PJM is reducing its load forecast for 2018 by 2.6%, due in part to a temporary change in modeling that aims to address over-forecasting in recent years.
Acknowledging criticism that its forecasts have overestimated economic growth and failed to capture energy efficiency and behavioral changes that have dampened demand, PJM officials will use a “binary variable” to reduce next year’s forecast.
“There are things outside our model that our model is not picking up,” PJM’s Andrew Gledhill told the Planning Committee last week in a briefing on its draft load forecast.
Before applying the variable, PJM was projecting a 1.5% reduction in its 2018 summer peak load compared with the projection it made last year.
In addition to reducing the forecast for summer 2018 — the delivery year for next year’s capacity auction — the draft report reduces the summer peak load forecast for 2015 by 4,716 MW (-2.9%).
Peak load for 2020, the next Regional Transmission Expansion Plan (RTEP) study year, was cut by 4,152 MW (-2.5%) versus last year’s projection.
Economist James Wilson, a consultant to consumer advocates, questioned the use of the binary variable, saying it overcorrects in the short term and results in too high a rate of growth in later years. “It’s not a very good approach,” he said.
PJM Vice President of Planning Steve Herling said the debate would soon be moot. “I’m less concerned about the long-term implications of [this year’s fix] because we’re not going to be doing it next year,” he said.
Wilson also questioned why forecasters continue to add years to their historical period instead of dropping some of the earlier years.
Wilson said the first four years of PJM’s 1998-2014 historical base was a period when peak demand was growing in about a 1-to-1 relationship with growth in PJM’s economic variable, an elasticity that hasn’t been seen since and which may not return because of increased energy efficiency and demand response.
“A better way to move the forecast in the right direction would be to drop some of those now-anomalous early years from the forecast period,” he said.
Gledhill said the data from those previous years remains valid. “When you start shortening the estimation period, you’re shortening the period where you can measure how load reacts to economics,” he said.
Direct Energy’s David “Scarp” Scarpignato backed Wilson’s argument. “Something’s changed that’s making that data way-back-when less useful in the forecast,” he said. “Do you really want more data points if some of the data points are garbage?”
Herling said a final forecast report will be presented by the end of this month.
The electric and natural gas industries remain divided over the start of the gas day, nine months after federal regulators proposed changing the start time from 9 a.m. CT to 4 a.m. CT.
On March 20, the Federal Energy Regulatory Commission issued a Notice of Proposed Rulemaking proposing the change to better align it with electric operations (RM14-2). The commission gave the North American Energy Standards Board six months to reach consensus among its gas and electric industry stakeholders. (See FERC: Six Months to Move Gas, Electric Schedules.)
But NAESB reported in September that the two sectors remained split, with the gas industry resisting any change in the start time. When the comment period on the NOPR closed at the end of November, there was no evidence of any change in the stalemate.
Thus it will be up to FERC to decide whether to change the start time over the gas industry’s objections.
Whether Chairman Cheryl LaFleur has the votes to force a change is unclear. The commission approved the NOPR on a 3-1 vote with LaFleur, Commissioner Philip Moeller and former Commissioner John Norris in support. Commissioner Tony Clark dissented, saying he wanted to give the industries more time to reach consensus before FERC “put its thumb on the scale” in favor of a change.
In their comments, stakeholders from both industries were largely supportive of other modifications proposed by NAESB.
Besides changing the start of the gas day, FERC proposed moving the deadline to schedule gas for the Timely Nomination Cycle from 11:30 a.m. CT to 1 p.m. CT and increasing the number of intraday cycles from two to four. NAESB’s proposals were similar: it proposed the same start time for the Timely Nomination Cycle, but it suggested moving the end time from 4:30 p.m. CT to 5 p.m. CT. NAESB also added one extra intraday cycle to the proposal, instead of FERC’s two.
But the standards board was unable to bring the two industries to an agreement regarding the gas day, with electric favoring the earlier gas-day start time so it more closely aligns with the electric day, and gas saying the time change is unneeded and may be disruptive to gas markets.
Battle Lines Remain in Place
In its late September filing detailing its modifications, NAESB said that stakeholders on the Gas Electric Harmonization Committee had narrowed 13 proposals to four, each containing identical cycle schedules but different gas-day start times.
“Despite forum participants casting over 13,000 votes on 56 different motions, no single proposal gained the supermajority support required of both [electric and gas] quadrants to reach consensus on a single proposal,” NAESB said.
The board instead left the start time question up to FERC, submitting a proposal with the provisions that had common agreement while replacing all references to the start time in the standards with a question mark.
While some stakeholders suggested minor alterations to NAESB’s proposed cycle schedules, they each fell into one of two camps when it came to the gas day start time.
“Changing the start of the gas day is unnecessary to achieve the commission’s objectives in this proceeding and could create unintended adverse consequences to the natural gas industry,” said the Natural Gas Council, which represents companies in all segments of the gas supply chain. In comments filed late last month, the council urged FERC to adopt NAESB’s proposed cycle schedules, which it said would address generators’ concerns over running out of gas toward the end of the gas day, as demand for electricity ramps up during the morning.
The council also noted the regional disparity between generators who wanted an earlier start time, with those on the West Coast siding with the gas industry in maintaining the status quo. The proposed change would mean a 2 a.m. PT start time.
“Disrupting the entire natural gas market by moving the start of the gas day would be an overwhelming undertaking,” the council said. “The commission should not require a change to the national gas day to address a problem that is more limited and regional in nature.”
RTOs, meanwhile, support the earlier start time.
“The current start of the gas operating day … requires electric generators to nominate gas over two electric days. Gas scheduled during the day-ahead Timely Nomination Cycle covers the evening peak of one electric day, and the morning electric ramp of the following electric day,” the ISO/RTO Council said in its comments. “Schedules for the second electric day, which correspond to the morning electric ramp, are not yet known when generators nominate gas. Moving the gas operating day to an earlier time would allow generators to nominate gas in the day-ahead Timely Nomination Cycle, i.e., the most liquid cycle, to cover the morning electric ramp and the evening peak of a single electric day.”
The IRC represents all nine RTOs in North America, including CAISO, which the council said also supported an earlier start time. A number of RTOs filed their own comments as supplements to the IRC’s.
“Moving the gas day to 4 a.m. CT or earlier, coupled with changing the Timely Nomination Cycle to 1 p.m. CT, will enable owners of gas-fired generators needed for the peak morning period to timely nominate and schedule gas supply to support their ability to generate electricity at the start of the morning peak,” said ISO-NE, which noted New England’s heavy reliance on natural gas and its past difficulties procuring it.
MISO and SPP also voiced their support for the earlier start time, with SPP also proposing an even later start to the Timely Nomination Cycle.
Representing Diverse Views
Some stakeholders stayed neutral in the start-time discussion, as their membership was too diverse and divided to take a position on either side of the issue.
In its comments, the Electric Power Supply Association, which represents players in both the gas and electric industries, said it supported NAESB’s modifications and that it could not support either start time because its members were divided. But it also noted that there was a broad consensus on one aspect of the start time.
“While there are EPSA members on each side of this issue in terms of the 4 a.m./9 a.m. debate, there is clear consensus that some other time between 4 a.m. and 9 a.m., or different times set for different regions of the country, is not acceptable or workable,” EPSA said.
The Edison Electric Institute, which represents U.S. investor-owned utilities, also refrained from taking a position on the gas-day, but did offer support for NAESB’s modifications. It also urged FERC, regardless of what it decides, to “provide the necessary lead time to ensure that the changes are made in a coordinated manner that maintains the reliability of both the electric and the natural gas systems.”
EEI recommended that FERC implement the changes during a “shoulder month,” preferably in the spring, when demand isn’t as high.
PJM’s new graduated queue-entry cost structure has not persuaded interconnection customers to file their requests earlier, PJM officials told members last week.
About 54% of the project applications in the queue that closed Oct. 31 (AA1) came in the final month, and 43% of those came in the final week — 26% on the final day — said David Egan, manager of interconnection projects. In the previous queue, before the fee structure was changed, 47% of applications came in the final month.
“This is not workable,” said Steve Herling, vice president of planning. “It hasn’t really improved with the changes we’ve made.”
Under the new structure, the deposit for applications filed in the first four months was set at $10,000; for the fifth month, $20,000; and for the last month, $30,000.
“I’m noodling on a method to fix this. That is going to be a proposal that we bring to better allow my group to handle it,” Egan said, inviting suggestions to incent early participation. “This is creating big chunks of work, and invariably things get dropped or missed.”
Projects totaling about 30,000 MW are currently under study, with another 19,000 MW under construction. Natural gas accounts for 80% of the total. PJM received 2,376 project applications in the queue. Of that, 23% are in-service and 172 agreements were terminated.
TO/TOP Matrix
Members approved Version 8 of the TO/TOP (Transmission Owner/Transmission Operator) Matrix, the result of an annual review. The document serves as an index between PJM manuals and North American Electric Reliability Corp. standards and creates no new obligations for PJM or its members.
U.S. Solicitor General Donald Verrilli will ask the Supreme Court to review an appellate court ruling voiding the Federal Energy Regulatory Commission’s authority over demand response in wholesale energy markets.
Verrilli said in a filing yesterday that Chief Justice John Roberts had granted his request to extend a Dec. 16 deadline for filing a petition for a writ of certiorari by one month. “The FERC orders that the court of appeals set aside in this case address an integral feature of the nation’s wholesale electric-power markets under FERC’s jurisdiction — the rules for participation by demand-response resources — that is of substantial importance to the proper functioning of those markets and to assuring just and reasonable rates for wholesale power,” Verrilli said in a Dec. 5 filing requesting the extension.
FERC Chairman Cheryl LaFleur welcomed Verrilli’s action. “I believe the commission’s ability to regulate demand response in wholesale electric markets is of vital importance,” she said in a statement. “Demand response contributes to reliability, sustainability and affordability of electric service.”
NEPGA Request
Verrilli’s action came last week as ISO-NE and others took sides in response to a request by generators that DR be eliminated from New England’s forward capacity market.
The generators said the request was warranted by the D.C. Circuit Court of Appeals ruling that vacated FERC Order 745, which set pricing rules for DR in wholesale energy markets. The ruling, which resulted from a challenge by the Electric Power Supply Association, was also cited in a similar challenge by FirstEnergy in PJM’s capacity market.
As of Friday, nearly 40 entities had sought to intervene in the New England docket, including power generators, demand response providers, consumer and environmental advocates, utilities, state regulators and commercial customers.
ISO-NE said the generators’ request is premature. “NEPGA’s suggestion that demand response simply be removed from the capacity market fails entirely to account for the continued benefits of demand response that currently participates in the wholesale market on the supply side, and the potential for structural and tariff adjustments to reflect these continued benefits.”
The New England Power Pool Participants’ Committee said ISO-NE must follow its filed rate and that NEPGA has not sought to utilize the stakeholder process to change it.
Demand response provider CPower said NEPGA’s complaint should be denied because it will make the capacity market less competitive, resulting in higher prices.
Public Service Enterprise Group was among those filing in support of the generators, saying the commission should prevent the ninth Forward Capacity Auction clearing prices from being distorted by resources that cannot lawfully participate in the auction. Commission action would avoid having to unwind the results of FCA 9 after the auction has run, PSEG said.
NEPGA asked FERC to issue an order by Jan. 15, two weeks before ISO-NE is set to begin its next FCA on Feb. 2.
The U.S. Department of Justice is investigating the interconnection process in PJM’s MAAC sub-region as part of its anti-trust review of Exelon’s $6.8 billion takeover of Pepco Holdings Inc.
PJM officials said last week they had received a request for documents regarding “each proposed generating facility or planned upgrade to an existing facility (300 MW and above) that filed a request with PJM to interconnect in the MAAC sub-region of PJM in the last 10 years.”
The request came just five days after the Federal Energy Regulatory Commission approved the acquisition, without discussion or conditions, at its Nov. 20 meeting (EC14-96).
The Justice Department appears to be investigating concerns previously raised by PJM’s Market Monitor, which said transmission owners may have a conflict of interest in conducting interconnection studies on competitors’ generation.
The request covers PJM and all members involved in the interconnection process. “If you are a transmission owner or generator owner in the MACC sub-region involved in generator interconnection queue requests 300 MW and above in the last 10 years, then you are an affected member,” Dave Anders, PJM director of stakeholder affairs, wrote in an email to members.
Of the more than 1,100 projects submitted in the last 10 years, about 245 of them are 300 MW or above and about 118 are in MAAC. The department wants those documents from all parties by Dec. 16.
“We’re just sending them all of our file cabinets,” joked Steve Herling, PJM vice president for planning, when asked about the request during the Planning Committee meeting last week.
Section 7 Inquiry
The Justice Department’s notice doesn’t detail why it is seeking the documents. The demand letter notes that it is seeking the documents “in the course of an antitrust investigation to determine whether there is, has been or may be a violation of Section 7 of the Clayton Act … by conduct, activities or proposed action” of the acquisition of Pepco by Exelon.
Section 7 prohibits a merger if “the effect of such acquisition may be substantially to lessen competition or to tend to create a monopoly.”
Exelon spokeswoman Judy Rader said the company has already provided the department with documents in connection with what she called “the DOJ’s review of our proposed merger, not a separate antitrust investigation.”
Interconnection Process
As in non-RTO regions, PJM’s transmission owners conduct the studies that determine what developers will need to spend to connect their generators to the grid without causing overloads or other reliability problems. PJM manages the queue process.
“The process is complex and time-consuming as a result of the nature of the required analyses. The cost, time and uncertainty associated with interconnecting to the grid may create barriers to entry for potential entrants,” the Independent Market Monitor noted in the State of the Market report for the third quarter of 2014. “The queue contains a substantial number of projects that are not likely to be built. These projects may create barriers to entry for projects that would otherwise be completed by taking up queue positions, increasing interconnection costs and creating uncertainty.”
PJM Assistant General Counsel Steve Pincus said PJM received a data request for Exelon’s acquisition of Constellation Energy. That deal closed in 2012.
This is the first time Pincus said he was aware of the department taking interest in the interconnection process.
FERC enforcement staff has investigated interconnection processes in other regions, such as the Southeast. There, independent generators complained that vertically integrated utilities outside of RTOs were using the process to thwart competition by delaying studies and requiring excessive spending on transmission upgrades.
“We think that our process, with the RTO’s independence, addresses those issues that existed in the past,” Pincus said.
IMM Still Has Concerns
Market Monitor Joe Bowring declined to comment yesterday on the department’s inquiry. But the Monitor has been recommending since 2013 that PJM outsource interconnection studies to an independent party to avoid potential conflicts of interest.
“Currently, these studies are performed by incumbent transmission owners under PJM’s direction. This creates potential conflicts of interest, particularly when transmission owners are vertically integrated and the owner of transmission also owns generation,” the Monitor said in the third-quarter report.
“There is also a potential conflict of interest when the transmission owner evaluates the interconnection requirements of new generation which is part of the same company,” the report added.
The Monitor also recommended last year that PJM establish a review process to ensure that projects are removed from the queue if they are not viable, and that commercially viable projects advance in the queue ahead of projects that have failed to make progress.
“DOJ issues these kinds of requests from time to time in large merger cases to gather more information to complete its investigation,” Rader said. “Exelon and PHI have already provided the DOJ with our documents related to this request, and now the DOJ is asking for similar information from other parties. Exelon and PHI will continue to work cooperatively with the DOJ as it conducts its review of our proposed merger.”
Not Routine
But D.C. energy attorney Carolyn Elefant, who has 25 years of experience in federal regulatory matters, sees it as anything but routine.
“It is very unusual,” Elefant said yesterday. “It does seem unusual for the Department of Justice to go right to the transmission organization, and also I am not quite sure why the Department of Justice didn’t raise these issues” with FERC, she said.
Elefant represents the Mid Atlantic Renewable Energy Coalition, one of the interveners in the Exelon-Pepco acquisition docket, but doesn’t represent any of the parties covered by the Justice Department document demand.
“I think it is fair to say that the Department of Justice either has concerns about the acquisition or concerns about FERC’s resolution,” she said.
FERC Approval
In September, FERC issued a notice that it had given permission for staff to communicate with the department.
In its Nov. 20 order, FERC indicated it did not have any anticompetitive concerns with the Pepco acquisition. (See FERC Approves Exelon-Pepco Merger.)
Dismissing concerns of market power, possible rate climbs and suppressed competition, the commission approved the pending acquisition without discussion. Its written decision made clear it didn’t see any market issues with the acquisition, in part because Pepco holds only a negligible amount of generation. “While the commission is aware that Exelon will be a member with more assets after the merger, there is nothing in the record of this proceeding to indicate Exelon will have excessive influence over the stakeholder process or the independence of PJM.”
FERC did not immediately respond to a request for comment yesterday.
PJM’s Board of Managers will file a proposal this week with the Federal Energy Regulatory Commission to increase the reliability expectations of capacity resources with a “no excuses” policy that would result in larger capacity payments and higher penalties for non-performance.
It includes a more gradual transition into the proposed new market design and increased benefits for high-performing generators than staff’s Oct. 7 proposal. The board’s changes are intended to blunt criticism that PJM’s plan was overly expensive and being implemented too quickly.
The proposal borrows heavily from ISO-NE’s “pay-for-performance” design, which won FERC approval earlier this year. PJM officials are hopeful that the eight changes made by the board in the proposal announced last week will blunt most of the criticism.
The changes would begin to take effect for the 2016/17 delivery year with full implementation in 2020/21.
What is PJM Proposing?
The proposal includes a new product called “Capacity Performance,” which would replace the current product (renamed Base Capacity). Resources that clear the capacity auction would be required to deliver energy when scheduled and dispatched by PJM during “compliance hours,” defined as any emergency procedure event requiring implementation of demand response or the loading of emergency capacity.
Each Capacity Performance resource must offer into the day-ahead energy market and be available for at least 700 hours of non-emergency operation in the delivery year.
PJM is proposing a “no excuses” approach similar to ISO-NE’s that eliminates “out-of-management control” exemptions.
The increased risks and rewards are intended to incent generators to introduce dual-fuel capability or sign firm natural gas delivery contracts to minimize their fuel delivery risk.
Intermittent and seasonal resources could satisfy Capacity Performance requirements with “coupled offers” in which they share the responsibility with one or more other resources.
Offer parameters would be limited to physical resource limits. During Hot or Cold Weather Alerts, resource notification time would be limited to one hour.
All resources must take steps to ensure they are available for scheduling with no more than a 14-hour lead time.
Performance Obligation – Each resource is required to deliver its pro-rata share of system requirements during Compliance Hours. The resource’s pro-rata share is calculated during Compliance Hours as the lesser of the resource’s cleared capacity megawatt quantity times the ratio of real-time demand plus reserves divided by PJM’s total quantity of cleared capacity megawatts and the resource’s economic dispatch point, net of any PJM-approved outages.
What Happens to Resources that Fail to Perform?
A resource that fails to deliver its full obligation will be assessed a penalty (“Performance Payment”) equal to the shortfall (in megawatts) multiplied by the performance payment rate.
Performance Payment Rate – The Performance Payment Rate is the Net Cost of New Entry (in $/MW-year) multiplied by the number of days per year and divided by the expected number of Compliance Hours per year.
Annual penalties would be limited to 1.5 times net cost of new entry, multiplied by the resource’s committed megawatts, multiplied by the number of days per year. Monthly penalties would be limited to the annual stop-loss divided by three.
Penalties collected from under-performing resources would be allocated pro-rata to all over-performing resources in the hour, including energy-only resources that perform during compliance hours. Performance payments would not be assessed during non-emergency hours.
Generation owners with multiple plants can avoid penalties by providing energy from non-capacity resources.
How much will it Cost?
PJM says the increased performance will result in increased monthly capacity costs of about $2 to $3 per household beginning in 2018, assuming average winter and summer weather. In a year of extreme weather, officials say, it would result in net savings because the increased capacity costs will be more than offset by reduced energy costs. The program would have saved $7 billion in 2014, according to a PJM simulation.
Andy Ott, executive vice president for markets, noted that only 10% of total billings are for capacity, while 80% is energy. “Even a modest change in the energy price will offset the capacity price” increase, he said during a press conference last week.
PJM would allocate costs to load based on total compliance hours for the year and the five coincident-peak hours. The current cost allocation is based on the current five-coincident-peaks alone. The cost allocation is based on actual, measured loads.
The offer cap for Capacity Performance product offers is equal to the net CONE. If a resource desires to offer above the net CONE, its offer is subject to cost-based-offer review per the current processes if it fails the three pivotal supplier tests.
When Will it Take Effect?
PJM hopes to receive FERC’s OK in time to begin implementing changes in May’s Base Residual Auction for delivery year 2018/19. (On Nov. 28, FERC approved changes to the capacity market parameters for the May auction with minimal changes. (ER14-2940))
PJM plans to procure an additional 2,500 MW of Base Capacity for winter 2015/16 and begin soliciting Capacity Performance resources for delivery year 2016/17 (60% of total capacity) and 2017/18 (70%) through incremental auctions. Capacity Performance will be acquired through the Base Residual Auction beginning with delivery years 2018/19 (80%) and 2019/20 (80%). Capacity Performance would be 100% of resources starting with delivery year 2020/21. (See table.)
What Happens to Demand Response?
The Capacity Performance plan does not include PJM’s proposal to eliminate demand response as a supply resource. The DR proposal, outlined in an Oct. 7 white paper, would make load-serving entities responsible for incorporating DR in reduced demand estimates. (See PJM DR Cos. Confident; Reject PJM EPSA Response.)
CEO Terry Boston said PJM should delay changes in its DR rules pending the resolution of a potential Supreme Court review of the D.C. Circuit Court of Appeals’ Electric Power Supply Association ruling voiding federal jurisdiction over DR compensation. (See related story, U.S. to Seek Supreme Court Review of EPSA Ruling.)
What has been the Reaction from Stakeholders?
RTO Insider requested comment on the plan from the spokespeople for the 15 coalitions that met with the Board in November.
EnergyConnect’s Bruce Campbell, representing the Advanced Energy Management Alliance, said PJM has not allowed adequate stakeholder review for what is a “substantial redefinition of capacity.”
“We anticipate significant unintended consequences as well as substantial increased costs with no particular promise of increased reliability,” Campbell said. “We are disappointed that what should have been a measured response to poor generator performance during last winter’s polar vortex events has evolved into a major reworking of PJM’s capacity market.”
The alliance said PJM should have proposed “more focused penalties for generator non-performance during actual emergencies similar to those demand resources have always accepted.”
Other coalitions either did not respond or said they needed more time to analyze the proposal.
Utilities and independent power producers said the Environmental Protection Agency should delay or eliminate the interim goals in its proposed carbon emission plan.
The EPA’s plan calls for a two-part goal structure for each state: an “interim” average goal over 10 years beginning in 2020, and a final goal that must be met by 2030.
Some companies and trade groups, while supportive of the general effort to reduce greenhouse gas emissions, criticized the goal schedule as inflexible. The plan calls for the majority of the overall cuts in its first years, forcing states to make decisions without “thoughtful implementation,” NRG Energy said in its comments.
“The EPA’s proposed rule provides great flexibility for how states can achieve the required CO2 reductions,” NRG said. “However, it offers hardly any flexibility on when to achieve them.”
The company said this would create the unintended consequence of hastily built natural gas plants as states struggle to quickly meet the interim average, lowering emissions but deepening the country’s dependence on fossil fuels and making it difficult for renewable sources to break into the mix.
The Edison Electric Institute, which represents investor-owned utilities, echoed NRG’s criticism.
“In order to satisfy the 10-year average goal, many states must achieve more than 50% of their 2030 emission-reduction goals by 2020; and 11 states — including Arizona, Arkansas, Florida and Minnesota — must achieve more than 75% of their 2030 goals by 2020,” the association said. “This effectively turns the 2030 goal into a 2020 goal for these states.”
“There is not sufficient time between now and 2020 for utilities and states to develop, plan, design and complete the infrastructure required to meet the interim goals as proposed,” EEI president Tom Kuhn said in a statement.
NRG suggested the EPA maintain its “strong” 2030 goal, but that the agency allow states to move toward that goal at their own pace.
Alternatively, the company suggested modifying the interim goal “so that states must meet one-half of the interim goal, on average, in each of the 10 years from 2020 to 2029, while also meeting the 2030 goal. This would allow each state to set a straight diagonal line glide path from 2020 to 2030, or a number of other trajectories that might better suit the state — including dramatic early reductions in any state that deems them prudent.”
Dominion Resources, while also signaling its support for reducing emissions, also urged the EPA to eliminate the 2020 interim goal but suggested allowing states to meet an interim 2025 target before fulfilling its 2030 obligations.
EEI, while questioning the plan’s legality, echoed these suggestions. “Eliminating the interim compliance goal and allowing states to determine their own reduction glide paths and milestones to achieve the 2030, or the early-action alternative 2025, goals as part of their compliance plans would provide states with real flexibility to preserve reliability and minimize costs to electricity customers.”
Regional Approach rather than State-by-State
Companies and groups also criticized the use of state boundaries as a means of setting compliance targets, noting that many utility service territories and RTO and NERC regions do not coincide with state lines.
EEI questioned the legality of state-wide goals.
“Nothing in section 111(d) [of the Clean Air Act] clearly authorizes EPA to set emission goals based upon a large, heterogeneous set of units aggregated across a state,” the EEI said. “Instead, for EPA to regulate CO2 emissions (or emissions of any other type of pollutant) from existing sources, the regulations should be based on the sources themselves — and on a standard of performance attainable by implementing measures at those sources — rather than an aggregation of sources that happen to be within a particular state.”
Janet McCabe, acting assistant administrator for the Environmental Protection Agency’s Office of Air and Radiation, said last week that the agency had met with more than 300 groups and received more than 1.6 million comments since releasing its proposed carbon emission rule in June. Here are a few samples.
Aluminum-maker Alcoa said states should be allowed to take into account the “measurable and verifiable” carbon reductions made by utilities and industrial power generators since 2005.
Alcoa points to its massive plant in Newburgh, Ind., where it installed more efficient turbines and sulfur scrubbers in the early 2000s.
Making additional improvements to energy efficiency would be cost-prohibitive today, Alcoa said. Thus, the company said the EPA should identify which existing units in the state have no cost-effective options to achieve a 6% unit heat rate improvement under building block 1.
“This correction also should be applied to the proposed CO2 standards for other states where heat rate improvements have already been implemented on the existing utility boilers,” said Michael Padgett, vice president of energy and carbon strategy at Alcoa.
Federal Energy Regulatory Commissioner Philip Moeller said market forces have already reduced greenhouse gas emissions by 10% below 2005 levels. But he said the EPA’s proposed rule “will dramatically interfere with America’s competitive market forces, perhaps resulting in even more greenhouse gases in the future.”
The EPA plan “seems to assume that a significant amount of new natural gas pipelines needed to fuel power plants, along with a similarly significant expansion of the nation’s electric transmission system will suddenly appear so as to meet the new demands,” Moeller continued. “Such an assumption ignores the very real challenges we currently have in expanding these categories of energy infrastructure.”
The Kentucky Chamber of Commerce was among the critics asserting that the EPA lacks legal authority for the proposed rule, which the agency plans to administer under section 111(d) of the Clean Air Act.
“The statutory language of Section 111(d) is the result of differing House and Senate versions of the language that were never reconciled in conference, but instead, were both signed into law. The House version prohibits existing sources from being regulated under Section 111(d) if those sources are already regulated under Section 112. The Senate version provides that unless a particular air pollutant emitted by an existing source is regulated by one of the other listed Clean Air Act provisions (e.g., Section 112), existing sources emitting that pollutant could be regulated under Section 111(d). Because the Senate version was classified as a conforming amendment and conforming amendments are considered procedural in nature, the House amendment controls.”
The Ohio Environmental Protection Agency said the EPA’s cost analysis is “flawed and radically underestimates the projected cost of electricity from this proposal.”
The American Coalition for Clean Coal Electricity said the EPA’s proposal “is based on flawed data and sets a dangerous legal and regulatory precedent that puts America’s energy and economic future in jeopardy. The problems associated with this legally questionable proposal are manifold and will result in needless harm to Americans’ pocketbooks and our economy at large.”
The Nuclear Energy Institute, which noted that nuclear power produces about two-thirds of all carbon-free electricity in the U.S., called the plan “fundamentally flawed.”
“EPA’s proposed rule … recognizes the importance of nuclear energy in reducing electric sector carbon emissions and attempts to create an incentive for states to preserve existing nuclear generating capacity. As proposed, however, the rule does not achieve that objective. In addition, the proposed rule creates a significant, inappropriate and inequitable penalty for Georgia, South Carolina and Tennessee, where new reactors are being built.”
The Natural Resources Defense Council said the EPA can achieve substantially deeper cuts in carbon emissions by accelerating the use of energy efficiency and renewable power. “The administration can make this good plan even better,” said David Doniger, director of NRDC’s Climate and Clean Air Program.
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.
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.
