases in New Jersey decided by the 3rd Circuit Court.
(An earlier version of this story erroneously stated that the court would also hear arguments in the New Jersey cases.)
New York’s winter electricity prices are expected to average about 9% lower than last year’s, the staff of the New York Public Service Commission said on Thursday.
In a presentation to the commission, staffers said market conditions would benefit from better preparation and other practices refined over the past two winters, as well as from lower natural gas prices that have also influenced other eastern U.S. markets.
“We have adequate resources to meet the needs of the utilities … while we’re also looking at lower commodity prices,” said Raj Addepalli, managing director for utility rates and services at the PSC.
For example, at the New York Mercantile Exchange, futures prices for electricity in the New York City, Hudson Valley and Western New York zones range from about $11 to $23/MWh lower than they were a year ago. New York City futures prices averaged $91.06/MWh a year ago, while that same contract now averages $67.94.
The PSC said utilities and the commission have instituted a series of “lessons learned” procedures that grew out of the polar vortex two years ago. Plants have increased their capacity for on-site fuel storage, especially in eastern New York, and state officials have implemented an expedited procedure to obtain permits from the Department of Environmental Conservation to allow fuel-oil burning.
“Terry Boston’s service to PJM and stakeholders has set a high standard,” board Chairman Howard Schneider said. “The board and I are confident that Andy will continue to ensure the stakeholder collaboration and outstanding performance for which PJM is known while establishing his own visionary leadership.”
“There’s a lot of things that make Terry exceptional, not the least his humility,” said FERC Commissioner Cheryl LaFleur, a luncheon speaker at the event Monday. “He has a rare combination of technical expertise — no matter what you’re talking about: everything from transformers to transmission planning to market planning — and people leadership skills.”
Ott’s previous role was as PJM’s executive vice president of markets. An 18-year veteran with the RTO, Ott was responsible for implementing LMP, financial transmission rights, the day-ahead energy market and capacity market.
Prior to joining PJM, he worked for GPU Inc. in transmission planning and operations.
He is a board member of both PJM Technologies and PJM Environmental Information Services. He also serves on the board of directors for the Association of Power Exchanges and chairs the Study Committee on Electricity Markets and Regulation for Paris-based CIGRE (International Council on Large Electric Systems).
He received his bachelor’s degree in electrical engineering from Pennsylvania State University and his master’s in applied statistics from Villanova University. Ott is an Institute of Electrical and Electronics Engineers fellow.
