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November 19, 2024

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RGGI: EPA ‘Building Blocks’ May Overlook Progress of Early-Action States

By William Opalka

The Regional Greenhouse Gas Initiative did most of the talking for states in the Northeast about the Environmental Protection Agency’s Clean Power Plan, as ISO-NE declined to file its own comments, instead signing on to those of the ISO/RTO Council.

RGGI, which established a carbon-reduction market with proceeds to benefit renewable energy and energy-efficiency programs, generally supported the EPA plan and suggested other areas of the country could follow its lead.

RGGI’s comments were signed by the utility regulators of its member states: Maine, New Hampshire, Vermont, Massachusetts, Rhode Island, Connecticut, New York, Delaware and Maryland.

The officials praised the EPA for recognizing RGGI as an acceptable compliance mechanism incorporating many of their recommendations into the proposal.

But the officials said the plan “may not adequately recognize the substantial progress already made by early-action states,” such as those in RGGI. They said it would be unfair for the agency to require early adopters to make the same kind of additional emission reductions as the states that did little or nothing.

RGGI states have already achieved a 40% reduction in regional carbon emissions from the electricity sector from 2005 levels, the states said.

The comments were intended as a group statement, with states able to provide additional observations.

Connecticut Department of Energy and Environmental Protection Commissioner Robert Klee responded to the EPA’s request for comments on using 2012 as the base year for reductions instead of 2005. He supported the later baseline.

“Between 2005 and 2012, we reduced gross CO2 emissions from the power sector by 23% and per capita emissions by 25%,” he wrote.

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PJM: EPA Clean Power Plan Should Include Reliability ‘Safety Valve’

By Suzanne Herel and Rich Heidorn Jr.

Like the ISO/RTO Council, PJM called for a reliability “safety valve” in the Environmental Protection Agency’s proposed Clean Power Plan to ensure that the final rule and state implementation plans include provisions for minimizing reliability impacts on the grid.

The idea is similar to a provision included in the agency’s mercury and air toxics standards (MATS). Such a safety valve might allow delaying a plant’s retirement until transmission upgrades can be completed.

PJM said its recommendations aim to ensure “overall reliability of the bulk power system” and promote regional coordination in grid operations while also respecting states’ rights to establish individual plans.

PJM also said EPA should:

  • Change aspects of the proposed rule that discourage regional coordination on implementation;
  • Include a measure to encourage coordination and consistency of compliance measurement and verification protocols;
  • Propose an approach for flexibility in the determination of “at-risk” nuclear units in a state; and
  • Clarify the term “under construction” in the EPA target-setting. PJM suggested that the term be tied to readily identified benchmarks.

The council also called on the EPA to expand its “glide path” flexibility proposal to allow for construction of gas pipelines and new electric system infrastructure.

PJM said the rule leaves little leeway for conditions arising during the 2020-2029 compliance period.

It suggested “case-by-case relief” in addressing a demonstrated reliability issue. That would allow a state or region to adopt a less strict averaging requirement if it met the 2030 compliance target and took affirmative steps to address the identified reliability issues.

PJM also proposed relief based on “triggering events” to allow for exceptions to meeting the state-specific average interim target.

In addition, it noted that the proposed rule does not define the term “backsliding.”

“Technically, retaining generators otherwise slated for retirement through ‘Reliability Must Run’ contracts, although limited and justified only for local reliability needs, could well be deemed ‘backsliding’ and thus in violation,” PJM said, noting that RTOs and federal and state regulators often are faced with making spot decisions on whether to allow a generator to run in this manner.

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NYISO: EPA Clean Power Plan Threatens Reliability for New York City

By William Opalka

The Environmental Protection Agency’s proposed Clean Power Plan threatens system reliability in New York City due to the city’s frequent dependence on local oil-fueled generators, NYISO said.

NYISO also said the plan fails to recognize significant progress that New York state has already made in reducing CO2 emissions.

But the majority of its comments filed with the EPA highlighted the unique circumstances of the largest city in the United States: a densely populated area with inadequate transmission capacity to move electricity from other regions of the state, forcing it to rely on smaller units within city limits that are often fueled by oil.

“A majority of the electric capacity within New York City is dual-fuel oil/gas steam-fired electric generating units. These units are critically important, both due to their location within the transmission constrained New York City area and because they possess dual-fuel capability that provides a needed measure of protection against disruptions in the natural gas supply system,” NYISO said in comments filed with the EPA.

The units run principally on natural gas but can switch to oil when supplies are constrained. That dual capability was crucial last winter when natural gas supplies in the Northeast became constrained during the worst cold snaps.

Building Blocks

NYISO said the so-called “building blocks” in the EPA’s plan wrongly assume that output from these facilities could be reduced by more than 99%. Reliability would be compromised under the timeline contemplated by the plan, according to NYISO.

NYISO’s recommendations include:

  • A review of reliability impacts using a preliminary assessment already done by the North American Electric Reliability Corp. The Federal Energy Regulatory Commission also should be involved in this review to assess both the reliability and other issues that fall within its jurisdiction.
  • Formalization of a reliability “safety valve” by which the implementation of a state plan could be adjusted, with new time frames that may be caused by unforeseen circumstances.
  • Adjustments to the building blocks to produce a target that accurately reflects how power is generated, transmitted and used in New York. This would include elimination of the heat-rate improvements assumed in building block 1.
  • EPA adoption of a rate-to-mass conversion method that supports regional efforts, like the Regional Greenhouse Gas Initiative, that harness market forces.

The grid operator also said New York has not been given credit for emissions reductions already achieved or for its plans to further reduce carbon emissions.

“New York has already reduced CO2 emissions from its power sector by 41.6% below 2005 levels and generates approximately 53% of the electricity it uses on an annual basis from non-emitting resources,” NYISO said.

Its commitment under the nine-state Regional Greenhouse Gas Initiative calls for further carbon reductions by 2020.

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MISO, SPP: EPA Clean Power Plan Threatens Reliability, Needs Longer Compliance Schedule

By Chris O’Malley

SPP and MISO warned of a reliability crisis if the Environmental Protection Agency’s proposed Clean Power Plan isn’t eased to account for up to 134 GW of generation retirements by 2020, most of them coal-fired units.

“Unless the proposed CPP is modified significantly, SPP’s transmission system impact evaluation indicates serious, detrimental impacts on the reliable operation of the bulk electric system … introducing the very real possibility of rolling blackouts or cascading outages that will have significant impacts on human health, public safety and economic activity,” SPP CEO Nicholas Brown said in his comment to the EPA.

SPP said it conducted a study that assumed new generation was added without additional transmission infrastructure. The model showed that portions of the system in the Texas panhandle, western Kansas and northern Arkansas “were so severely overloaded that cascading outages and voltage collapse would occur and would result in violations of [North American Electric Reliability Corp.] reliability standards,” Brown said.

NERC has expressed similar concerns, commenting that “developing suitable replacement generation resources to maintain adequate reserve margin levels may represent a significant reliability challenge, given the constrained time period for implementation.”

NERC’s 2014 Long Term Reliability Assessment said that plant retirements and limited capacity additions are contributing to diminishing reserve margins in the Midwest, New York and Texas.

SPP said its reserve margins, now at 13.6% above peak demand, would fall to 4.7%, or a reserve margin deficiency of about 4,600 MW, by 2020.

MISO: ‘Untenable and Infeasible’

MISO proposed that the EPA eliminate the interim 2020 performance requirements because the organization’s initial analysis of the rule shows that nearly 80% of total emissions reductions must be met by then.

The EPA’s performance requirements create “an untenable and infeasible timeline for reliable compliance, and would cause states and MISO member companies to make decisions on a severely truncated timeline,” MISO CEO John Bear warned.

Bear said it will take more time to build new generation, natural gas pipelines and other necessary facilities than the interim period allows. Bear pointed to MISO’s Multi Value Projects, which were driven by state public policy requirements such as renewable energy.

The MVP portfolio took five years of planning and shareholder discussion, and even now many of the projects are in development, regulatory and construction phases, he said.

Bear said the soonest a state compliance plan could be approved is 2017, adding that it may not be until 2019 that some states iron out a compliance strategy.

“Since action will be needed by 2020 to achieve the interim emissions performance levels, there will not be nearly enough time to plan for the replacement capacity, transmission upgrades and natural gas delivery infrastructure that will be required to maintain reliability and resource adequacy,” he said.

MISO asked the EPA to push back its proposed carbon dioxide reduction requirements, estimating that 11 GW of plant retirements in its region would need to occur in 2020, “well before sufficient replacement capacity can be placed into service.”

Bear warned that MISO’s planning reserve margin is already under pressure because 10 to 12 GW of coal-fired generation capacity will retire by 2016 to meet the agency’s Mercury and Air Toxics Standards (MATS).

The erosion of the reserve margin increases the likelihood that MISO will need to manage periods of high demand with “emergency operation procedures,” Bear said. “The probability of a loss-of-load event becomes greater than the MISO region has ever experienced.”

Under the “best circumstances,” new generation capacity would not be available until 2024, Bear told the EPA.

Technical Conference Sought

SPP seeks a series of technical conferences jointly sponsored by the EPA and the Federal Energy Regulatory Commission that would focus on the plan’s effects on regional markets and power system reliability. It wants NERC to conduct a “detailed, comprehensive and independent” study of the North American bulk power system, prior to the agency adopting its final rule.

SPP also wants to see the CPP compliance schedule extended by at least five years.

Some commenters, including the Kansas Corporation Commission, told the EPA that the plan is “extremely flawed” and requested that it be withdrawn for a system of emissions reduction that is less complicated and ensures reliability at a reasonable cost.

The KCC said Kansas has approved more than $3 billion of environmental compliance projects for coal-fired generating plants. “To avoid stranded ratepayer investment, specific coal-fired units that were retrofit in compliance with EPA rules should be excluded from the EPA’s calculations in determining a CO2 emissions goal.”

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RTOs Raise Concerns over Reliability, Schedule in EPA Clean Power Plan

PJM, MISO, SPP and NYISO joined a chorus of critics last week in warning that the Environmental Protection Agency’s proposed carbon emission rule threatens grid reliability, saying the agency should provide more time to build the generation, transmission and natural gas pipelines needed to comply.

At the same time, officials in New England and elsewhere complained that the EPA’s Clean Power Plan does not give enough credit for carbon emission reductions that have already been accomplished.

The critiques were among more than 1.6 million comments filed with the EPA before a Dec. 1 deadline.

SPP warned of rolling blackouts while NYISO said the plan ignored New York City’s reliance on oil-fired generation. PJM, MISO, NYISO and the ISO/RTO Council called on the agency to add a reliability “safety valve.”

Sen. Lisa Murkowski (R-Alaska), who will likely become chairman of the Senate Energy and Natural Resources Committee under a Republican majority next year, and House Energy and Commerce Committee Chairman Fred Upton (R-Mich.) last month called on the Federal Energy Regulatory Commission to convene a technical conference to address reliability concerns.

Some congressional Republicans have threatened to use oversight hearings and appropriations bills to blunt the rule. But lacking a veto-proof majority, the GOP is unlikely to block President Obama’s signature environmental initiative. (See GOP Election Victories Unlikely to Thwart EPA Carbon Plan.)

The proposed rule would require states to devise plans to cut existing power plant carbon emissions from 2005 levels by 30% by 2030, with intermediate goals along the way.

The EPA signaled in October that the final rule, due in June 2015, may relax the interim targets. (See EPA Signals Flexibility on Interim Carbon Targets, Coal-Gas Shift.)

RTO Insider has a roundup of the comments by RTOs, state officials, utilities, trade groups and environmental organizations:

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PJM Board Releases Capacity Performance Proposal

By Rich Heidorn Jr.

PJM’s Board of Managers today announced a final Capacity Performance plan that includes a more gradual transition into the new market design and increased benefits for high-performing generators than staff’s Oct. 7 proposal.

The board’s proposal will be submitted next week for Federal Energy Regulatory Commission approval. PJM hopes to receive FERC’s OK in time to begin implementing changes in May’s Base Residual Auction for delivery year 2018/19.

The board’s changes are intended to blunt criticism that PJM’s plan was overly expensive and being implemented too quickly. On Oct. 28, 14 coalitions representing more than 80 stakeholders submitted their critiques via briefing papers to the board. Eight of the groups generally opposed the proposal while six were generally supportive. (See Coalitions Make Their Cases to PJM Board.)

In a late afternoon press conference today, Executive Vice President for Markets Andy Ott said the changes would provide an “insurance policy” at a cost of about $2 to $3 per month per household when it is implemented in 2018.

“Many of the issues raised during this five-month discussion of Capacity Performance are not unique to the PJM region,” PJM CEO Terry Boston said in a letter to stakeholders outlining the board’s revisions. “PJM is modeling its approach after the ‘Pay for Performance’ capacity market design that FERC recently approved for ISO-NE, along with changes in the transition period that allow time for market participants to adapt and to lessen cost impacts. This design also allows for greater opportunities for all resources to participate in this enhanced capacity market.”

Changes Detailed

The board made the following eight changes to PJM staff’s Oct. 7 proposal, saying it would “improve the balance between the cost of infrastructure improvements and the benefits of reliability”:

  1. Revises the performance requirement, incentive and payment structure to one similar to that approved by FERC for ISO-NE.

 

Penalties (or “performance payments”) from under-performing resources will be allocated to over-performing generators, including energy-only resources that provide energy during emergencies. The change will allow intermittent resources and non-capacity resources to earn additional revenue.

 

  1. Adopts a “no excuses” approach to performance requirements except for retention of the exemption for resources following PJM scheduling and dispatch instructions.

 

PJM says this will ensure generators invest in maintenance and fuel security — such as obtaining dual-fuel capability — to avoid penalties. “This approach appropriately assigns performance risk to capacity suppliers who are in the best position to manage the risk,” PJM said.

 

  1. Reduces the volumes and capabilities of capacity to be procured during the 2015-2018 transition period.

 

“This will reduce transition costs but still maintain reliability through the transition period,” PJM said.

 

  1. Expands opportunities for intermittent resources by allowing them to submit “coupled” resource offers.

 

  1. Eliminates the multi-year pricing mechanism.

 

The board said it made the change based on concerns that the mechanism — intended to reduce risk for multi-year investments in the single-year market structure — could result in “pricing anomalies and perverse incentives.” The board said the issue would be addressed separately.

 

  1. Modifies cost allocation for Capacity Performance to include all “compliance hours,” defined as any period when PJM implements emergency procedures requiring implementation of demand response or the loading of emergency capacity.

 

PJM said the change, based on discussions with its Independent Market Monitor, would maximize market efficiency and encourage year-round DR.

 

  1. Maintains DR as a supply-side resource, for now.

 

PJM said it will address uncertainties over DR’s role in wholesale markets — the result of an appellate court ruling voiding federal jurisdiction over DR compensation — in a separate proceeding.

 

Ultimately, DR would be adapted to become a peak shaving commitment, modeled on the load side.

 

Limited DR would be eliminated; annual DR would be converted to a Capacity Performance product, and summer DR would be treated as Base Capacity during the transition period.

  1. Promises to adjust the forward load forecast to address concerns that overly bullish demand predictions had caused the RTO to procure more capacity than needed, at additional cost to consumers.

 

The promise is part of the proposal to eliminate the short-term resource procurement target, a 2.5% “holdback,” which the Market Monitor says can result in price distortions.

 

By recognizing the “recent trends and impacts of energy efficiency,” the 2.5% holdback will no longer be necessary, PJM said.

Transitional Period

The board acknowledged stakeholder concerns that it might not be possible to begin requiring enhanced performance for winter 2015/2016 due to the short time available for investment in winterization, dual-fuel capability and firm-fuel contracts.

Instead, it said it would seek to procure up to 2,500 MW of additional “base” capacity — the current product definition — for December 2015 through March 2016.

For the 2016/17 delivery year, PJM proposes an auction to procure a “transitional version” of the Capacity Performance product with lower prices and nonperformance penalties than when the transition is complete. “If a resource that already has [a capacity] commitment for the delivery year clears as Capacity Performance, the Capacity Performance commitment replaces its previous commitment,” PJM said.

This transitional version of the product would make up 60% of total capacity. For the 2017/18 delivery year, Capacity Performance would increase to 70%, while in 2018/19 and 2019/20, PJM proposes 80% of total capacity be fulfilled by the new product.

Beginning in 2020/2021, all capacity would be obtained under the Capacity Performance rules.

“During the transition, Base Capacity would retain the same rules as the current annual capacity product except that the peak performance penalty structure would replace the peak forced outage metric that is currently used,” PJM said.

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FERC Nixes Gov’t Veto Power from NERC Physical Security Standard

By Michael Brooks

The Federal Energy Regulatory Commission gave final approval to a North American Electric Reliability Corp. standard on physical security without a provision that would have given FERC and other government agencies the ability to overrule transmission owners’ definition of “critical” facilities.

In its final order (RM14-15), FERC said it dropped the veto proposal in response to criticism that the term “applicable governmental authorities” was too vague, making the standard impractical to enforce. Many also called it redundant, as FERC’s power to enforce NERC reliability standards would already ensure coverage of the most critical facilities.

“We are persuaded by commenters that the [Notice of Proposed Rulemaking] directive would present NERC, as the entity that would have to develop the proposed modification, and the commission, which would have to approve any NERC proposal, with a number of substantial policy issues,” FERC said.

The NOPR said the commission and “other appropriate federal or provincial authorities” should have the ability to add or remove critical facilities. The NOPR was issued under pressure from members of Congress alarmed by the 2013 sabotage of a Pacific Gas and Electric substation. (See FERC: We’ll Have Last Say on Sabotage Rules.)

The reliability standard (CIP-014-1) requires that transmission owners and operators perform risk assessments to identify transmission stations and substations “that, if rendered inoperable or damaged, could result in widespread instability, uncontrolled separation, or cascading within an Interconnection.” Operators of such facilities will be required to conduct an evaluation of the physical threats posed and report on how they are addressing them.

“While the rule does not go as far as some would like, it is still a step in the right direction,” Commissioner Norman Bay said last week. “It’s my hope that registered entities have already begun the process of doing risk assessments and engaging in planning.”

FERC OKs NERC 5-Year Performance Assessment

FERC last week also accepted NERC’s second performance assessment, which the organization is required to file every five years. The commissioners praised NERC for its work in ensuring reliability, but they also said there was room for improvement.

In its order, FERC directed NERC to submit a report on its work to improve the coordination among the regional entities, as well as an analysis of repeat reliability violations by companies.

Chairman Cheryl LaFleur said FERC’s approval of the assessment “reflects the commission’s continued confidence in the work of  NERC and the regional entities in strengthening the reliability of the bulk power system. At the same time, it appropriately challenges NERC and the regional entities to further strengthen their efforts.”

The commission also gave preliminary approval to NERC’s revised Real Power Balancing Control Performance Reliability Standard (RM14-10). The standard (BAL-001-2), which applies to balancing authorities and regulation reserve sharing groups, is designed to maintain Interconnection frequency within predefined limits.

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PJM Traders Continue to Shun UTCs on Uplift Fears

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Up-to-congestion trading volumes in PJM have dropped by about 85% since September, after the Federal Energy Regulatory Commission said it might make the transactions liable for uplift assessments.

The average volume of cleared up-to-congestion trades had increased 22.5% in the first three quarters of 2014, compared to the first nine months of 2013, according to the Independent Market Monitor’s third-quarter State of the Market report.

But the growth came to a halt Sept. 8, the effective date set by FERC for any uplift assessments.

Market Monitor Joe Bowring told the Members Committee webinar last week that traders appear to have begun limiting their UTC trades to the most profitable paths, as average profits have increased from $0.02 per MW in the two months before Sept. 8 to $0.94 per MW in the two months after.

Before the FERC ruling “you could make money and have a very small margin with large volumes,” Bowring said.  Now, he said, traders are shunning less profitable trades that they fear will be net losers if uplift assessments are applied.

FERC ordered a Section 206 proceeding to determine whether PJM is improperly treating UTCs differently than INCs and DECs in the interpretation of a forfeiture rule and in the application of uplift charges. (See UTC Trading Falls Following FERC Order.) FERC has scheduled a technical conference on the issue for Jan. 7.

The Monitor’s quarterly report said the reduction in UTC trading has not resulted in “negative impacts … and there have been some positive impacts.” Day-ahead and real-time binding constraint hours have fallen sharply since Sept. 8.

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Task Force Proposed to Resolve Inconsistencies in PJM Governing Documents

By Suzanne Herel

PJM is planning an effort to identify discrepancies among its governing documents, an initiative prompted by a lawsuit that officials say could have harmed the RTO’s credit rating and increased its insurance costs.

At last week’s Markets and Reliability Committee meeting, General Counsel Vince Duane presented the first read on a problem statement to create a Tariff Harmonization Senior Task Force to review what he called “legal boilerplate” provisions regarding definitions, indemnification, limitation of liability and alternative dispute resolution procedures in the Tariff, Operating Agreement, Reliability Assurance Agreement and Manual 35.

“Sometimes they should be the same; sometimes they should be different,” he said.

Duane said the inconsistencies came to light when counsel examined the documents in connection with a lawsuit brought in 2008 by PPL electrician Marlin Yorty, who was severely burned while working at a substation on the Juniata-Conemaugh 500-kV transmission line.

In October 2013, the Pennsylvania Superior Court ruled that PJM was not responsible for Yorty’s injuries because it was protected by a Federal Energy Regulatory Commission tariff that superseded state law.

“We began looking at the provisions more carefully in the legal department and found inconsistencies and vulnerabilities,” Duane said.

Separately, the MRC approved non-substantive revisions to definitions in the Tariff, Operating Agreement, Reliability Assurance Agreement and Manual 35. The changes are intended to align the documents.

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PJM Independent Transmission Cos. Win Concession on Project Evaluation Fees

Transmission upgrades of $20 million or more and all “greenfield” transmission proposals will be charged a $30,000 fee under an Operating Agreement revision approved by the Members Committee Thursday.

The proposal by LS Power was approved by an 84% sector-weighted vote after an earlier proposal by the Regional Planning Process Task Force, which would have charged only greenfield projects, fell short of a two-thirds majority. The task force’s proposal was approved by the Markets and Reliability Committee in October. (See PJM Members Approve $30K Fee on ‘Greenfield’ Tx Proposals.)

The result is a victory for LS Power and other nonincumbent transmission developers, who contended it was unfair to charge greenfield projects only.

PJM officials said that upgrades by transmission owners typically did not require the intensive engineering analysis that the fee is intended to pay for. “There is virtually no cost in evaluating these proposals,” said Steve Herling, vice president of planning.

The fee will be re-evaluated after a two-year trial.