PJM won stakeholder approval of its short-term plan for capturing reserve costs in energy prices after agreeing to a sunset provision that won over load representatives.
The Markets and Reliability Committee initially rejected PJM’s plan by a 49-64 vote, with only a single vote from End Use Customers and none from Electric Distributors.
The committee then approved by an 87-4 margin an alternative proposed by Direct Energy’s David “Scarp” Scarpignato that would sunset the plan on Sept. 30, with PJM filing a proposed long-term solution with the Federal Energy Regulatory Commission Oct. 1. Later in the meeting, the MRC also approved a problem statement on the long-term solution.
The Market Implementation Committee had approved the PJM proposal — which is intended to reduce uplift costs — by a more than 2-1 margin last month. The approval came despite concerns it would unfairly penalize load and could increase overall costs. (See PJM Reserve Proposal OK’d Despite Misgivings.)
Critics repeated those concerns at the MRC meeting Thursday. Scarp said that by putting the cost of reserves into LMPs, which are borne by load only, the proposal violated cost-causation principles. “Generators failing to start, at least today, they pick up some of that” cost, he said.
Ed Tatum of Old Dominion Electric Cooperative agreed. “We feel that we’re rushing into a solution that will have dire unintended consequences,” he said. “All of the sudden load is going to start picking up [the cost of] operational problems.”
Tatum also questioned how such a significant change could be accomplished by only a manual change, rather than a Tariff change that would require FERC approval.
Harry Singh of Goldman Sachs acknowledged that the increase in LMPs is likely to exceed the uplift costs because marginal costs are higher than average costs. But he said the LMP costs can be hedged, unlike uplift.
After the first vote failed, members quickly coalesced around Scarp’s proposal, for which he had been building support for weeks.
The sunset proposal “moves the ball forward,” Executive Vice President of Markets Andy Ott said. “It gives us a chance to evaluate the impact [of the change] during the summer. It’s a workable way forward while still respecting the concerns raised.”
Plan Described
PJM’s short-term plan would increase day-ahead and real-time reserve requirements when Hot- or Cold-Weather Alerts or Max Emergency Generation alerts are issued for the RTO or for either the Mid-Atlantic-Dominion or Mid-Atlantic regions.
The adder for day-ahead reserves would be set at 3% of forecasted load, boosting reserves from 6.27% to 9.27%. The real-time reserve adder would be equal to the default Mid-Atlantic-Dominion synchronized reserve requirement of 1,300 MW.
The increased reserves would be reflected in market clearing engines, ensuring that the costs go into locational marginal prices and not uplift.
Long-Term Solution Sought
The MRC also approved a problem statement and issue charge giving the Energy and Reserve Pricing and Interchange Volatility (ERPIV) stakeholder group authority to develop long-term solutions to the problem, which would likely involve Tariff changes and revisions to PJM software. The expansion of the ERPIV charter passed by acclamation.
Stakeholders last week approved new rules designed to ease the way for public policy transmission projects, but Maryland regulators said the “multi-driver” approach may be irrelevant because of parallel cost allocation rules proposed by PJM Transmission Owners.
The Markets and Reliability Committee Thursday approved Operating Agreement and Tariff revisions that envision two types of multi-driver projects:
The “incremental” method would be used when the multi-driver project was developed as a result of a single driver, such as reliability or market efficiency, but is modified to satisfy one or more other goals and becomes a more cost-effective solution to all of the drivers. Under the TOs’ proposal, the original driver would have its cost allocation reduced by “an amount equal to the ratio of the estimated incremental cost of the new driver(s) to the estimated new total cost of the project multiplied by the estimated cost of the original driver.”
The “proportional” method would be used when the multi-driver project is developed in parallel with individual solutions to different drivers and then combined. The TOs would allocate costs based on the relative costs of the individual projects that would have been required to address each driver alone.
Stakeholders won’t get a vote on the TOs’ proposal, although the TOs are accepting comments on the plan through June 6. The opportunity for opponents to challenge the proposal will come after the TOs make a Section 205 filing seeking Federal Energy Regulatory Commission approval.
“We are one of those who are very concerned with the TOs’ cost allocation” proposal, Walter Hall of the Maryland Public Service Commission told the MRC. Hall said the OA and Tariff changes approved Thursday “may become much ado about nothing” because the TOs’ cost allocation may make public policy projects too expensive to pursue.
John Farber of the Delaware Public Service Commission said that PJM, which will administer the cost allocation process, should use a case-by-case approach for evaluating the relative benefits rather than the “formulaic, rigid approach” envisioned under the TOs’ plan.
Steve Herling, vice president of planning, said Farber’s proposal was unworkable. Cost allocation “has to be formulaic,” Herling said. If the RTO did evaluations project by project, “we’d spend all our time doing cost allocation,” he said.
The states say the rules being drafted by the TOs differ from those outlined by PJM last year.
In a presentation to the Regional Planning Process Task Force (RRPTF) in August, the incremental approach envisioned public policy projects being allocated only the costs added to the proposal to accommodate the public policy needs. For example, if a $250 million project originally designed for reliability and market efficiency grew to $600 million as a result of the public policy needs, public policy would be apportioned only the $350 million additional cost.
Under the current TO proposal, however, the original drivers would receive a credit for some of their costs, with public policy paying more than just its incremental increase.
For example, if a $300 million reliability project expanded to $400 million to accommodate public policy, the public policy would be allocated $175 million — the incremental $100 million plus an additional $75 million based on the ratio of the incremental cost to the total cost. The costs allocated to the reliability portion would be reduced from $300 million to $225 million. (See chart)
Businesses with up to 100 kW in annual peak demand will be exempt from the new 30-minute notice rule for demand response providers under a compliance filing yesterday by PJM.
In approving the new “operational” DR rules last month, the Federal Energy Regulatory Commission ordered PJM to add small commercial customers to the list of those eligible for a “mass market” exemption from the requirement that they respond within 30 minutes of notice (ER14-822). (See PJM Wins on DR, Loses on Arbitrage Fix in Late FERC Rulings.)
PJM told the Markets and Reliability Committee Thursday that it planned to file changes to Manual 18 that reserved the exemption to businesses with less than 20 kW of annual peak demand. PJM said 20 kW is the threshold FERC has used to define “small commercial.”
Representatives of the Maryland Public Service Commission and Pepco Holdings Inc. said such a low threshold could cripple current and planned demand response programs for small businesses.
Walter Hall of the Maryland PSC said the 20-kW cut-off would force 30% of commercial customers in his state to drop out of the DR program. Hall said the threshold should be increased to at least 100 kW, adding that the PSC would contest the issue before FERC.
Gloria Godson
Gloria Godson of Pepco said PJM should look to the rate classes set in state tariffs for guidance in setting the threshold. The 20-kW limit “is not going to work,” she told PJM officials. “Your approach is really very constraining.”
GT Power Group’s Dave Pratzon, however, said that “PJM is being entirely appropriate in setting these limitations.
“A 100-kW customer — or a 350-kW customer, as suggested at another meeting — is nothing like a small C&I.”
PJM made no commitments to changing the threshold at the meeting. But in its compliance filing yesterday, the exemption limit was increased to 100 kW.
A change to PJM’s Regional Practices in response to a FERC directive sparked an exchange between Market Monitor Joe Bowring and consultant Roy Shanker.
In April, FERC ruled that PJM’s scheduling rules did not fulfill Order 764, which requires transmission providers to offer scheduling at 15-minute intervals. The order is intended to remove barriers to wind and other variable energy resources. (See FERC Rejects PJM Schedule Rules.)
Roy Shanker
FERC took issue with PJM’s practice of requiring that interchange transactions have a minimum duration of 45 minutes. The commission said the practice was inconsistent with Order 764 because it does not allow a generator to schedule for less than three consecutive 15-minute intervals.
PJM implemented the 45-minute rule in 2008, after MISO officials determined that nearly 60% of intra-hour schedules between MISO and PJM occurred in the final 15 minutes of the hour. PJM said the trading was the result of market participants’ ability to “predict with relative certainty the direction of the price separation between the two RTOs.” PJM said this resulted in interchange spikes of up to 1,000 MW — increasing uplift charges because of the need to balance the generation swings.
With FERC rejecting the restriction, Shanker said PJM and the Market Monitor should clarify the circumstances under which trades made in the last 15 minutes of the hour would be subject to enforcement action. Shanker said failing to create a “safe harbor” for traders would leave them unfairly vulnerable to “subjective judgment.”
“It is not acceptable to put market participants in this position,” Shanker said. “Some profitable transactions in the last quarter of an hour are OK and some are not? Who’s to tell?”
Among Shanker’s clients are Powhatan Energy Fund, which has mounted a public campaign in response to a FERC enforcement action over up-to congestion transactions. Shanker said FERC was incorrect in describing the company’s transactions “wash” trades. (See PJM Trader Calls FERC on Manipulation Probe.)
Executive Vice President for Operations Mike Kormos said PJM was making the rule changes to comply with the FERC order. Whether transactions are referred to FERC “will be Joe’s decision,” Kormos said.
Bowring said he wanted to retain the ability to review such trades for manipulation. “It is possible to game the market while following the rules,” he said.
No Debate
The MRC endorsed the following changes without debate:
Manual 36: System Restoration: Annual update of manual as required by NERC Standards EOP-005-2 (R3) and EOP-006-2 (R3).
Manual 03: Transmission Operations: Updates to special protection schemes, operating procedures, etc.
Manual 28: Operating Agreement Accounting: Changes resulting from the Settlements Formulation Review project — including revisions regarding calculation of regulation lost opportunity cost credits during shoulder hours — and other clean-up items.
Manual 18: PJM Capacity Market: Revisions developed by the Demand Response Subcommittee that would allow a curtailment service provider to add additional MWs as “existing” for offer into RPM auction through an exception process, if the nominated amount on the registration is low because the peak load contribution is low due to a load data anomaly. The current process does not allow for exception for one-time events such as power outages or major equipment failure.
Manual 33: Administrative Services for the PJM Interconnection Operating Agreement: Sets forth rules for communicating with electric distribution companies and reallocating load reallocation due to defaults by load serving entities. (See PJM Considers New Rules on Defaults.)
Exelon shareholders shed no tears last week over the news that five of the company’s nuclear units failed to clear PJM’s base residual auction.
In fact, analysts say the company will earn almost $150 million more in capacity revenue from planning year 2017/18 than it would have if all of the company’s capacity had cleared: The additional supply would have reduced the clearing prices.
Exelon confirmed that its Oyster Creek plant in New Jersey, as well as Byron Units 1 and 2 and Quad Cities Units 1 and 2 in Illinois, failed to clear the auction. Other plants that may not have cleared include two NRG coal-fired plants in Maryland, Chalk Point and Dickerson. (See related story, Capacity Results: Who’s in, Who’s Out?)
Prices cleared at $120/MW-day for most of PJM, doubling the RTO-wide clearing price of $59 for planning year 2016/17. Other owners of generation within PJM also benefited from the higher capacity prices, as total capacity revenues will increase from about $3.6 billion in 2016/17 to $7.3 billion in 2017/18.
Investors responded by bidding up shares of Exelon, FirstEnergy, PPL and NRG Energy by more than 5% last week, with Exelon leading the pack with a gain of 7.85%.
Meanwhile, the failure of Exelon’s nuclear plants to clear allows the company to continue making its case for changes to the capacity market rules that would benefit nuclear plants. FERC and PJM officials have indicated support for a “firm-fuel premium” or “clean” energy portfolio standards to ensure nuclear plants’ continued operation.
As the nation’s largest nuclear operator, Exelon is arguably better positioned than any company to capitalize on the carbon emission rules proposed yesterday by the EPA. The new rules seek to reduce U.S. greenhouse gas emissions by 30% from 2005 levels by 2030 — a target that would be much more difficult, if not impossible, to meet if the U.S. loses a substantial portion of its nuclear fleet, the largest carbon-free source of baseload capacity. (See related story, Carbon Rule Falls Unevenly on PJM States.)
“You can’t maintain the current emission level unless you keep the nuclear units viable today. And you surely can’t reduce if you start taking them off,” Exelon CEO Chris Crane told the Sanford C. Bernstein Strategic Decisions Conference last week. “So we think we’re uniquely positioned to be able to … work through a state-level design that will compensate the assets adequately” for their contributions to fuel-secure capacity and carbon reductions, Crane said.
A Good Quarter
Exelon shareholders have had a rough few years.
The company cut its dividend by 41% last year as its share price, which peaked at $90 in 2008, fell below $30.
But things have brightened considerably since January, when energy prices and demand spiked during the frigid winter. The company reported first-quarter earnings of $90 million, versus a loss of $4 million for the same period last year. Revenue rose to $7.24 billion, from $6.08 billion. Electric futures prices at PJM-West Hub are up by about 25% since November.
In addition, fuel supply problems that hampered production from coal- and gas-fired generators have PJM and Federal Energy Regulatory Commission officials talking about the possibility of adding a “fuel security” premium to the capacity market that would benefit nuclear generators.
FERC officials last week also talked about states supporting nuclear plants through “clean” energy portfolio standards similar to those that have supported renewable power. (See related story, ‘Clean’ Energy Portfolios Could Save Nukes, FERC tells NRC)
Hitting the Sweet Spot
As for the capacity auction, Exelon couldn’t have played its hand any better, said analysts from UBS Securities.
UBS said Exelon’s ideal strategy was to “withhold” 4,457 MW of its 25,000 MW PJM fleet — almost exactly the 4,225 MW of capacity that failed to clear. UBS Securities calculated that Exelon will earn $148 million more in capacity revenues in 2017 than it would have earned had all of its capacity cleared.
Eliminating 4,457 MW reduces daily revenue by $267,000 but increases clearing prices by $33/MW-day, UBS said. With the higher clearing price, the remaining 20,543 MW fleet earns $148 million more in revenue than had the entire portfolio cleared at the lower price. (See graphic.)
Utility rate analyst Paul Chernick agreed with UBS’ math. “If you had another 4,000 MW in there at the prices they must have bid in, it would have almost certainly pushed it below the $70 level,” said Chernick, president of Resource Insight Inc., a Massachusetts consulting firm whose clients include the Maryland Office of People’s Counsel.
UBS said Exelon’s “maximum benefit can be obtained by withholding just enough supply to drive prices received for the remaining fleet up without eliminating too much revenue and reducing the overall benefit.
“Given that only a relatively small portion of the fleet is required to be withheld for maximum benefit, we would conclude that [Exelon], at any rate, has more than adequate market power to drive auction results through an aggressive bidding strategy,” UBS said.
UBS analysts calculated the revenue gains from “hypothetical withholding scenarios,” hastening to add “we do not intend to imply that this behavior took place as described.”
Indeed, refusing to bid the plants into the auction would violate PJM rules and likely federal antitrust law. But with new PJM rules limiting imports and demand response, and with economics and the EPA’s Mercury and Air Toxics Rules forcing as much as 14 GW of PJM coal capacity into retirement, Exelon felt confident in offering its nuclear plants at maximum price it was allowed — the Avoided Cost Rate less net energy revenue.
Bowring: No Rules Broken
Market Monitor Joe Bowring said in an interview Friday that all generation offers were screened by his staff and PJM to ensure market power was mitigated by offer caps. That included a determination that no generator with market power could offer at a price higher than ACR less net energy revenue. “We do not believe market power was exercised in the capacity market,” Bowring said.
UBS noted that “the outcome is highly dependent on the initial assumption for where the auction would have come out at without any withholding. Lower baseline assumptions generally incentivize more withholding since less revenue is removed by the withheld assets (less risk in the strategy) while overall net uplift increases as well.”
“While outright strategic collusion is prohibited, participants may have been `telegraphing’ their intentions to each other more subtly in public comments from more than one company regarding potential retirements, seeking higher Avoided Cost Rates (ACR), etc.,” UBS said.
Chernick said that with imports and demand response limited by new rules in the 2017 auction, there was little risk to Exelon’s bidding strategy. “I think you could get a pretty good sense that this change in supply was enough to drive the price up,” he said. “It wasn’t like you could get huge amounts of [supply] zooming in.”
Crane seemed to confirm the analysts’ conclusions in his remarks at the Strategic Decisions conference last week, saying that although five units failed to clear, “overall the clearing price was beneficial to the total fleet.”
In its presentation to the conference, Exelon said its PJM capacity revenues will increase by $150 million in 2017 versus 2016. The company also expects a $250 million increase in 2017 capacity revenues from the New England capacity auction, held in February.
Crane said generators exhibited more “discipline” in their bidding this year.
“In the last auction, over two-thirds if not about three-quarters of the participants in the auction took themselves in as a price taker, which means they bid zero [and] not their full Avoided Cost Rate,” he said. “… The way that the RTO cleared, there is much more discipline in bidding, where people did bid their full ACR as we did on our plants.”
Retirement Threat
Crane said the failure of the Illinois nuclear plants to clear “gives us an opportunity to work with the state and work with the RTO on the value that they provide not only as a firm fuel during any weather event, but also provide a clean energy source that, if taken away, would be very difficult to meet the new [greenhouse gas] mandates.”
Earlier this year, Exelon warned Illinois legislators that low energy prices and renewable energy subsidies could force them to shut down three nuclear plants in the state. Exelon lobbyists reportedly named the Quad Cities and Byron plants in addition to the Clinton plant in southern Illinois (part of MISO) as those most at risk. (See Exelon in Lobbying Push to Save Ill. Nukes.)
Oyster Creek is scheduled to retire in 2019 under an environmental settlement with New Jersey officials. Exelon spokesman Paul Adams said that plan is unchanged.
Exelon said it has agreed not to make any retirement decisions about its Illinois plants before June 2015. The Illinois House introduced a resolution (HR1146) that calls for changes to recognize nuclear power’s reliability and environmental benefits. The resolution urges FERC, PJM and MISO to “expeditiously adopt market rules and policies, including transmission expansion rules and policies, that will ensure the continued operation” of the nuclear fleet. It also urges the EPA to make nuclear power a central part of compliance with the greenhouse gas rules.
GHG Rules to Benefit Nukes
Crane predicted last week that Illinois will seek a clean energy standard that would provide nuclear plants clean energy credits it can sell, similar to renewable energy credits (RECs).
A second path to compliance is the cap-and-trade approach used by California and the nine-state Regional Greenhouse Gas Initiative, which includes Maryland and Delaware.
Exelon made no secret last week that its Oyster Creek, Bryon and Quad Cities nuclear plants failed to clear the base residual auction.
Other generators — representing almost two-thirds of the 11,500 MW of generation capacity that failed to clear — were less forthcoming.
Dickerson Plant (Source: EPA)
UBS Securities analysts believe that at least some of the units at two NRG coal-fired plants in Maryland, Chalk Point and Dickerson, also failed to clear. UBS said it believes some of the 750 MW of uncleared capacity in the ComEd Zone may have been part of NRG’s Midwest Generation fleet.
An NRG spokesman, citing competitive reasons, declined to comment on the auction results.
A proposed 859-MW combined-cycle plant planned by Panda Power in Brandywine, Md., also may have failed to clear, according to UBS, which cited “air permit issues.” A Panda Power spokesman Friday declined to comment on the auction results but said the planned plant is still going forward.
Last year, FirstEnergy announced it would deactivate Hatfield’s Ferry and Mitchell plants in southwestern Pennsylvania after both plants failed to clear the auction. While a company spokesman wouldn’t say whether it bid those plants in this year’s auction, he said the decision to retire those plants stands.
New Generation
Rendering of the Oregon, Ohio Power Plant (Source: North American Project Development LLC)
PJM said it cleared 5,927 MW of new generation, the most ever. About 4,800 MW is combined-cycle generation clearing for the first time, all of it east of the west-to-east transmission constraints or in zones short of capacity.
Among this new combined-cycle generation is believed to be an 800-MW plant planned in the ATSI zone in Oregon, Ohio. The plant is being developed by North America Project Development LLC with funding from Energy Investors Funds, a private equity firm.
UBS said it believes Old Dominion Electric Cooperative’s 800-MW Wildcat expansion and PSEG’s Linden advanced gas path (AGP) uprate also cleared.
Reactivations
In addition, PJM cleared about 1,100 MW of generation that was slated for retirement but will be reactivated after switching from coal to another fuel.
NRG spokesman David Gaier said the company has several repowering projects underway or in the planning stages.
The company’s 732-MW Avon Lake, Ohio, plant and 325-MW New Castle plant in West Pittsburg, Pa., are in the process of being switched from coal to natural gas.
Its 158-MW, coal-fired Portland, Pa., plant ceased operations last week, but the company announced it will switch that unit to low-sulfur diesel, a project expected to be completed in June 2016.
Gaier said NRG is also considering converting its 597-MW Shawville, Pa., coal-fired plant to natural gas.
FirstEnergy spokesperson Stephanie Walton said the company doesn’t have any current plans to repower any of its coal-fired plants.
Stakeholders gave final approval to a revised Zonal Base Load definition last week that will ensure that zones don’t lose Auction Revenue Rights due to “extraordinary circumstances” that suppress their base load calculations.
The vote by the Markets and Reliability Committee was prompted by Superstorm Sandy in 2012. Storm-related outages produced base loads in the AE, JCPL, PSEG and RECO zones that were far lower than would have been expected under normal conditions. (See Superstorm Sandy Stirs Change to Zonal Base Load Definition).
PJM obtained a waiver from the Federal Energy Regulatory Commission in February to prevent the zones from losing a portion of their Stage 1A ARR allocations as a result of the muted ZBLs.
WASHINGTON – The Environmental Protection Agency’s proposal to cut carbon dioxide emissions 30% from 2005 levels won’t fall evenly on all states.
EPA Administrator Gina McCarthy
Coal-heavy Kentucky, West Virginia, Pennsylvania and Ohio will be required to make major changes in their generation mixes by 2030, while states such as Delaware — which participates in the northeast cap-and-trade program and has a less carbon-intensive generation — may need to do little more than continue their current efforts.
In percentage terms, however, Kentucky and West Virginia will need to reduce their carbon by half as much as less carbon-intensive states such as New Jersey.
The EPA said it attempted to determine what was “practical and affordable” for individual states, taking into account factors such as their current generation mixes and the availability of natural gas.
The EPA identified four “building blocks” that states can use to meet their targets, including unit-level efficiency improvements for coal-fired units (4% from implementing best practices plus 2% from replacing equipment); fuel switching from coal to natural gas; renewable energy and nuclear power; and demand-side energy efficiency (based on savings of up to 1.5% annually including existing state EE programs). (See related story, PJM Welcomes Rule’s ‘Flexibility’; Generators’ Views Mixed.)
The rule is intended to minimize the economic hurt on states like West Virginia and Kentucky and, thus, the political blowback. As a result, the relative carbon intensity of the states’ electric systems won’t change much by 2030.
Kentucky, West Virginia and Indiana, the top-ranked PJM states in 2012 carbon emissions per MWh, would have to cut their emissions by only 20% and would still retain their top ranks in carbon intensity in 2030. Meanwhile, New Jersey, which ranks last among the 13 PJM states in 2012 emissions/MWh, will have to cut its emissions the most in percentage terms (43%).
Most of the states would remain in the same rank order in 2030 or shift only one rank. The exceptions are two states that would swap positions: Tennessee (drops from fourth to seventh) and Ohio (rises from seventh to fourth).
“It’s clear that EPA spent a lot of time listening to concerns,” said Steve Fine, vice president of ICF International in an interview. “While wanting to push for pretty aggressive carbon reductions by 2030, they certainly made an attempt to take into account state-specific circumstances.”
Despite the EPA’s efforts to create what it called a “flexible” standard, some coal-state politicians vowed to fight the rule, which will be open for comment for 120 days and — barring court challenges — finalized in June 2015. States will have at least one year after the final rule is published to submit implementation plans for the EPA’s approval.
Below is a first look at the potential impact of the rule on PJM states and the reaction from them, ranked by 2012 carbon intensity. (The District of Columbia has no fossil fuel generation and is exempt.)
1. KENTUCKY
2012 power sector CO2 emissions (metric tons): 83 million
2012 emission rate: 2,158 lb/MWh
2030 emission target: 1,763 lb/MWh (-18%)
Gov. Steve Beshear released a statement noting his opposition to the carbon rule issued last year for new power plants, which would essentially ban new coal-fired plants without carbon-capture technology, a rule he said “would decimate Kentucky’s economy.
“Since then, my administration has worked hard to provide viable alternatives to the Obama administration that recognize the uniqueness of states like Kentucky and provide flexibility to help those states be a part of the solution.
“I appreciate that the proposed rule regarding existing power plants announced today does recognize that differences do exist among manufacturing states and in states that produce the nation’s energy. However, I am still extremely concerned that it does not provide adequate flexibility or attainable goals.”
2. WEST VIRGINIA
2012 power sector CO2 emissions (metric tons): 66 million
2012 emission rate: 2,019 lb/MWh
2030 emission target: 1,620 lb/MWh (-20%)
There was little uncertainty in West Virginia, where federal lawmakers from the state are already prepared to take steps to fight the rule.
Democratic Rep. Nick Rahall will work with Republican Rep. David McKinley with the goal of stopping the EPA’s rule on existing power plants and an earlier proposal covering yet-to-be-built plants. Rahall said the proposals would “wreak havoc” on the state’s coal industry if implemented.
Gov. Earl Ray Tomblin agreed in a statement. “If these rules are put into place, our manufacturers may be forced to look overseas for more reasonable energy costs, taking good paying jobs with them and leaving hardworking West Virginians without jobs to support their families. We must make every effort to create opportunities for our young people, not hinder them,” he said.
Tomblin pledged to form a working group of diverse voices from across the state to determine the impacts of the new regulations and challenges for West Virginia’s energy industry, as well as opportunities to diversify the state’s economy.
Randy Huffman, secretary of the West Virginia Department of Environmental Protection, said of the proposed EPA rules: “The most obvious thing that jumps out at you is that, in order to achieve the proposed standards, the role that coal plays in the West Virginia energy mix will diminish significantly.”
He said the mix is currently 96% coal, and that 60% of all energy produced from coal is exported, which provides important revenues for the state’s energy companies.
3. INDIANA
2012 power sector CO2 emissions (metric tons): 92 million
2012 emission rate: 1,923 lb/MWh
2030 emission target: 1,531 lb/MWh (-20%)
Gov. Mike Pence said the Obama Administration is advancing its “anti-coal” agenda without regard for the impact on the U.S. economy or workers.
“As a state that relies heavily on coal-burning power plants, these proposed regulations will be devastating for Hoosier workers and families,” Pence said. “They will cost us in higher electricity rates, in lost jobs and in lost business growth due to a lack of affordable, reliable electricity. Indiana will oppose these regulations using every means available.
“The proposal makes good on then-presidential candidate Obama’s statements in 2008 that under his plan electricity prices would ‘necessarily skyrocket,’ and that anyone who built a coal-fired electricity power plant would be bankrupted.”
Pence said he opposed the rules in 2009 when Democrats in Congress attempted to pass cap-and-trade, and he opposes them now.
Republican U.S. Sen. Dan Coats echoed Pence’s remarks. “By supporting these regulations, the president is putting our economic well-being, grid reliability and American jobs at risk,” Coats said.
2012 power sector CO2 emissions (metric tons): 37 million
2012 emission rate: 1,903 lb/MWh
2030 emission target: 1,163 lb/MWh (-39%)
Reaction in Tennessee was mixed.
TVA CEO Bill Johnson said the utility has been cutting emissions since 2005. Johnson said in a conference call that the utility has cut its carbon dioxide emissions by about 30% since 2005 and expects a 40% reduction by 2020. TVA said by 2020, its carbon emissions will be about half of what they were at the 1995 peak.
U.S. Rep. Jim Cooper (D) said EPA acted “because Congress failed to.”
“I haven’t seen the new regulation yet, but I am hopeful it will insure against any more harm to the planet. Every nation needs to join our effort,” Cooper said.
U.S. Rep. Marsha Blackburn (R), vice chairman of the House Energy and Commerce Committee, said the regulations were a continuation of “the Obama administration’s war on coal.”
“This rule is another tax on the American taxpayers and will lead to higher electricity rates and fees,” she said in a statement.
State Rep. Glen Casada, chairman of the House Republican Caucus, said the new rules will cost jobs. “It’s going to cause our electric bills to go up dramatically and for really no empirical data reason why,” he said.
Casada said he will look for legislative ways around the requirements. “The exact solution is still being worked out, but I think the first step should be to say, ‘Mr. President, you don’t have the authority to do this. The Constitution does not give you this right,'” Casada said.
2012 power sector CO2 emissions (metric tons): 87 million
2012 emission rate: 1,895 lb/MWh
2030 emission target: 1,271 lb/MWh (-33%)
Illinois officials and lawmakers applauded the EPA’s proposal and say the state is well-prepared to meet its new emission-reduction goals.
“It is important that we take serious, comprehensive action to reduce carbon emissions, so I look forward to reviewing the draft guidelines of the federal plan in detail and helping to develop a flexible and effective approach for Illinois,” state Attorney General Lisa Madigan said.
“Communities in Illinois are already leading the nation in choosing power that is renewable, affordable and clean,” U.S. Sen. Dick Durbin (D) said in a statement. “I will continue to support these efforts and other investments in innovative technologies … that create Illinois jobs now and invest in clean energy sources for the future.”
Illinois already generates almost half of its power from nuclear plants, but only gets 6% from natural gas.
The EPA’s proposal comes just days after state lawmakers passed a bill freeing up $30 million for purchasing solar power.
2012 power sector CO2 emissions (metric tons): 18 million
2012 emission rate: 1,870 lb/MWh
2030 emission target: 1,187 lb/MWh (-37%)
Gov. Martin O’Malley said he supports the rule because it will improve public health and help neutralize climate change and rising sea levels in the state. He said it would also help Maryland expand its use of renewable energy sources and “unleash the power of our innovative green economy.
“We are already witnessing a transformation in the U.S. economy to increased production of lower carbon energy through fuel switching to natural gas and expansion of wind, solar, geothermal and other renewable non-carbon intensive energy sources,” O’Malley said in a statement.
Maryland is one of two PJM states, along with Delaware, that participate in the Regional Greenhouse Gas Initiative (RGGI) cap-and-trade program.
7. OHIO
2012 power sector CO2 emissions (metric tons): 93 million
2012 emission rate: 1,850 lb/MWh
2030 emission target: 1,338 lb/MWh (-28%)
In Ohio, which gets nearly 70% of its power from coal, legislators are expected to act quickly on a bill that would seek to limit the impact of the EPA’s proposal. The bill would require that any plan to reach this goal submitted by the state to the EPA maintain electricity affordability and minimize effects on consumers. Republican state Rep. Andy Thompson, the bill’s sponsor, said it has bipartisan support.
“It’s kind of a delicate dance because the Ohio EPA has to reconcile itself to what the federal EPA is doing,” Thompson said.
The EPA’s proposal comes just days after legislators approved a bill, which Gov. John Kasich is expected to sign, pausing the state’s renewable energy standards for two years while a committee studies the issue.
“Ohio is now tying one hand behind its back and taking renewables and energy efficiency out of the mix of tools” state officials can use to reduce carbon pollution, said Steve Frenkel, Midwest director of the Union of Concerned Scientists.
Ohio EPA Director Craig W. Butler said he was still evaluating “how exactly this proposal impacts Ohio. We are, of course, concerned with anything that could hurt Ohio’s economy at a time when we are just beginning to get back on track,” he said.
2012 power sector CO2 emissions (metric tons): 63 million
2012 emission rate: 1,696 lb/MWh
2030 emission target: 1,161 lb/MWh (-32%)
The Michigan Department of Environmental Quality stressed the importance of flexible targets, especially for manufacturing states like Michigan that have a higher percentage of coal-fired power plants.
“If we have to achieve a goal too fast and too much, it will create reliability and affordability issues not only for ratepayers but also Michigan’s economy, and it would put Michigan at a competitive disadvantage,” department director Dan Wyant said.
He said the state’s cap should take into account energy efficiency as well as gains it has already made in alternative energy. Michigan is on track to meet a renewable energy standard of 10% by 2015.
Detroit-based DTE Energy plans to replace its older coal plants, about a third of its coal-fired capacity in the state, by 2025 and replace them with wind power and natural gas plants. The company has spent nearly $2 billion on emissions control equipment for its Monroe Power Plant and is pursuing a license to build a new nuclear power plant.
Consumers Energy plans to retire its seven oldest coal plants by the second quarter of 2016 and is building its second wind farm. “We previously established a goal of reducing our carbon emissions by 20% by 2025 and are making more than $1 billion in investments in clear air equipment at our power generating facilities,” spokesman Dan Bishop said in a statement.
2012 power sector CO2 emissions (metric tons): 53 million
2012 emission rate: 1,646 lb/MWh
2030 emission target: 992 lb/MWh (-40%)
“At this point, we have more questions, probably, than the media does,” Tom Mather, of North Carolina’s Air Division of the Department of Environment and Natural Resources, said in an interview yesterday.
“In their fact sheets, [EPA is] comparing a lot of this to 2005, which led us to believe that would be the baseline, but in the [conference call with state environmental representatives] they are referring to 2012, and that makes a huge difference to North Carolina,” he said.
Mather cited the North Carolina Smokestacks Act, which required significant emissions reductions by Duke Energy and Progress Energy — a 75% reduction of nitrogen oxides (NOx) and sulfur dioxide (SO2) from 1998 levels by 2012.
“In meeting the goals for NOx and SO2, the companies closed a number of older coal-fired power plants and converted others to natural gas — effectively reducing their CO2 emissions in the process,” Mather said. “The companies also have invested a lot of money in energy production from alternative sources of energy including solar, wind and biomass in complying with another state law that sets a renewal energy portfolio for the state.”
“We do not know if we would get credit for those CO2 emissions reductions under the proposal EPA carbon rule,” Mather said. “That is one of the questions we are trying to get answered.”
Mather said the issue of imports also caused confusion.
“One of the callers was from Kansas, and they have a lot of wind generation, but it is sold out of state, so who gets credit for that, Kansas, or the state where the utility is based?” Mather said. “The [EPA] administrator frankly didn’t have the answer to that question.”
10. PENNSYLVANIA
2012 power sector CO2 emissions (metric tons): 106
2012 emission rate: 1,540 lb/MWh
2030 emission target: 1,052 lb/MWh (-32%)
In Pennsylvania, a state with 63,000 coal industry jobs, the proposed rule was met with concern.
“While we continue to review the EPA’s proposed rulemaking in detail, I am concerned that these new mandates will eventually shut down hundreds of coal-fired power plants across the country and destroy thousands of family-sustaining jobs,” Gov. Tom Corbett said. “Anything that seeks to or has the effect of shutting down coal-fired power plants is an assault on Pennsylvania jobs, consumers and those citizens who rely upon affordable, abundant domestic energy.”
He said greenhouse emissions in the Keystone State are already at their lowest levels since 1994 and will be reduced further by cleaner coal technology.
11. VIRGINIA
2012 power sector CO2 emissions (metric tons): 25 million
2012 emission rate: 1,297 lb/MWh
2030 emission target: 810 lb/MWh (-38%)
“It’s a very complex document that my staff and I are just beginning to delve into,” said Michael G. Dowd, the director of the Air Division of Virginia’s Department of Environmental Quality. “So we have no immediate reaction to the proposed rule.”
12. DELAWARE
2012 power sector CO2 emissions (metric tons): 4 million
2012 emission rate: 1,234 lb/MWh
2030 emission target: 841 lb/MWh (-32%)
Collin O’Mara, secretary of the Delaware Department of Natural Resources and Environmental Protection, said that the state should hit its target by 2020 or sooner through its RPS and EE programs and its participation in the RGGI.
He noted that the state shut down the Indian River Unit 3 coal-fired plant last year, a reduction not reflected in its 2012 numbers. Calpine’s planned combined-cycle plant in Dover will also bring down its average, he said.
In addition, RGGI is lowering its cap on carbon emissions by 2.5% annually.
O’Mara, who attended EPA Secretary Gina McCarthy’s announcement yesterday, said several non-member states, including some in the Midwest and Pacific Northwest, have contacted RGGI for information, although none have thus far committed. “They like that it’s a plug-and-play approach,” he told RTO Insider after the announcement.
13. NEW JERSEY
2012 power sector CO2 emissions (metric tons): 12 million
2012 emission rate: 932 lb/MWh
2030 emission target: 531 lb/MWh (-43%)
Gov. Chris Christie pulled the state out of RGGI in 2011 and has vetoed attempts by the legislature to rejoin. Nevertheless, Larry Ragonese, a spokesman for the state Department of Environmental Protection, said the state’s power sector emissions have already dropped to 503 lb/MWh, below the 2030 target.
“We have virtually eliminated coal plants in this state,” he said. “Most have been replaced by natural gas,” and most gas plants have tended to be combined-cycle ones, the cleanest designs of their kind available. These plants can help balance wind generation, he said.
U.S. Sen. Robert Menendez (D) applauded the administration’s move, as did several environmental groups who called the proposed rules an important step toward mitigating the effects of climate change.
The Markets and Reliability Committee last week got a first read of two packages designed to better represent the supply curves posted following RPM auctions without revealing sensitive data. (See MIC Seeks Better Way to Draw Capacity Supply Curve.) Market Monitor Joe Bowring didn’t like what he saw. The packages, which were created by a working group of the Market Implementation Committee, both include supply curve smoothing that use the same seven-segment moving average approach and detailed methodology. Package A, however, includes detailed criteria to disallow publishing a curve for a locational deliverability area if certain tests for market concentration are failed, while Package B will only publish supply curves for the diverse RTO and MAAC transmission zones. Marji Philips of Direct Energy said she was glad to see more accurate and transparent supply curves so those serving load could “have the inside scoop” on market pricing. Bowring replied: “The goal is for no one to have the inside scoop.” He said if either of the packages was implemented, it could potentially reveal sensitive data about price-quantity offers and cause collusion among generators. He urged stakeholders to reject both packages and maintain the status quo when the issue is brought to a vote of the MIC this week.
Exelon last week filed an application with the Federal Energy Regulatory Commission seeking approval of its acquisition of Pepco Holdings Inc. FERC approval is expected to come fairly swiftly, as PHI has no generation, and market power issues shouldn’t come into play.
The two companies announced the proposed acquisition late last month. If approved, it will bring together Exelon’s three electric and gas utilities – BGE, PECO and ComEd – with PHI’s three utilities – Delmarva Power, Pepco and Atlantic City Electric. The combined companies would become the largest electric and gas utility in the Mid-Atlantic.
Because no generation plants are involved, the companies are asking for approval within 90 days. The acquisition still requires approval from state regulatory agencies in Delaware, Maryland, New Jersey and Virginia, as well as from the D.C. Public Service Commission. Those approvals are expected to take longer to obtain. The companies have said they anticipate full approvals by the second or third quarter of 2015.
FERC has gained a valuable new tool in the fight against energy market manipulation as a result of an agreement giving the commission access to the Commodity Futures Trading Commission’s Large Trader Report. “Until recently, we didn’t have a lot of visibility into large trading data, [but] the CFTC has given us a lot more transparency in terms of positions,” Sean Collins, FERC’s deputy director of surveillance, told a conference in Texas last month.
Collins said the memorandum of understanding between the two organizations has given FERC investigators a clearer view of what is going on in the derivatives market, which often plays a crucial role in manipulative schemes that involve both physical and financial products. “The ability to see across those two markets and to be able to see what market participants are doing is essential, so we’re very thankful for that data,” he said.
Citing previous safety studies, the Nuclear Regulatory Commission rejected calls from lawmakers to speed up the transfer of spent fuel bundles from pools to dry cask storage.
The commission, relying on its staff’s recommendations, has said it believes it makes more sense to leave the spent rods in on-site cooling ponds than engage in hurry-up transfers to dry cask storage.
An NRC Northeast Regional administrator said both pools and dry casks were “adequate storage processes for spent fuel, and there is not a significant safety benefit to requiring transfer to dry cask storage.”
Some lawmakers, however, citing security concerns and dwindling space in cooling pools, are pushing for the transfers.
Several senators wrote to NRC Chair Allison Macfarlane earlier to complain about a lack of security around the pools and closed plants. “We are one natural disaster, mechanical failure or terrorist attack away from a disaster,” said Sen. Bernie Sanders (I-Vermont). “The sooner we get the spent [fuel] out of the pools and into dry casks, the better, and if the NRC will not change the rules, I will continue to work with my colleagues to change the rules through legislation.”
The EPA successfully fended off efforts by environmental groups to hasten implementation of rules combatting acid rain. The U.S. Court of Appeals for the D.C. Circuit last week accepted the EPA’s arguments that rules covering acid rain must take into account “large complexities” and shouldn’t be hurried. The EPA announced two years ago that it needed more time to determine new standards of certain pollutants, primarily those emitted by fossil-fuel fired power plants. Environmental groups, including the Center for Biological Diversity, sued and accused the EPA of delaying the implementation of new regulations.
“In light of the deference due EPA’s scientific judgment, it is clear its judgment must be sustained here,” U.S. Circuit Judge A. Raymond Randolph wrote for a three-judge panel.
A joint proposal from PJM and the Independent Market Monitor to reduce payments to frequently mitigated units (FMUs) rose from the ashes to best three generator-backed proposals last week.
The PJM-IMM proposal earned nearly 70% approval in a sector-weighted vote of the Markets and Reliability Committee, despite earning just 43% support from the Market Implementation Committee in early May. (See Members Reject PJM-IMM Plan on FMUs).
The proposal was approved after three packages favored by suppliers failed to earn enough support for approval.
Market Monitor Joe Bowring has said the adders are no longer needed because of PJM’s capacity market.
The PJM-IMM proposal (Package A) leaves the calculations for adder payments unchanged but limits them to units whose net revenues are not covering their avoidable cost rate (ACR). PJM said that had the proposal been in effect in 2013, it would have reduced the number of units receiving adders from 112 to only 28 — 23 of which are scheduled to retire.
Neil Fitch of NRG Energy said his company couldn’t support the PJM-IMM package because it “seems tantamount to eliminating FMUs.”
Package G, which was considered first based on the 65% support it received at the MIC, received only 40% support from the MRC. It would have capped adders at 12% of the gross Cost of New Entry (CONE).
Of the three generator-backed proposals, only Package H received more than 50% of sector-weighted support, though it didn’t come close to the two-thirds support needed for approval. It would change adders only for Tier 2 FMUs — units that are offer-capped between 70% and 80% of their run hours over the prior 12 months.
The Market Implementation Committee had approved the PJM proposal — which is intended to reduce uplift costs — by a more than 2-1 margin last month. The approval came despite concerns it would unfairly penalize load and could increase overall costs. (See PJM Reserve Proposal OK’d Despite Misgivings.)
