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October 31, 2024

Exelon: EPA Plan Will Get Nuclear Issue ‘Half Right’

Joe Dominguez, executive vice president of government and regulatory affairs for Exelon, said the company is not abandoning organized markets but needs them to reflect the cost of carbon emissions for its nuclear fleet to survive.

epa“The work that we’ve seen from the RTOs — from PJM, even from ERCOT — indicate that with a relatively modest price on carbon we can achieve compliance with the EPA’s [Clean Power] Plan.”

Dominguez said he believes EPA will get the nuclear issue “half right” in the final emissions rule, due this summer.

“My guess is EPA is going to largely ignore the problem and hope that nuclear plants don’t retire,” he said.

But he predicted that EPA will “give substantial incentives for mass-based regional cooperative programs to achieve compliance.”

“And there, I think, nuclear is going to be fully recognized, because in any mass-based program the loss of nuclear units would quite obviously be reflected in an increase in the emissions as fossil fuel takes up the gap left by nuclear. That will self-correct.”

Ideas to Reform MISO Out-of-Cycle Process Emerge

By Chris O’Malley

MISO stakeholders have submitted recommendations for refining the out-of-cycle request process in the wake of transmission developer complaints over Entergy’s $187 million transmission upgrade near Lake Charles, La.

MISO approved the OOC request, which Entergy said was necessary to meet the sudden needs of an industrial customer, following a clamor from transmission developers complaining they were denied a chance to compete for the project. (See Entergy Out-of-Cycle Requests Win MISO Board OK.)

Transmission developers, transmission owners and ITC Holdings proposed numerous changes to MISO’s Transmission Planning Business Practices Manual. “The urgency and the need cannot be the result of inadequate planning, or worse, action that attempts to circumvent the robust, stakeholder-driven process” in the MISO Transmission Expansion Plan (MTEP), the TD sector said in comments submitted at a Planning Advisory Committee meeting.

Among the sector’s proposed changes is a requirement that OOC projects involving multiple load additions have “documented customer service requests.” One of the criticisms of the Entergy OOC request was that neither MISO nor stakeholders were privy to details about the Entergy customer or its specific load needs.

Entergy pointed broadly to an industrial renaissance in the Lake Charles region and said that it received unanticipated customer demand for service after the annual MTEP cutoff date. It said it was not permitted to disclose the customer.

The TD sector also proposed to insert language that would require MISO, before submitting a request for stakeholder review, to determine that a project “does not directly or indirectly eliminate the need for a Market Efficiency Project or Multi-Value Project” — projects that are subject to competition.

More Flexible Language

Meanwhile, TOs are seeking to tweak OOC eligibility rules. They proposed language that notes that “it is not possible to predict every event that will lead to the need for OOC treatment” of a baseline reliability project or “other” project. For example, projects may be driven by generation retirements or regulatory mandates, they said.

ITC Holdings, which did not join with the majority of transmission owner comments, also proposed to change the criteria for OOC project designation. ITC said its language change would allow for needs not specifically identified in the existing criteria. “For example, storm damage that necessitates a system change may require OOC review,” ITC said.

Alternatives to OOC

Other changes proposed for the Transmission Planning Business Practices Manual involve stakeholder reviews of OOC requests.

The TD sector complained that MISO moved too fast on Entergy’s Lake Charles request, without adequate feedback from stakeholders.

The sector is seeking at least one sub-regional planning meeting or public Technical Studies Task Force meeting “at which the out-of-cycle project and identified alternatives will be evaluated.” Stakeholders would be able to submit alternatives to an OOC at a following sub-regional or task force meeting.

TOs Assert Rights

At the PAC meeting last week, MISO officials attempted to compare the suggested stakeholder redlines to the BPM manual. Stakeholders offered some additional perspective.

“What we were trying to do is return this BPM language to its fundamental source, which is the transmission owner’s agreement,” said Cynthia Crane, principal regulatory analyst at ITC Holdings.

“And that’s what’s missing in all this dialog, it’s [that] the transmission owners agreement gives transmission owners certain rights” such as to upgrade, modify, alter or replace its facilities, she said. “We have to be really careful in what we are drafting here in order to not violate the TOA,” she added.

Jeff Webb, director of planning at MISO, said “The last thing you want to do is impede the TOs’ [ability to meet their] obligations.”

Suspicion of OOC Requests

But some speaking at the PAC meeting urged MISO to be vigilant about maintaining oversight, given the potential for utilities to misuse the OOC process.

“I can play this game all day where I need to build [a line] because I haven’t put my load in for three years now and I know it’s coming, but I don’t want to go through that competitive process stuff,” said Kip Fox, director of transmission strategy and grid development at American Electric Power, speaking of a hypothetical abuse. “So I’ll just wait until the four-year window closes and then I’ll submit it and all of the sudden it’s a reliability project.”

Fox told MISO: “You have to give us some confidence that those loads are being looked at.”

Webb noted the challenge in obtaining information from a load-serving entity making an OOC request. “What is the load-serving entity able and willing to disclose to defuse this sort of ‘proof issue’ that’s in front of us?”

Load-serving entities often counter that they’re prevented by nondisclosure agreements from revealing specifics about customer expansion plans.

Webb said MISO would review the feedback and return at a future meeting with draft language of its own.

PJM Markets and Reliability Committee Briefs

PJM doesn’t plan to allow generators to make hourly market offers for winter 2015/16, despite a Federal Energy Regulatory Commission order that such flexibility be developed by Nov. 1.

Officials said the RTO cannot accept such offers until it revamps its market system and that the new software cannot be completed by next winter.

In its June 9 ruling, FERC ordered PJM to file Tariff changes allowing market participants to submit day-ahead offers that vary by the hour and update their offers in real time, including in emergency situations, or explain why the changes are unnecessary. The commission said the changes should take effect by Nov. 1 “or as soon as practicable thereafter.” PJM must make a compliance filing informing the commission of its plans by July 10. (See Duke, ODEC Denied ‘Stranded’ Gas Compensation.)

In April, stakeholders approved the creation of the Generator Offer Flexibility Senior Task Force to consider such changes in response to a problem statement by Calpine. Calpine noted that PJM is the only organized market in the country that doesn’t permit generators to vary their offers hourly. (See Bid for Generator Price Flexibility Draws Debate over 10% Adder.)

PJM said it considered proposing an interim solution while it waits for the software changes but bowed to stakeholder sentiment for a single, long-term solution.

The task force held its first meeting June 29.

Monitor: Marginal Benefit Factor Faulty, Inconsistently Applied

The Independent Market Monitor is recommending a broader look at concerns that PJM is buying too much fast-responding “RegD” resources in the regulation market. The Monitor said Thursday that stakeholders should revisit the marginal benefit factor that defines the substitutability between “RegA” and RegD megawatts.

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“PJM’s current marginal benefit factor function is, at least in some hours, overvaluing RegD as a substitute for RegA in the optimization,” said Howard Haas of Monitoring Analytics. The misalignment also means RegD resources are being incorrectly compensated — sometimes being paid too little, and sometimes too much, Haas said. (See PJM Market Monitor: Faulty Marginal Benefit Factor Harming Regulation.)

The Monitor proposed a problem statement and issue charge that will be considered at the MRC’s July 23 meeting.

PJM introduced its own problem statement on the regulation issue at the April Operating Committee meeting, but it has not yet been brought to a vote. Under times of system stress, PJM said, it has observed issues with regulation performance when the proportion of megawatts from RegD resources is greater than 42%. (See “Too Much of a Good Thing? PJM Concerned Fast Response Regulation Crowding out Traditional Resources,” PJM Operating Committee Briefs.)

A PJM official told the MRC that the RTO is currently performing a study on the issue, which will take eight weeks to complete.

Changes Would Allow Earlier Replacement Transactions

The committee will be asked to vote at its July 23 meeting on manual changes that would allow market participants to enter replacement capacity transactions earlier than Nov. 30 prior to the start of the delivery year if the need is linked to a physical reason that would prevent a participant from meeting its commitment.

Such replacements would be permitted when the owner of the replaced resource could show the expected final physical position of the resource at the time of the request.

Existing generators could engage in such transactions if they are being deactivated, while new generators could replace themselves if their project is cancelled or delayed. Demand response or energy efficiency resources could be replaced due to the permanent departure of their loads.

Resources replaced would not be able to be recommitted for the delivery year.

PJM Law Proposes Cleaning up Language in Governing Documents

The PJM Law Department proposed an initiative to clean up language in the RTO’s governing documents that is “ambiguous, incorrect or requires clarification.”

The project would entail reviewing the Tariff, Operating Agreement and Reliability Assurance Agreement related to topics including offer caps and prices, demand resources and the capacity market.

PJM’s proposed problem statement and issue charge would assign the task to the Market Implementation Committee,  separating it from the effort already underway involving the Tariff Harmonization Senior Task Force. The task force was formed in December to identify discrepancies in provisions regarding definitions, indemnification, limitation of liability and alternative dispute resolution procedures in the same governing documents. (See Task Force Proposed to Resolve Inconsistencies in PJM Governing Documents.)

Ed Tatum of Old Dominion Electric Cooperative suggested that PJM consider unifying the efforts, saying ODEC wanted to participate but had limited resources. “Words do matter,” he said. “Anytime we do something like this, it’s a big deal.”

“I didn’t think what we were trying to do here really fit” the task force’s charter, responded PJM attorney Jacqui Hugee, who added the charter could be changed.

The task force plans to bring its first batch of changes to the next MRC meeting for a vote, along with a second batch for first reading.

Changes to Manuals 03, 3A, 19 Endorsed

Members endorsed the following manual changes:

  • Manual 19: Load Forecasting and Analysis. Makes changes to residential measurement and verification rules. Provides a solution for the issue that some electric distribution companies (EDCs) are prohibited from sharing personally identifiable information about residential customers participating in demand response programs. EDCs may use unique ID numbers instead through May 31, 2016.
  • Manual 03: Transmission Operations. Requires a separation between emergency and load dump ratings. In the event they are the same, the emergency rating submitted by the transmission owner shall be, at a minimum, 3% lower than the submitted Load Dump rating. If this change results in a normal rating that is higher than the long-term emergency rating, the TO shall, at a minimum, make the normal rating equal to the LTE rating.
  • Manual 3A: Energy Management System Model Updates and Quality Assurance. Continues effort to streamline and update sections pertaining to model updates. Most significant change is new section added on sub-transmission model submission requirements. TERM Appendix A reworked to more clearly outline business rules and tool interaction.

— Suzanne Herel

ODEC Seeks Last-Ditch Vote on Deadlocked FTR/ARR Issue

By Suzanne Herel

WILMINGTON, Del. — Old Dominion Electric Cooperative introduced a last-ditch effort to reach consensus on a redesign of the financial transmission rights and auction revenue rights processes Thursday, seeking a vote on a proposal combining recommendations from PJM and the Independent Market Monitor.

ODEC’s Steve Lieberman introduced the proposal to the Markets and Reliability Committee, prompted by a discussion at the May MRC meeting over whether the deadlocked FTR/ARR Senior Task Force should be disbanded. (See Move to Disband FTR Task Force Splits PJM Members.)

odecThe task force was established last spring to address concerns that FTR funding was falling short of target allocations. Although it was unable to reach consensus on rule changes, the FTR funding shortfall has evaporated as PJM has become more conservative in its modeling of ARRs and FTRs. For the 2014/15 planning year, which ended May 31, 2015, FTR funding had a surplus of more than $130 million.

As a result, however, Lieberman said, Stage 1B and Stage 2 ARR allocations have been “nearly eliminated.”

“In ODEC’s mind, this highlights the need for additional transmission development.”

His proposal, which will be brought to a vote at the July MRC meeting, incorporates three elements, which PJM had presented to the task force as package 22.

The first, drawn from a PJM staff proposal regarding the Stage 1A 10-year process, would escalate current ARR results using a zonal load forecast growth rate of +1.5%.

The other two elements were proposed by the Monitor and supported by PJM. It would change the method of reporting the monthly payout ratio so that any negative target allocations are included as revenue, slightly increasing the reported payout ratio.

It would also treat each FTR individually, eliminating the netting of positively and negatively valued FTR positions in a portfolio prior to determining positively valued FTR payout ratios.

Prospects Cloudy

Although the odds against the package winning two-thirds support in a sector-weighted MRC vote may be steep — none of the 12 packages brought to votes at the task force won even a simple majority vote — ODEC did receive some support Thursday.

Market Monitor Joe Bowring said he supported the proposal but said it was only a start in solving the issue.

PJM also endorsed the plan. “PJM would be supportive of moving forward with this particular package,” said Stu Bresler, vice president of market operations.

Carl Johnson, representing the PJM Public Power Coalition, agreed. “This is the best way to move forward. As a load-serving entity, this is something we can support,” he said.

But the proposal had its detractors.

DC Energy’s Bruce Bleiweis, who served on the task force, suggested ODEC eliminate the netting proposal in order to garner wider support. And, he said, “At some point in time, stakeholders and PJM need to agree that we just didn’t come to a solution for the problem we were facing.”

Consultant Roy Shanker agreed with Bleiweis that the “netting” proposal did not increase ARRs.

Shanker also accused ODEC of “cherry picking” from proposals made to the task force. “We’re hearing three-line summaries of things people spent months on,” he said.

“There was no attempt at cherry picking,” Lieberman responded. “It’s the proposal that received the greatest support” at the task force.

Unilateral Filing?

In a June 2 filing with the Federal Energy Regulatory Commission, PJM suggested it may make a unilateral Section 206 filing to break the deadlock. PJM said the shift of revenues from ARR holders to FTR holders “is less equitable and desirable than it would prefer.” (See FERC Denies Rehearing on PJM FTR Funding.)

PJM Considering Release of Uplift, Outage Data

By Rich Heidorn Jr.

WILMINGTON, Del. — PJM is proposing to relax confidentiality rules regarding uplift payments and generator outages, saying they are inhibiting stakeholder discussions.

The RTO on Thursday presented the Markets and Reliability Committee a problem statement and proposed changes to section 3.5 of PJM Manual 33.

pjm

PJM said the proposed changes were prompted by requests from stakeholders for more granular data, particularly following severe system events such as weather disruptions.

The existing rules, which were prompted by the Federal Energy Regulatory Commission’s Order 719, have “no strict definition” of what information is confidential and do not consider the age of the information — meaning data considered confidential remains that way even after the reason for nondisclosure may have passed, PJM said.

The manual currently allows release of aggregate market data only if it includes more than three market participants’ data and the aggregation is for an area no smaller than a PJM transmission zone. The rules also prohibit PJM from disclosing some data even if it has been released publicly elsewhere, such as the nuclear plant outages the Nuclear Regulatory Commission posts on its website.

As a result, said PJM’s Tom Zadlo, the RTO is unable to be specific about conditions surrounding weather events, closed-loop interfaces and transmission planning.

Uplift Recipients

The Independent Market Monitor called for changes to the confidentiality rules in February 2014, when it disclosed that 10 generating units had received $335 million in uplift payments in 2013, 38% of the RTO’s total for the year. The Monitor contends all uplift payments should be public information, saying that identifying the causes of uplift and the generators receiving payments would allow competition to reduce those costs.

PJM said then that it would be unable to disclose the names of the units in question without a FERC order. (See PJM Won’t Name Uplift Recipients.) But in its proposed manual changes, PJM altered its position, saying that generator-specific information regarding uplift payments would not be considered confidential and that the RTO may disseminate the information daily.

Other Changes

The changes also would allow PJM to release information on generation outages once they have concluded, “if PJM deems them to be relevant.” The RTO said it would release such data only when related to an event on the grid, such as severe weather or a transmission system event.

PJM noted that while generation outage data has been considered confidential by the RTO it publishes transmission outages on its OASIS system.

pjm

The RTO also would be able to disclose demand response supplies in small areas, such as a group of zip codes, information it said is important to understanding the impact of weather events and closed-loop interfaces. Specific offers or suppliers would not be released.

The identities of generators that cleared in capacity market auctions — though not their offers — also would be disclosed.

Data that is already in the public domain from other sources would no longer be considered confidential.

Market Monitor Joe Bowring said he may ask PJM to consider amendments to the scope of the problem statement, which is expected to be brought to a vote at the July MRC meeting.

Stakeholder Concerns

Jason Barker of Exelon expressed misgivings over the release of information on generators receiving uplift payments, saying it would give competitors “information about what unit costs are.”

John Citrolo of Public Service Electric and Gas also expressed concern, saying release of uplift and outage information could “send the wrong message” to investors of publicly traded companies and interfere with established communication protocols with their organized labor.

PJM Moving on Day-Ahead Schedule Changes

By Rich Heidorn Jr.

WILMINGTON, Del. — PJM officials said last week they intend to move up the day-ahead energy market schedule despite a lack of consensus among stakeholders.

RTO officials said they believe the change is necessary as a result of the Federal Energy Regulatory Commission’s April order moving the timely nomination cycle deadline for gas to 2 p.m. ET from 12:30 p.m. and adding a third intraday nomination cycle.

pjm

The order required grid operators to adjust the posting of their day-ahead energy market and reliability unit commitment processes to a time “sufficiently in advance” of the timely and evening gas nomination cycles to allow generators to obtain gas (or to show cause why such changes are not necessary). Compliance filings are due July 23. (See FERC Approves Final Rule on Gas-Electric Coordination.)

Adrien Ford, director of market evolution, said PJM officials determined that they must change the energy market deadlines to comply with the order.

PJM’s filing will propose moving the deadline for submitting day-ahead offers up 90 minutes to 10:30 a.m. ET from noon. The RTO said it will post day-ahead results by 1:30 p.m., up from the current 4 p.m., as it reduces its clearing time to three hours from four.

The rebid window for the reliability assessment and commitment (RAC) run will be open from 1:30 to 2:15 p.m., up from the current 4 to 6 p.m. (Day-ahead commitments are based on demand bids from load-serving entities; the RAC run adds resources PJM believes may be needed based on PJM’s load forecast.)

In a poll of 51 stakeholders, none of the five suggested day-ahead clearing windows received a supermajority.

Slightly more than half of voters selected as their first choice a clearing window of 11 a.m. to 2 p.m., which PJM said would be too late to comply with the order. A clearing window of 10:15 a.m. to 1:15 p.m. was the first choice of 29%.

PJM said the window it proposed “received the highest overall support.” Although it was the first choice of only 8%, 31% picked it second and 59% made it their third choice.

Ford said stakeholders expressed a variety of opinions on how much time they needed between the posting of energy market awards and the gas nomination deadlines. “There was one stakeholder that needed 10 minutes. We had other members who said they needed an hour. There were others who didn’t think any of these [proposed windows] were sufficient,” Ford said. “Based on what I heard, 30 minutes was a way to meet” the FERC compliance requirement.

Stakeholder Reaction

Consultant Bob O’Connell said the changes increase risk premiums because generators will be basing offers into PJM’s markets on gas transactions executed during periods in which there is less price transparency. “You’re imposing higher costs on customers,” he said, adding that PJM should set a goal of clearing the day-ahead market in two hours or less.

John Citrolo of Public Service Electric and Gas said his company, which owns gas generation, would prefer a somewhat later start than proposed by PJM. But he added, “If gas traders get to their desks by 7 a.m. and show me some liquid prices by 9 a.m.,” the industry will adapt.

David “Scarp” Scarpignato of Calpine said his company supports PJM’s proposal, calling it “critical” to the company, whose fleet is virtually all gas-fired.

Generators with firm transportation can use second intraday nomination (ID 2) to bump those without firm transport who bought gas in ID 1. ID 3 is not bumpable.

As a result, if generators selected on the reliability run aren’t able to get their gas nominations in time for ID 2 at 3:30 pm., he said, “We’re not going to get gas.”

“Under [Capacity Performance], PJM has told generators to secure firm gas transport,” he added. “What’s the point of getting firm gas transport if we don’t get committed in time to use it?”

“We think we can get most RAC run commitments out before ID 2,” said Stu Bresler, PJM vice president of market operations.

Citrolo noted that PJM clears about 94% of its megawatts in the day-ahead market, urging, “Don’t turn things upside down for the other 6%.”

Scarp countered that on some days, the RAC run could provide as much as 12,000 MW. “It would be absolutely critical for reliability,” he said.

“We’ve been managing that later rebid window with one less nomination cycle for years,” responded Citrolo.

“And we’ve had a lot of units that can’t get gas,” interjected Mike Kormos, PJM executive vice president of operations. “We’ve been managing, but not that well.”

Monitor at Odds with PJM, Marketer over FTR Forfeiture Rule

By Rich Heidorn Jr.

PJM’s Independent Market Monitor told the Federal Energy Regulatory Commission last week that proposals by the RTO and a marketer to change the financial transmission rights (FTR) forfeiture rule would weaken protections against market manipulation.

The Monitor leveled the criticism in comments filed last week in the Section 206 case FERC ordered last year regarding the RTO’s treatment of virtual transactions (EL14-37).

The Monitor said PJM’s proposal to use a load- or generation-weighted reference bus rather than the largest impact bus would “functionally eliminate” the forfeiture rule under the current, non-portfolio approach to evaluating impacts of transactions on congestion.

In September, FERC ordered the Section 206 proceeding to determine whether PJM is improperly treating up-to-congestion transactions differently than incremental offers (INCs) and decrement bids (DECs). While INCs and DECs are charged uplift and subject to the FTR forfeiture rule, UTCs are exempt from both.

Ruling by October?

The Monitor’s criticism was in response to some of the almost two dozen comments filed in late May following a Jan. 7 technical conference on the issue.

In opening the Section 206 docket last year, the commission said it would rule within five months after it receives comments following the technical conference. That would put FERC on schedule for a ruling by the end of October. (See FERC Issues Request for Comments in UTC Uplift Docket; Ruling by October?)

The Monitor’s reply, filed June 23, was also critical of a proposal by EDF Trading to replace the forfeiture rule with individual enforcement actions.

“An enforcement action approach, relative to a rule-based approach, is inefficient, non-transparent and of limited value as a deterrent to market manipulation,” the Monitor said. “Such a rule is unclear and effectively unenforceable, which may be the point.”

The Monitor added that PJM’s current rule not subjecting UTCs to forfeitures “ignores [the] laws of physics.”

“As the power flows from the UTC source to the UTC sink, it flows across constraints. As a result, the net flow from a UTC should be treated the same as an INC when the UTC net flow is an injection and the same as a DEC when the UTC net flow is a withdrawal, under the FTR forfeiture rule.”

Uplift Task Force to Resume

FERC’s ruling in the 206 case may result in the application of uplift charges to UTCs, an issue that has split PJM stakeholders. UTC trading volumes collapsed after Sept. 8, the refund-effective date set by FERC for any uplift assessments.

PJM told the Markets and Reliability Committee on Thursday that the Energy Market Uplift Senior Task Force (EMUSTF) will resume regular meetings in August or September.

Stakeholders had asked to suspend the task force’s efforts on uplift cost allocation pending FERC action on PJM’s Capacity Performance proposal. FERC largely approved the proposal June 9.

Until last week — when it met to discuss the results of the backcast analysis on several cost allocation proposals — the task force had not held a meeting since April.

Also last week, PJM filed a proposed revision on how it pays generators for lost opportunity costs in the day-ahead and real-time markets (ER15-1966). The MRC approved the proposal, which came out of the task force meetings, in April. (See PJM Members Tighten Lost Opportunity Cost Rules; Tech-Specific Eligibility Retained.)

Supreme Court: EPA Erred on Mercury Rule

By Tom Kleckner

The Supreme Court ruled Monday that the Environmental Protection Agency acted “unreasonably” when it failed to consider costs before deciding to regulate mercury and other toxic emissions from power plants under the Clean Air Act.

The court’s 5-4 ruling did not void EPA’s authority to regulate the emissions but will require the agency to rewrite the Mercury and Air Toxics Standards (MATS) with a consideration of costs at the beginning of the process. It remanded the case to the D.C. Circuit Court of Appeals for further review.

Muted Impact

The ruling in Michigan v. Environmental Protection Agency is not expected to affect the number of coal-fired plant retirements. Industry analysts say about two-thirds of the nation’s 460 coal plants are already in compliance and investments in emission controls have already been made. (See MATS Challenge Too Late for Targeted Coal Plants.)

supreme court

“EPA is disappointed that the court did not uphold the rule, but this rule was issued more than three years ago, investments have been made and most plants are already well on their way to compliance,” EPA spokeswoman Melissa Harrison said in a statement.

“Because of the stricter air regulations that have been in place in New England for years, most plants would not have been affected by this rule,” said ISO-NE spokeswoman Marcia Blomberg. “And further, the economics of low-priced natural gas have driven many of the region’s older fossil-fired units to retirement, so we expect there will be limited impact from this ruling.”

NYISO is analyzing the decision, spokesman David Flanagan said.

Coal plants also are under pressure from EPA’s cross-state pollution rule and the carbon emission rule expected later this summer. Even without MATS, EPA Administrator Gina McCarthy told HBO’s “Real Time with Bill Maher” on Friday, “we’re still going to get at the toxic pollution from these facilities.”

Overreach

Nevertheless, the ruling gave EPA’s opponents something to celebrate. “The Supreme Court’s decision today vindicates the House’s legislative actions to rein in bureaucratic overreach and institute some common sense in rulemaking,” House Majority Leader Kevin McCarthy (R-Calif.) said.

Coal stocks rallied on the news. Peabody Energy rose almost 10% on the day, while Alpha Natural Resources was up 8.6%, Cloud Peak Energy gained 6.4% and Arch Coal jumped 4.5%.

‘Appropriate and Necessary’

MATS went into effect in April, although some power plants were given an extension until April 2016. Michigan v. Environmental Protection Agency combined what began as three challenges by industry groups and 23 states.

After the D.C. Circuit upheld the rule last year, the Supreme Court agreed to consider whether EPA acted unreasonably by refusing to consider costs in determining whether it is “appropriate and necessary” to regulate hazardous air pollutants emitted by electric utilities.

“EPA strayed well beyond the bounds of reasonable interpretation in concluding that cost is not a factor relevant to the appropriateness of regulating power plants,” Justice Antonin Scalia wrote in the majority opinion, in which he was joined by Chief Justice John Roberts and Justices Clarence Thomas, Samuel Alito and Anthony Kennedy.

“It is not rational, never mind ‘appropriate,’ to impose billions of dollars in economic costs in return for a few dollars in health or environmental benefits,” Scalia said.

In a dissent, Justice Elena Kagan noted that while EPA’s power plant regulations would have been unreasonable without considering costs, the agency had taken an “exhaustive” consideration of costs.

“Over more than a decade, EPA took costs into account at multiple stages and through multiple means as it set emissions limits for power plants,” Kagan wrote. “And when making its initial ‘appropriate and necessary’ finding, EPA knew it would do exactly that — knew it would thoroughly consider the cost-effectiveness of emissions standards later on.” Justices Sonia Sotomayor, Stephen Breyer and Ruth Bader Ginsburg joined in the dissent.

Cost-Benefit

EPA has said MATS compliance will cost electric utilities $9.6 billion annually but produce total benefits of at least $37 billion to $90 billion per year, while preventing as many as 11,000 premature deaths and 130,000 asthma attacks. It will also eliminate 5,700 hospitalizations and emergency room visits and 540,000 missed workdays, the agency said.

However, only a fraction of the benefits — $500,000 to $6.2 million annually — are directly related to cuts in mercury emissions. The remainder are “co-benefits” that arise not directly from reducing toxic emissions, but from reductions in particulate matter and carbon emissions expected to result from the standards.

EPA critics have said the agency has engaged in over counting, citing the same co-benefits to justify multiple EPA regulations.

Clean Air Act Amendments

The MATS regulations were initiated when Congress amended the Clean Air Act in 1990. The amendments ordered EPA to regulate 189 hazardous air pollutants, including mercury, arsenic and cadmium, which had not been previously controlled. (See MATS: 25 Years in the Making.)

“It is disappointing that a quarter century after the 1990 Clean Air Act amendments, Americans are still waiting on the first-ever limits on mercury from coal-fired power plants, the single largest source of these toxic emissions,” Ken Kimmell, president of the Union of Concerned Scientists, said in a statement.

Implications for Future Regulations

The ruling is a “groundbreaking administrative-law case,” Justin Savage, a partner at the law firm Hogan Lovells and a former Justice Department environmental lawyer, told the National Journal. “It essentially says that when a statute is ambiguous, an agency must consider costs.”

“After this decision, an agency would not want to walk into court saying, ‘Your Honor, we did not consider costs at all when deciding to take regulatory action on an issue,’” agreed environmental law professor Jonathan Adler of Case Western Reserve University.

Sean Donahue, who represents environmental and public health groups that supported EPA, told The New York Times that the ruling will require the agency “to do more homework on costs.”

“But I’m very confident that the final rule will be up and running and finally approved without a great deal of trouble. This is a disappointment. It’s a bump in the road, but I don’t think by any means it’s the end of this program.”

FBR Capital analyst Benjamin Salisbury told StreetInsider.com that the ruling could ultimately result in tougher regulations on mercury and toxic emissions. “EPA could resurrect MATS in a stronger form, given the ‘baseline’ EPA will observe includes less of the older, high-emission coal-fired plants and current units with more emission control than previously,” he said.

— William Opalka contributed to this article

NYISO, SPP: Reject Tx Developers’ Protests

By William Opalka and Tom Kleckner

NYISO and SPP told the Federal Energy Regulatory Commission last week it should reject transmission developers’ protests to their recent Order 1000 compliance filings.

NYISO said that LS Power and NextEra Energy made “inaccurate or misleading statements” in response to its filing, and that the protests raise issues outside of the proceeding and propose changes that would impair system reliability (ER13-102).

LS Power and NextEra filed their protests in response to the ISO’s April compliance filing. (See Tx Developers Challenge NYISO, SPP, ISO-NE Order 1000 Filings.)

LS Power said an incumbent transmission owner should be required to execute a development agreement if its regulated backstop solution is selected by NYISO as the more efficient or cost-effective transmission. “It is important that the developer agreement impose no more stringent obligations on the developer of an alternative regulated solution,” it wrote.

NextEra said the filing burdens alternative developers without guaranteeing faster project completion.

NYISO responded that the incumbents are already required to file a development agreement under Order 1000. The ISO said the language suggested by NextEra “would interfere with the existing requirements to timely identify and address potential project delays.”

SPP Protest

LS Power also filed a protest against SPP, which responded by saying its May 18 compliance filing fully complied with FERC’s directives.

The RTO said LS Power’s arguments were a “collateral attack” on Order 1000. “SPP has demonstrated full compliance with all of the regional transmission planning and cost allocation requirements of Order No. 1000” and FERC’s compliance orders, SPP said (ER13-366-006).

In April, FERC ordered SPP to submit a fourth compliance filing revising Tariff provisions pertaining to “‘rights of way where facilities exist.’” The commission said SPP must acknowledge that “retention, modification or transfer” of rights of way remain subject to state and local laws.

SPP said its proposal is “substantially similar” to FERC’s Order 1000 language and that LS Power failed “to demonstrate otherwise.”

LS Power said SPP should only invoke the right-of-way language when the relevant law expressly “prohibits” alteration of existing rights of way and there is only one “feasible route” for the transmission project that would alter a transmission owner’s use over its existing rights of way.

The RTO also said LS Power’s request “seeks to impose requirements on SPP not found in Order No. 1000 and not required by the commission in the SPP compliance orders or in other Order No. 1000 transmission planning regions.”

PJM: CFTC Order on SPP Undermines Exemption

By Tom Kleckner

PJM, ERCOT and CAISO have asked the Commodities Futures Trading Commission to remove language from a draft order that they say could undermine the broad exemptions the commission granted RTOs and ISOs in 2013.

The three grid operators filed joint comments last week concerning CFTC’s May 2015 draft order on a request from SPP seeking the same exemptions from the Commodity Exchange Act that the commission granted the six other RTOs and ISOs in 2013.

CFTC’s 2013 order exempted electricity transactions subject to tariffs approved by the Federal Energy Regulatory Commission from most provisions of the CEA while retaining its general anti-fraud and anti-manipulation authority over such transactions. SPP was the only grid operator not party to the 2013 order because its day-ahead market, the Integrated Marketplace, was not fully implemented until March 2014. (See CFTC Approves Dodd-Frank Exemption for RTOs.)

Private Rights of Action

The three grid operators said they are concerned that the CFTC draft order to SPP included, for the first time, a statement of its intent “to preserve private rights of action” under Section 22 of the CEA.

“Although the proposed exemption involves another RTO, the commission’s insertion … can be construed as a retroactive attempt to modify the ISO-RTO final order and, therefore, raises fundamental fairness and regulatory policy issues that potentially impact the ISO-RTO final order,” they said.

Although the text of the proposed SPP order does not preserve a private right of action, the preamble states that “[i]t would be highly unusual for the commission to reserve to itself the power to pursue claims for fraud and manipulation … while at the same time denying private rights of action and damages remedies for the same violations. …Thus, the commission did not intend to create such a limitation and believes the [2013 order and the proposed SPP order do not] prevent private claims for fraud or manipulation under the act.”

“In the draft order, the CFTC generally addressed whether private parties could bring actions against RTO/ISO market participants they allege to have manipulated energy products and markets, which had otherwise been exempted from CFTC regulation,” PJM said in a press release. “However, rather than clarifying the CFTC’s intent on private rights of action, the draft order is confusing and could increase legal exposure to RTO/ISO market participants.”

PJM said its concerns were heightened by a recent civil case in Texas arising out of market conduct in ERCOT, which it said “raised questions as to whether the CFTC intended to also preserve the ability for a private party to sue a market participant for alleged market manipulation.”

Regulatory Certainty

Exempting ISO and RTO transactions from private rights of action under the CEA is essential to avoiding conflicting or duplicative regulation and providing market participants with certainty about the regulatory treatment of the transactions, the grid operators said.

The three requested that CFTC “remove its proposed statement about private claims in the preamble language or conform it to the text of the proposed SPP order. Alternatively, the commission should defer any action on its statement of intent until after it has conferred with its fellow regulatory and enforcement agencies.”

SPP’s application to CFTC asked for an exemption from provisions of the CEA and CFTC regulations for transmission congestion rights, energy transactions and operating reserve transactions. CFTC issued its draft order May 18.

PJM, ERCOT and CAISO filed their comments June 22 after consulting with other ISOs and RTOs, FERC and industry trade groups.