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.
Members last week agreed to create a senior task force to fix the underfunding of Financial Transmission Rights (FTRs) following a debate over the role of Auction Revenue Rights.
PJM says over-allocation of Stage 1A ARRs have become the biggest cause of the problem, responsible for $420 million of underfunding for planning year 2013/14, 73% of the total. That was up sharply from 2012/13, when ARRs caused only 26% of underfunding, or $75 million. (See chart below.)
PJM agreed to modify the task force’s initiating documents to include an evaluation of the causes of underfunding after several stakeholders raised concerns that ARRs were being unfairly singled out. ARRs are allocated annually to firm transmission service customers and entitle them to receive a share of the revenues from the annual auction of FTRs.
Ed Tatum of Old Dominion Electric Cooperative objected to the original problem statement, which he said improperly included a solution that targeted ARRs.
ARRs are “a touchstone issue for the load-serving entities,” Tatum said. “We don’t believe the numbers [cited by PJM] reflect the actual impact of the problem … We think it’s a much lower number and we’d like to understand how PJM calculated it. It’s more than likely there are other, more significant causes of the underfunding.”
Andy Ott, executive vice president for markets, said PJM wanted to keep the issue scope narrow to avoid the “food fights” of the past.
PJM says more than 15% of Stage 1 historical generation (25,544 MW) has retired or submitted deactivation notices since the ARR allocation process was designed. “This is the biggest reason for underfunding,” said Harry Singh of Goldman Sachs. “You’re allocating things that don’t exist.”
Singh said a failure to address FTR over-allocation could jeopardize the Commodity Futures Trading Commission’s order exempting FTRs from the agency’s jurisdiction. The order said FTRs must “be limited by the physical capability of the … transmission system.”
The problem statement also identified other underfunding causes, including external loop flows, maintenance- and construction-related transmission outages and the creation of temporary interfaces to capture operating procedures — such as the dispatch of demand response — in locational marginal prices.
The RTO introduced FTRs in 1999, intending them to provide a financial hedge against the costs of day-ahead transmission congestion.
Singh said that load-serving entities “should also care about having good hedges.” Those who oppose solutions to the problem “are not doing a favor for the people they work for,” he said. Over-allocation to a handful of load-serving entities amounts to a subsidy by other LSEs, he said.
Ott said the task force, which will report to the MRC, should complete its work by Oct. 31, before the next annual FTR auction. “If we don’t deal with it by October, then we miss a whole year,” he said.
ROCKVILLE, Md. — “Clean” energy portfolio standards may be a way for states to provide financial support for ailing nuclear plants, Federal Energy Regulatory Commission officials said last week.
FERC Commissioner Phil Moeller, FERC Acting Chair Cheryl LaFleur, NRC Chair Allison MacFarlane (L to R)
The comments came during FERC’s public meeting with the Nuclear Regulatory Commission on grid reliability Wednesday. Officials of the North American Electric Reliability Corp. (NERC) also took part in the 90-minute session at NRC headquarters, which included discussions on NRC’s actions to address lessons learned in the 2011 Fukushima nuclear disaster and FERC’s regulation of hydropower dams near nuclear plants.
But coming on the heels of a capacity market auction in which five Exelon Corp. nuclear generating plants in Illinois failed to clear, the financial health of nuclear power was the central topic. (See related story How Exelon Won by Losing.)
FERC Commissioner Tony Clark noted that PJM and other organized wholesale markets have been able to coexist with state renewable portfolio standards (RPS) that ensure a place for wind and solar power in the generation mix.
“So an elegant solution might be pivoting to a clean-energy standard if the concern of a state is emissions and … if we’re moving into a 111(d) world where carbon is going to be regulated,” Clark said, referring to the greenhouse gas rule released by the EPA yesterday. “These would seem to be some of the most valuable units we have.”
Arnie Quinn, director of FERC’s Division of Economics and Technical Analysis, said such a structure might overcome the jurisdictional challenges that he said have “hamstrung” regulators in restructured states.
Quinn said state regulators have expressed a desire to obtain purchase-power contracts to keep their nuclear plants open. “They look [for someone] to sign that contract and they have difficulty finding who they still have jurisdiction over,” he said. In states with RPS, load-serving entities are obligated to purchase minimum percentages of renewable sources such as wind and solar.
Fuel Security
FERC is also considering ways to bolster nuclear generators’ capacity revenues, perhaps through a “fuel security” premium.
FERCs Arnie Quinn
Acting FERC Chair Cheryl LaFleur said although the wholesale markets are “fuel blind,” they also acquire resources that possess important capabilities, such as ramping, needed to keep the grid functioning. Fuel security could be such a capability to incorporate, she suggested.
In January, natural gas-fired plants had trouble obtaining fuel due to high prices and pipeline constraints. Coal-fired plants also experienced problems due to frozen coal and delayed rail shipments.
Nuclear plants need to add fuel about once every two years — about the same frequency with which FERC and NRC hold these joint meetings.
“Knowing that you’ve got a stock of fuel on site … that will be there for the duration of a weather event — it’s another thing you don’t have to” worry about, Quinn said.
Causes of Nukes’ Problems
Quinn cited data from the PJM Market Monitor showing that nuclear generators’ net energy and capacity revenues in the RTO have declined from more than $300,000/MW-year in 2010 and 2011 to $240,000 in 2013.
Quinn said the causes include excess supply, particularly from low-cost natural gas and wind, and capacity prices depressed by demand response and transmission upgrades.
“There is currently a very robust debate about the relative importance of those potential drivers,” Quinn said. “FERC staff hasn’t come up with an independent opinion on which of these drivers is more important than the others.” (See Who’s to Blame for Negative Prices?)
Quinn said that fossil fuel plant retirements resulting from the EPA’s Mercury and Air Toxics Standards and transmission expansion that makes it easier for generators to reach load may help boost prices. “But the degree to which any of these future changes will result in a full recovery of revenue levels is just uncertain at this point,” he said.
Quinn also noted that nuclear plants benefited from energy market prices in January that hit $1,000/MWh during some hours.
“In some degree the system has been designed so that’s where a lot of cost recovery occurs … If your marginal cost was down at $15 to $20 per megawatt-hour there was a lot of money there to be earned to recover some fixed costs.”
The question FERC is considering, Quinn said, is whether current energy and capacity revenues are enough to preserve the nuclear fleet or whether it requires some other payment stream.
Duke Energy has reached an agreement with the EPA about the cleanup of its massive coal ash spill on the Dan River. The agreement formalizes the cleanup activities already underway after February’s spill of an estimated 39,000 tons of ash and includes ongoing monitoring and post-cleanup assessment. It also provides penalties of up to $8,000 per day if the company doesn’t follow the conditions. Duke agreed to pay the EPA’s costs for responding to the spill, estimated at $1 million so far. The agreement is filed under the federal Superfund hazardous sites law.
Duke Energy contractors and engineers survey the site of the coal ash spill on the Dan River in North Carolina.
Duke is also facing a stockholder suit over its potential liability for spills at its other coal ash depositories. The complaint by shareholders Edward Tansey and the Police Retirement System of St. Louis alleges management exposed the company to billions in liability over its coal ash storage methods.
The suit was filed in the Court of Chancery in Delaware, where Duke is incorporated. It claims that Duke officials were aware of the risk of coal ash contamination from its stock piles and settling ponds. It seeks to force the company to eliminate ash contamination, as well as unspecified damages and changes in how Duke handles the waste.
Meanwhile, a North Carolina House bill filed last week aims to force Duke to clean up its most dangerous coals ash ponds within the next five years. House Bill 1226, introduced by Democratic lawmakers, includes a long list of coal ash regulations, including a moratorium on accepting more coal ash starting this summer.
Most notable about the bill is a provision denying the company the ability to recover remediation costs from customers. In addition to stopping new coal ash deliveries, the bill calls for all coal ash storage ponds to be closed by 2029 and the most dangerous coal ash ponds cleaned up by 2019.
American Electric Power Company is reportedly pondering the sale of its Midwestern power plants, becoming the second large generation owner, after Duke, to exit the Midwest regional generating business.
CEO Nick Atkins told Bloomberg that because of the paucity of long-term power purchasers, which bring certainty to merchant plants, the company could decide to concentrate almost exclusively on its regulated businesses, with their guaranteed rates of return.
Duke is seeking to sell 13 plants that produce 6,600 MW. AEP owns more than 10,000 MW of generation, valued at about $3 billion. The company said a final decision on whether to sell should come by the end of the year.
Exelon’s aging Oyster Creek nuclear power station last Wednesday reported a leak of chlorine used to control algae near the plant’s water intakes, but the plant remained at full power, authorities said. The “unusual event” was declared at 10:30 a.m. and ended an hour later, according to Nuclear Regulatory Commission spokesman Neil Sheehan. No one was hurt. Oyster Creek is scheduled to be retired in 2019.
Susquehanna 1 Refueling Done
But Turbine Work Needed
PPL’s Susquehanna Unit 1 will remain offline indefinitely while the company investigates the cause of turbine issues the unit experienced a year ago. The refueling and scheduled maintenance outage work on the 1,260-MW Unit 1 was done last week, but the plant on the Susquehanna River will stay cold while engineers inspect the low-pressure steam turbine. The company did not say when it would return to service.
Unit 1’s turbines have been inspected five times since 2011. Unit 2’s turbines have been inspected at least six times, most recently in March. Unit 2 remains operating at full power, according to the NRC.
PJM told the Federal Energy Regulatory Commission last week it should allow a Duke Energy peaking plant to recover $9.8 million it spent on expensive natural gas it was unable to burn in January.
Responding to a complaint filed by Duke May 2 (EL14-45), PJM disagreed with Duke’s legal analysis and some aspects of its claim. But it said not paying Duke under the circumstances would be an “[in]equitable result” for generation owners.
The Market Monitor and others argued against Duke’s claim, saying capacity resources such as Duke need to be responsible for their fuel-cost risk.
What’s at Stake
If FERC rules in Duke’s favor, PJM’s tab could total tens of millions. In a filing supporting Duke’s claim, NextEra Energy Resources said it will make a similar claim to recoup $1.3 million in gas costs. Mike Bryson, executive director of system operations, told RTO Insider last week that about 10 companies have informed PJM that they also suffered “stranded gas” losses.
On Thursday, the Markets and Reliability Committee approved a problem statement to improve PJM’s procedure for committing gas-fired units. The initiative was broadened at stakeholders’ suggestions to cover several additional issues, including the definition of an outage and handling of dual-fuel units. “We’d like to get [solutions] before the winter so we don’t have a replay of the confusion” of January, said Mike Kormos, executive vice president for operations.
Duke’s Claim
Duke’s claim resulted from the late January cold snap. On Jan. 27, PJM issued a Maximum Generation Alert for the following day, signaling that all generation capacity resources should be ready to operate. (See related story, Recordings Capture Tense Operations During January Cold.)
Duke Lee Energy Facility (Source: Bill Spindler, SouthPoleStation.com)
As a result, Duke purchased $12.5 million worth of gas, enough to run five of the eight 80-MW units at its Lee County, Ill., facility for both Jan. 27 and 28. (Due to the mismatch of the gas and electric days and pipeline restrictions, Duke needed to purchase enough gas for two 24-hour periods in order to cover all hours for Jan. 28.)
Duke said it was able to recoup $2.6 million by self-scheduling several of the Lee units on Jan. 27 and 28, selling unused gas and receiving “very limited make-whole payments and credits” from PJM, leaving it with a loss of about $9.8 million.
Duke asked PJM to indemnify it under section 10.3 of the PJM Tariff, which requires that a generation owner be held “harmless” for “obligations … to third parties, arising out of … a Generation Owner’s (acting in good faith to implement or comply with the directives of the Transmission Provider) performance of its obligations.”
As an alternative, Duke seeks “a one-time, Duke-specific waiver” of Operating Agreement and Tariff provisions that bar make-whole payments.
PJM: No Order
In its filing last week, PJM insisted that its conversations with Duke did not constitute a directive to buy gas.
“It is a common occurrence that PJM dispatchers indicate that units need to be available to run only to later find that due to changes in load conditions, PJM does not need to commit the particular unit,” PJM said. “Although clearly done under more stressful conditions here, dispatchers are called on a routine basis and asked to prognosticate on whether units might be picked up and run in real time. Dispatchers answer those questions based on the best information they have available but are not providing guaranties through their answer.”
PJM also disagreed with Duke’s request for indemnification under the Tariff.
“Any extension of Section 10.3 to cover the type of loss Duke incurred under the circumstances at issue would read the indemnification provision into a blanket insurance policy for losses of whatever sort, caused by accident, act of God or plain misfortune that a Market Seller may incur in responding to PJM dispatch,” PJM said.
Commission approval of Duke’s request, PJM said, “would open the floodgates for a host of meritless claims that would present an existential threat to PJM and every independent system operator and regional transmission organization.”
PJM said capacity resources such as Lee must be offered into PJM’s markets on a daily basis and “do not have an automatic right to recover all of its costs should the units not actually be dispatched.”
Nevertheless, it said Duke should be compensated under a waiver because of the “extraordinary” circumstances of January. “Gas balancing losses that are usually no more than a routine `cost of doing business’ were in some cases transformed, in large part due to the conditions of the gas market and large price fluctuations, into multi-million dollar losses,” PJM said.
Monitor: Don’t Pay
In its own filing last week, the Market Monitor called on FERC to reject Duke’s request, saying it would be “a dramatic change in market rules and an associated, inappropriate shift in the costs and risks of the market to customers.”
The Monitor said Duke chose to rely solely on interruptible gas pipeline service and did not invest in back up fuel capability. “It is inappropriate for Duke to ask PJM customers to hold it harmless from such decisions, from which Duke has benefitted. It is also unfair to Duke’s competitors, who may have made different choices about fuel supply.”
The Monitor also said more than half of Duke’s claimed losses resulted from its delay in purchasing gas, which rose from $37/mmBtu to $63/mmBtu in the hours before Duke decided to purchase.
Retailers and the PJM Industrial Customer Coalition were also unsympathetic. The “waiver would harm the market, principles of market certainty and market participants … who may be forced to pay even more for Balancing Operating Reserve costs,” said the Retail Energy Supply Association.
Several generators, the PJM Power Providers Group and the Electric Power Supply Association filed comments siding with Duke.
“Denying Duke’s complaint despite Duke’s good faith efforts to comply with the PJM directive would be unjust and unreasonable,” FirstEnergy said. “System dispatchers need to have confidence that resources will perform when instructed to do so. And market participants must have confidence that, when directed by system operators to act for the sake of reliability, they will be made whole for the costs to carry out dispatcher’s instructions.”
NextEra Energy Resources also supported Duke, saying it also suffered losses in late January. NextEra said PJM “committed” a 290-MW generator in Sayreville, N.J., that NextEra co-owns with GDF Suez before the Jan. 27 operating day. PJM cancelled its dispatch, leaving the plant with a $1.3 million loss for unburned gas.
NextEra’s filing included a transcript of its exchange with PJM, in which one PJM dispatcher assured the company it would be reimbursed for its gas purchases: “I understand that you guys have already purchased the gas, ah, that’s not an issue, as far as if you’re worried about being reimbursed for that … PJM will obviously take care of that.”
Concept design of planned data center (Source: University of Delaware)
A plan to construct a 279-MW natural gas-fired plant for a developing data center on the grounds of a shuttered car factory is being challenged in the state’s Superior Court. The plant was described as being crucial to provide reliable power for the University of Delaware’s new state-of-the-art data center. But opponents are arguing that the site’s zoning doesn’t allow for such a power plant, and another challenge said the air emissions studies are flawed.
With a major approval from the Federal Energy Regulatory Commission in its pocket, Dominion Resources passed another test when it received conditional approval for a 130-MW generating plant crucial to the operations of a proposed liquefied natural gas export terminal on the Chesapeake Bay. The Maryland Public Service Commission authorized the plant but imposed nearly 180 conditions, including air and water quality monitoring, forest conservation, low-income energy assistance and $40 million for community programs and state renewable energy programs.
More than 50 Maryland legislators signed a letter calling on the state Department of the Environment to finalize regulations on smog and fine particle pollution from power plants.
Twelve counties regularly fail federal air quality standards for smog. The state is mandated to set limits on air pollution from coal-fired power plants and other emitters and to require that they use the best available emission control technology. “Coal plants in Maryland are the largest individual sources of air pollution and in many cases lack modern pollution-cutting technology,” read the letter, which was addressed to Gov. Martin O’Malley. “We urge you now to follow through on your commitment to public health and direct [the department] to expeditiously finalize — not delay or weaken — the proposed regulations that will protect our children.”
Ashville-based Innovative Solar Systems says it wants to start constructing large-scale solar farms in the state. North Carolina ranks fourth among states in installed solar capacity, but most of its projects are 5 MW or smaller.
Innovative Solar Systems is proposing 12 solar farms of between 25 and 80 MW, most of them in the eastern section of the state. The projects are still in the planning stage and will need large tracts of farmland, interconnection agreements and purchase power agreements. Taken in whole, Innovative’s planned projects will produce about 620 MW.
North Carolina provides a bullish solar energy climate, with green-energy mandates and tax credits.
Robert Powelson, chairman of the state Public Utility Commission, resigned from an energy-lobbying group last week over conflict-of-interest allegations.
A dispute over Powelson’s unpaid role as a member of the Greater Philadelphia Energy Action Team arose as the PUC was being asked to rule on Sunoco Logistics’ request to expand a natural gas pumping station in Chester County. The chairman of the advocacy group is Phil Rinaldi, CEO of Philadelphia Energy Solutions LLC, which lists Sunoco Inc. as a minority partner.
The Energy Action Team has acted as a booster for energy projects and expansion projects, including some regulated by the PUC. State law does not forbid commission members from unpaid positions with advocacy groups. Powelson’s resignation letter said he had minimal interaction with the Energy Action Team.
The Public Utility Commission said PECO’s restoration work in the wake of a winter ice storm was up to standards but said the company needs to improve communications with customers during such events.
Adding to customer frustration over power outages were erroneous messages from the company indicating that power had been restored when it had not. “Many of the phone calls that we got … [were] that people were frustrated by the lack of information, or the inaccurate information, they were getting from the utilities, including PECO,” said PUC Spokeswoman Jennifer Kocher. The company has until September to respond to the report.
FirstEnergy wants to amend its recent rate hike increase request to cover the cost of complying with a Public Service Commission mandate to read its customers’ electric meters monthly. In April, it asked for a 13.95% increase for its Monongahela Power and Potomac Edison subsidiaries.
The PSC ordered the monthly readings to begin in July 2015. FirstEnergy hasn’t said how much more it is seeking to comply with the order but previously estimated the cost at $15 million.
While the commission has indicated it believes it reasonable for FirstEnergy to cover the costs with rate hikes, critics are not so sure. “FirstEnergy created the problems that customers were having with their bills, denied for months that there were any problems and blamed everyone but itself for the impact on customers,” said Keryn Newman of the Coalition for Reliable Power. “Yet the PSC says it’s ‘punitive’ for the company to pay the cost of getting its billing right. That makes no sense.”
