WILMINGTON, Del. — The Members Committee overwhelmingly agreed last week to fund a $450,000 budget for the Consumer Advocates of the PJM States (CAPS), in part through an assessment on electric customers.
According to the proposal, the charge to a residential customer using 12,000 kWh annually will be eight-tenths of a cent. The group also would receive a one-time infusion of $350,000 from Exelon if the D.C. Public Service Commission approves its acquisition of Pepco Holdings Inc., under a settlement brokered with D.C.’s mayor.
“The consumer advocates designated by state statute are in a position of having to be in two places at once — the state where there’s always lots to do, and here at PJM, where most of the charges are coming from,” said CAPS Executive Director Dan Griffiths. That, he said, has stretched the advocates’ resources, making it difficult to monitor the “hundreds” of meetings the RTO holds each year.
“This is something we think is a serious problem because the voice of the retail folks who are ultimately paying the bills is absent.”
Griffiths said the group modeled its budget and funding request on that of the Organization of PJM States Inc. (OPSI), which is funded through a charge in Schedule 9 of the RTO’s Tariff.
The proposal passed with slightly more than 81% of a sector-weighted vote, receiving unanimous support from End Use Customers and 89% from Other Suppliers. About 79% of Electric Distributors supported the funding, along with 71% of Generation Owners and two-thirds of Transmission Owners.
At the Members Committee meeting earlier this month where the plan was introduced, it met resistance from some suppliers, most notably Direct Energy, Talen Energy and Dynegy. Last week, Direct Energy abstained from the vote, while Talen and Dynegy opposed it. (See Consumer Advocates’ Funding Request Sparks Sharp Words.)
Jesse Dillon, assistant general counsel for Talen, repeated his argument that the proposal runs afoul of the First Amendment prohibition against “compelled speech.”
“I’ve already made the policy point that no member should have to fund the advocacy voting of another member, period,” he said. “This one group is receiving treatment that others aren’t. Their voices are no more relevant in the marketplace of ideas than other entities.”
In response to the free speech argument, the consumer advocates penned an Oct. 13 memo to the heads of the Members Committee defending the proposal, saying in part that the doctrine doesn’t apply to government entities, “which the members of CAPS clearly are.”
The memo cites FERC’s approval of OPSI funding in 2006 over a similar objection by Public Service Enterprise Group (ER06-78).
In that case, FERC ruled, “PJM is providing funding to make its job of working with the states easier and more efficient. The ability of any participant to express its views will not be constrained by this proposal.”
Dillon disputed the classification of CAPS as a government entity, noting that the group is a 501c tax-exempt nonprofit organization.
CAPS, made up of consumer advocates from PJM states and D.C., was formed in 2012 with start-up funding from a FERC enforcement settlement with Constellation Energy (IN12-7-00).
West Virginia Consumer Advocate Jackie Roberts pointed out that a portion of electric customers’ bills already go toward having the companies — Appalachian Power, in her case — represented at PJM.
“All we’re asking is that the customers we represent have an opportunity to pay less than a cent a year to have us have a seat at the stakeholder table,” she said.
States trying to meet their goals for the federal Clean Power Plan should be able to get two-year extensions without much trouble, according to the Environmental Protection Agency.
EPA Acting Assistant Administrator for Air and Radiation Janet McCabe told the Environmental Council of States that meeting the requirements for the two-year extension was “not intended to be a heavy lift.”
“We understand that it may be every single state that needs to seek an extension,” McCabe said. “There’s a lot of work for states to do and a lot of different processes.”
Trudeau’s Election in Canada May Be Good News for Keystone
Trudeau
Canada’s new prime minister, Justin Trudeau, has said he supports the construction of the embattled Keystone XL pipeline, which would carry oil from Canada to the U.S. Gulf Coast. The proposed pipeline does not have the support of the Obama administration, so environmentalists in both countries are waiting to see how hard Trudeau’s Liberal Party will push for the project.
Trudeau declined to say if he and President Obama discussed the Keystone XL project during their call after the election. “I think one of the things that has been a challenge in the relationship between Canada and the United States is it has in many cases been focused on a single point of disagreement, a single potential point of disagreement, a single pipeline,” he told reporters.
Although he is publicly in favor of pipelines as part of a national infrastructure program, Trudeau has also been an outspoken advocate for adoption of a national plan for reducing greenhouse gas emissions.
DOE Approves Emera CNG Exports from Florida Facility
The Department of Energy on Thursday gave its approval for Emera CNG to export a relatively small amount of U.S.-produced compressed natural gas out of a proposed terminal at the Port of Palm Beach, Fla.
Emera needed federal authorization to export to countries that do not have free trade agreements with the U.S. Emera will be allowed to export 8 million cubic feet of gas a day in trailers, tank containers and ocean-going carriers for 20 years.
Massachusetts Attorney General Maura Healey has asked FERC to closely examine Tennessee Gas Pipeline’s proposed Northeast Energy Direct pipeline, questioning whether there is a need for the new pipeline in view of the number of other projects either planned or in progress.
“This proposed pipeline would have a significant impact on local residents and the energy future of Massachusetts,” Healey wrote to the commission. “FERC should fully evaluate the need for this project in conjunction with other pipeline proposals for the region.”
She urged the commission to study the results of a regional electric reliability study on the Northeast region, which is due Oct. 31. The Northeast suffered from fuel constraints during the past two cold winters, with gas supply at a premium.
FERC OKs Environmental Study for Dominion Pipeline in NY
FERC issued a positive environmental assessment for a natural gas pipeline in New York, spurring complaints from opponents of the project. Dominion Transmission, a subsidiary of Dominion Resources, wants to expand its 200-mile pipeline to deliver natural gas produced in the Marcellus Shale fields in Pennsylvania.
FERC ruled that there were no adverse environmental impacts, but opponents in central New York have said the assessment was rudimentary. They called for a more detailed review, as well as an analysis of the project’s possible impact on existing and future infrastructure.
National Renewable Energy Laboratory Names Keller as New Director
Martin Keller, a Department of Energy veteran who headed up the Energy and Environmental Sciences Lab at the Oak Ridge National Laboratory, has been named director of the National Renewable Energy Laboratory.
Energy Secretary Ernest Moniz said Keller’s “track record in building links between the basic sciences and our nation’s energy challenges will help NREL reinforce its place as the world’s leading laboratory for renewable energy and energy efficiency research and development.”
Along with the promotion, Martin Keller will also become president of the Alliance for Sustainable Energy.
Three quarters of Americans now share the scientific community’s acceptance of climate change, the highest number in four years of polling by the University of Texas at Austin.
Perhaps the largest surprise in the findings is that 59% of Republicans now believe climate change is happening, up from 47% only six months ago. The Democratic acceptance level is hovering at about 90%, the university reported.
$13.5 Trillion Investment Needed to Fund Climate Change Pledges
The International Energy Agency has calculated a number needed to meet the climate change action pledges submitted for the upcoming Climate Summit in Paris: $13.5 trillion.
The IEA’s World Energy Outlook estimated the energy industry will need to make a substantial investment in wind, solar, nuclear carbon capture and storage to meet the energy efficiency and low-carbon technology goals that will be introduced at the summit.
“The energy industry needs a strong and clear signal,” said IEA Executive Director Fatih Birol. “Failing to send this signal will push energy investments in the wrong direction, locking in unsustainable energy infrastructure for decades.”
TVA’s Watts Bar 2 Granted Operating License by NRC
The Nuclear Regulatory Commission last week granted the Tennessee Valley Authority an operating license for its Watts Bar Unit 2 reactor, the first new U.S. nuclear station in nearly 20 years. The license paves the way for fueling the reactor and to start testing. TVA says the plant, near Spring City, Tenn., will go online by December.
Construction began on Watts Bar 2 in 1973 but stopped in 1988 when TVA suspended its nuclear operations due to safety concerns. Watts Bar 1 was finished and went online in 1996. Work on Watts Bar 2 restarted in 2007.
NRC’s action “demonstrates to the people of the valley that we have taken every step possible to deliver low-cost, carbon-free electricity safely and with the highest quality,” said TVA President and CEO Bill Johnson.
Environmental Groups File to Intervene in ACP Project
Sixteen environmental groups on Friday filed to intervene in the permit process of the proposed 564-mile Atlantic Coast Pipeline, which would deliver shale gas from West Virginia through Virginia into North Carolina. Dominion Resources and Duke Energy are among the investors in the $5 billion project.
The groups, including Chesapeake Climate Action Network, the Sierra Club and Appalachian Mountain Advocates, say the pipeline would cause irreparable harm to the environment, it would “fragment the heart” of the largest tract of land in the eastern U.S. and the developers have not proven that it is needed.
The request came about a week after it was determined that the proposed route takes it through a portion of the George Washington National Forest in Virginia, which is home of the protected Cow Knob salamander.
Minnesota, North Dakota Continue Clash over Coal-fired Energy
The 8th U.S. Circuit Court of Appeals heard arguments in a case pitting Minnesota regulators against North Dakota and its utility and coal interests over a 2007 Minnesota law restricting new power generation from coal.
North Dakota successfully argued in federal district court that the law illegally regulates out-of-state utilities in violation of the U.S. Constitution’s Commerce Clause. A three-judge panel of the appeals court is reviewing the decision, which enjoined Minnesota from enforcing key sections of the law.
North Dakota interests say it hampers their ability to find buyers for power from existing coal-fired generating plants or to plan for new ones. Coal-generated electricity comprises 78% of North Dakota’s electricity.
WASHINGTON — For months, supporters and detractors of the Environmental Protection Agency’s Clean Power Plan have been debating whether the carbon reductions are too stringent or not tough enough; whether it will compromise reliability; whether it will save struggling nuclear power plants.
With Thursday’s publication of the rule in the Federal Register, another question took center stage, one whose answer could make the others academic: Does EPA have the legal authority to do what it did?
Twenty-six states gave their answer Friday, filing suit in the D.C. Circuit Court of Appeals to void the rule, which seeks to cut the power sector’s carbon emissions by 32% by 2030, compared with 2005 levels.
West Virginia and 23 other states — Alabama, Arizona, Arkansas, Colorado, Florida, Georgia, Indiana, Kansas, Kentucky, Louisiana, Michigan, Missouri, Montana, Nebraska, New Jersey, North Carolina, Ohio, South Carolina, South Dakota, Texas, Utah, Wisconsin and Wyoming — joined in one challenge while Oklahoma and North Dakota filed separate suits. Congressional Republicans have also vowed to push legislation preventing the plan from taking effect.
Fifteen other states, along with D.C. and New York City, are planning to intervene in support of EPA.
A senior EPA official and a panel of legal experts gave their own opinions at Infocast’s second Clean Power Plan Summit in Washington last week.
Best System of Emission Reduction
The Supreme Court ruled in 2007 that EPA had authority to regulate carbon dioxide. At issue is how EPA is attempting to do it, specifically how the agency defined the “best system of emission reduction (BSER),” the standard set in Section 111(d) of the Clean Air Act.
“The best system of emission reduction is a term of art in Section 111 [that] has been applied more than 60 times. And at bottom we did not undertake the process of answering that question any differently than we have in the past,” said Joseph Goffman, EPA associate assistant administrator and senior counsel.
The answer that EPA came up with — largely substituting coal-fired generation with natural gas and renewables — “amounted to assembling the information that we were getting back from states and utilities and stakeholders based on what they were already doing,” said Goffman, noting that nearly all states have energy efficiency programs and more than half have policies encouraging or requiring renewables.
“So we answered the question ‘What is BSER?’ in some ways by saying, ‘Keep doing what you’re already doing.’ Level the playing field so that everyone is doing some ensemble of those things.”
Impossible Standards for Coal Plants
Critics contend that the Clean Power Plan is based on a novel — and improper — interpretation of 111(d).
“While EPA has issued numerous rules under Section 111, it has never interpreted this section in this manner or this broadly,” said Allison Wood, an environmental and administrative law attorney with Hunton & Williams. “Are you allowed under the Clean Air Act to look beyond [the fence line] and think about the electric system as a whole? … The answer to that I would say is ‘no.’”
Peter Glaser, an energy and environmental lawyer with Troutman Sanders, noted that EPA added in the final rule something that was missing from the draft — national emission standards: 1,305 lbs/MWh for coal and oil plants and 771 lbs/MWh for natural gas plants.
“It’s something that [has been] in every single new source performance standard that EPA has ever done. The fact that they determined that they really want to have something like that in the final [rule] tells you that they were very nervous about the legal justification,” Glaser said. “The problem is that the rates they came up with are rates that obviously the sources in the category can’t meet. And that’s the whole point, actually. Coal plants are not supposed to be 1,305. It’s supposed to reduce generation or close.
“What EPA did is to say, ‘We’re not really regulating the sources in the categories; we’re regulating the owners of the sources.’ So owners can meet the standards by reducing the generation of their coal units and increasing the generation — or paying someone else — to increase generation of renewable resources. … Despite Congress having consistently resisted giving EPA authority to do cap-and-trade, that’s exactly what EPA has finalized here.”
Wood agreed. “Never before in the history of the Clean Air Act has a standard of performance … been based on ‘don’t run,’” she said. “There is not any coal plant in the world that can meet [the emissions standard]. The only way it can meet it is by not running.”
Shutting Plants Down
Panel moderator Kate Konschnik, director of the Harvard Environmental Policy Initiative, disagreed, saying that EPA has previously issued rules that “caused certain units to shut down.”
“In particular, that was squarely at issue in a D.C. Circuit case about the cement kiln industry in the 1970s — that one type of cement plant would cease to exist because of the standards,” she said.
Bob Sussman, an environmental and energy policy consultant and former EPA senior policy counsel, also saw the rule differently than the critics.
“I don’t think that 111(d) of the Clean Air Act is guaranteeing that every existing plant subject to a standard is going to be able to meet that standard and continue to operate. Indeed, the whole idea of 111(d) is to push the envelope on technology and emission reduction,” Sussman said.
“I think the important point here is that the term in the statute is ‘best system of emission reduction.’ It’s not ‘best emission-reduction technology achievable.’
‘System’ is a pretty big and [expansive] term. It doesn’t necessarily mean only hardware that can be installed at a plant site that would reduce emissions. Here EPA is defining ‘system’ in a way that reflects the interconnected nature of the electricity grid and I think that’s a very reasonable thing to do.”
Ann Weeks, senior counsel and legal director for the Clean Air Task Force, said the rule was “locking in” the industry’s displacement of coal-fired generation by cheaper natural gas.
“Could EPA have done more in this rule? Absolutely,” she said. “The rule is not really technology-forcing.”
Redundant Regulation?
Wood said the interpretation of BSER is not the only obstacle EPA will have to face in defending the rule.
“The other hurdle that EPA is going to have to get over is whether this source category can even be regulated under 111(d) of the Clean Air Act because of the fact that it is also regulated under Section 112 through the Mercury and Air Toxics Standards,” she said.
The rule’s fortunes in the D.C. Circuit may depend on which three judges are picked to hear the case. But observers on all sides of the issue expect the Supreme Court to have the last word. (See Former EPA Official: Clean Power Plan won’t Survive.)
Sussman predicted that conservative Justices Antonin Scalia, Clarence Thomas and Samuel Alito will find EPA’s interpretation of the rule unreasonable and liberals Ruth Bader Ginsburg, Stephen Breyer, Sonia Sotomayor and Elena Kagan to rule in the agency’s favor.
“I think in the end it will come down to what Chief Justice [John] Roberts thinks and what Justice [Anthony] Kennedy thinks,” he said.
In the court’s 5-4 ruling in Massachusetts v. Environmental Protection Agency, which established EPA’s authority to regulate CO2, Kennedy sided with the majority, while Roberts joined the minority.
The chief justice wrote a dissent that focused not on the merits of the case but on rejecting the legal standing of the coalition of government officials and environmental groups that sought to force the Bush administration to act.
EPA’s Goffman said the agency didn’t concern itself with handicapping the justices’ leanings when it was writing the rule. “I only think about it in terms of whether we have a solid legal case to make and we think we do,” he told RTO Insider after his remarks. “We think we’re on solid ground. We trust that ultimately the merits will speak for themselves.”
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.”
