FERC issued the order in February, accusing the company of billing ISO-NE for oil at its 181-MW plant in Pittsfield, Mass., while actually burning cheaper natural gas during a July 2010 heat wave. In dispute are a series of emails between Maxim employee Kyle Mitton and the Internal Market Monitor.
“Staff’s reply contains no credible evidence that Maxim or Mr. Mitton omitted any material fact in any of their communications with the IMM which left the IMM with any false impressions about what fuel actually was burned at Pittsfield,” Maxim said.
In its reply, Enforcement said Maxim “made a series of carefully managed statements about pipeline restrictions and the theoretical possibility of losses from offering gas and burning oil, and said nothing about what was actually happening at Pittsfield.”
In addition to the Pittsfield plant, Maxim operates two other plants in ISO-NE: CDECCA, a 62-MW cogeneration plant in Hartford, Conn., and Pawtucket Power, a 63.5-MW cogeneration plant in Pawtucket, R.I.
Transmission planners are considering additional changes to their light-load studies based on a reevaluation of three years of data that showed coal- and natural gas-fired generation are operating at higher capacity factors than previously assumed. Planners already had concluded that maximum wind capacity factors should be increased in the studies.
The analysis showed that capacity factors for coal generators during light-load periods — 1 to 5 a.m. from Nov. 1 through April 30 — have been trending up, in large part because retiring units are leaving more electricity to be generated by those remaining.
Planners are considering increasing the maximum ramping of coal plants 500 MW and larger above the current 60% and boosting the assumptions for coal plants below 500 MW above the current 45% maximum. PJM also is weighing an increase in assumptions for natural gas plants; planners currently assume they are not dispatched at all during light-load periods.
The analysis found large plants operated above the 60% capacity factor in about two-thirds of light-load hours RTO-wide during delivery year 2013-14, with the APS and AEP zones above that level about 80% of the time. Smaller coal units operated above their assumed capacity factor in about half of the hours RTO-wide. In APS, small coal ramped above the assumption in all light-load hours for the year, Mark Sims, manager of transmission planning, told the Planning Committee last week.
“A significant amount of coal has retired. What’s left is running more often because it’s more efficient and competitive,” Sims said.
Capacity factors also have been increasing during light-load hours for natural gas combined-cycle units as the fuel has become cheaper. RTO-wide, they operated in about one-quarter of light-load hours, with units in the AEP zone running in 86% of hours. When they are operating, they are generally doing so at capacity factors of 80% or higher.
No changes in assumptions are proposed for oil (assumed at 0%) and nuclear units (assumed at 100%).
PJM last month announced its intention to increase the maximum wind capacity factor from 80% to 100%, consistent with the modeling in MISO. (See Changes Proposed for Light Load, Wind Modeling.)
Sims said staff will conduct sensitivity analyses after finalizing their recommended changes and report back to the PC.
PJM Looks to Tweak Peak Load Forecast
PJM plans to recommend changes to improve its peak load forecasts by the end of June, officials told the PC. The revised model is an effort to better reflect customer usage, energy efficiency, weather and the impacts of “behind the meter” solar generation. (See PJM Seeking Improved Load Forecasts.)
PJM’s John Reynolds said efficiency in heating is continuing to climb, though not as dramatically in recent years. Meanwhile, cooling efficiency has leveled off and overall energy usage for cooling is expected to begin increasing by 2020.
PJM also is investigating the impact of distributed solar energy on demand. More than 1,700 MW of photovoltaic solar generation not registered as capacity resources is now receiving solar renewable energy credits in the PJM region, up from zero in 2005. Reynolds said most of the generation is in New Jersey, which has generous solar subsidies.
Planners expect to identify improvements to the model by the end of the second quarter, with revised manual language brought to stakeholders for endorsement by the end of the third quarter. Any changes would be implemented in the 2016 load forecast.
Long-Term Firm Transmission Study Endorsed
Members unanimously endorsed creating a Planning Committee sub-group to consider changes in how it studies long-term firm transmission service requests. The effort, initiated with a problem statement approved in March, is intended to ensure that individual requesters share in the cost of transmission upgrades required to serve them. (See Change Would Shift Baseline Upgrades to Network Customers.)
“PJM’s process, tools and thresholds have been established based around a local generation or transmission injection projects’ impacts and not around remote origination of energy,” according to the issue charge approved by members.
The group is expected to complete its deliberations by the end of the third quarter.
Committee Endorses Reserve Requirement Study
The PC approved revised assumptions for the 2015 PJM reserve requirement study that are expected to have a minor impact.
The study will determine the installed reserve margin, forecast pool requirement and demand resource factor for future delivery years and will look at the period from June 1, 2015, through May 31, 2026.
The two changes of note regard the computation of demand response and PJM’s proposed Capacity Performance product.
The study will use PJM’s new method of modeling demand response, which takes the average of the final amount of committed DR for the most recent three years. Previously, forecasters used the amount that cleared the last Base Residual Auction. (See Members Endorse Change to Demand Response Modeling.)
And, because the RTO’s Capacity Performance plan is in limbo as it awaits a ruling from the Federal Energy Regulatory Commission, the study will report using two sets of parameters — one with the CP product and one under the status quo. The forecast pool requirement values that ultimately will be applied will depend on whether FERC approves PJM’s plan. (See related story, PJM Responds to FERC Queries on Capacity Performance, Requests Approval.)
Order 1000 Problem Statement Approved
The PC approved a problem statement formalizing its work on process improvements as a result of Order 1000 “lessons learned.”
Although PJM already has begun incorporating the lessons — for example, introducing an improved method for receiving document submissions from transmission developers — officials said they decided a problem statement was needed because the issue would be a “standing agenda item” for the committee in the future.
PJM’s first project under the order, soliciting a fix for stability issues at New Jersey’s Artificial Island nuclear complex, has been beset by numerous delays and controversy. Planners expect to recommend a proposal to the Board of Managers next month — more than two years after the competitive window opened. (See related story, Planners Set April 28 for Artificial Island Recommendation.)
Republican Gov. Bruce Rauner has approved a bill allowing Commonwealth Edison and Ameren Illinois to avoid legislative review of a sweeping grid modernization program until 2019 instead of 2017.
Critics, including the Citizens Utility Board, worry that the move will allow the utilities to increase electric rates without being held accountable enough for their performance.
The bill passed both houses last year with bipartisan support, and Senate President John Cullerton (D-Chicago) waited to send it to the governor’s office until outgoing Democratic Gov. Pat Quinn, historically a utility antagonist, left office.
The Corporation Commission has ordered a reduction in the amount of drilling wastewater injected into deep disposal wells in light of a report linking the injections with earthquakes. The order relates to two counties bordering Oklahoma, which has experienced an increase in seismic activity apparently related to the disposal of wastewater produced from oil and gas wells.
“Because individual earthquakes cannot be linked to individual injection wells, this order reduces injection volumes in areas experiencing increased seismic activity,” the order states. “The commission finds increased seismic activity constitutes an immediate danger to the public health, safety and welfare. The commission finds damage may result if immediate action is not taken.”
The commission cited a study by the U.S. Geological Survey that showed an increase in the number of earthquakes corresponded with an increase in wastewater disposal. There were 30 earthquakes in Kansas between 1981 and 2000. In the first three months of this year, there have been 51 recorded earthquakes.
A Somerset County wind project has been scrapped after the developer tired of opponents who feared the wind turbine towers would endanger Naval Air Station Patauxent River. Pioneer Green Energy notified county authorities that it was withdrawing the plan, which would have built 25 turbines producing up to 150 MW.
State lawmakers pushed through a 15-month moratorium on the $200 million development, which then-Gov. Martin O’Malley vetoed. U.S. Sen. Barbara A. Mikulski pushed through a measure halting the project amid concerns that the turbine towers would interfere with the air station’s radar system. More legislation blocking wind development across the Chesapeake Bay on the Eastern Shore is brewing, with opposition growing against a planned 130-MW wind project near Kennedyville in Kent County. In view of the opposition, Adam Cohen, vice president of Pioneer Green Energy, decided to surrender. “We are truly saddened we cannot bring new investment, jobs and tax base” to Somerset County, he wrote to county officials.
Minnesota Power, State Reach Agreement on SO2 Releases
Minnesota Power reached an agreement with the Pollution Control Agency concerning sulfur dioxide emissions at its Taconite Harbor Energy Center in Schroeder. The 225-MW, coal-fired plant was the focus of attempts by environmental groups to force Minnesota Power to reduce emissions. The plant has been operating under a decade-old permit.
Minnesota Power has struggled to bring the plant into compliance and announced the closing of one of the three boilers this year. It also installed emissions-control technology, but it has not performed as expected. In addition to retiring one unit, the company will also pay a $1.4 million fine and spend $4.2 million on community projects. It will also need to submit a plan to the Public Utilities Commission that will outline what steps are being taken to reduce emissions further.
Supreme Court Rules Empire Must Offer Solar Rebates to All
Empire District Electric must offer all eligible customers solar rebates, the state Supreme Court has ruled. The court found that a state law exempting Empire from Missouri Clean Energy Act requirements was unconstitutional. The ruling spurred Renew Missouri, a clean energy advocacy group, to file a motion with the Public Service Commission to compel Empire to file an official tariff offering solar rebates by April 15. “Our hope is that Empire responds by immediately offering rebates,” said P.J. Wilson of Renew Missouri. “Their customers have been waiting since January 2010, the date Empire was required by law to start offering solar rebates. Today, the waiting should finally be over.”
The case came to the state’s high court as a result of developments dating back to 2007, when the state’s Renewable Energy Standard was passed. That standard called for utilities to get 15% of their energy from renewable sources by 2021 and to offer rebates to customers who wanted to install solar panels. But in 2008, lawmakers passed H.B. 1181, which exempted Empire from solar requirements. Renewable proponents challenged the law in court.
BPU Considering Request by New Jersey Natural Gas for Pipeline
New Jersey Natural Gas has filed a proposal with the Board of Public Utilities to build a 28-mile natural gas pipeline through three counties. If approved, the 30-inch pipline would start in Burlington County and run through Monmouth and Ocean counties. The proposed $130-million project, called the Southern Reliability Link, is designed to be a redundant line in the event an existing pipeline in Middlesex County is disrupted.
Already the plan is attracting opponents, who have previously organized against another project the company is involved with, the PennEast project. That proposed pipeline, which would run 110 miles from eastern Pennsylvania to Mercer County, has been the focal point of major opposition from community and environmental groups in both states. Some environmentalists note that the Southern Reliability Link is routed to go through federally protected pinelands. The first public hearings on the project have not yet been scheduled by the BPU.
Bill Would Allow Third-Party Leasing for Solar Installations
A Republican-backed bill would allow independent third-party energy companies to sell directly to homes and businesses. While the bill will likely attract opposition from utilities, the legislation would benefit solar developers. Major corporations are being enlisted to support the bill, which would allow independent companies to lease solar installations to home and business owners, and then sell the power produced directly to the owners, cutting out the utilities entirely. Wal-Mart, Target and Lowe’s have contacted House Speaker Tim Moore to support the bill, called the Energy Freedom Act.
“I’m coming at this from a Republican viewpoint,” said bill sponsor Rep. John Szoka of Fayetteville. “I believe in free markets and I believe in property rights. This allows property owners to use their property as they see fit.”
The state is already the nation’s fourth largest solar producer.
While the U.S. Environmental Protection Agency has released studies showing the probable impact of the rules of the Clean Power Plan on the nation, none of those studies get down to the state and local level. North Dakota hopes to change that by ordering a study that will examine the expected effects of the Clean Power Plan on natural gas prices, electricity rates and renewable energy production in the state. Gov. Jack Dalrymple signed a bill authorizing a study of the rules, which are expected to take effect this summer. Jason Bohrer, president of the Lignite Energy Council, said the study will look at the financial implications of the federal rules.
The Public Utilities Commission turned down Duke Energy’s request that it receive a ratepayer-guaranteed return for its share in two older coal-fired generation plants, rejecting the company’s argument that the arrangement would have provided long-term price stability for customers. PUCO in February denied a similar request by American Electric Power.
FirstEnergy has a similar request pending before the commission, and AEP has a request concerning other plants it says are at risk of closing if they are not guaranteed prices. The most recent decision involved the coal-fired plants owned by the Ohio Valley Electric Corp. OVEC’s shares are owned by Duke, AEP and FirstEnergy, among other companies. If PUCO had approved Duke’s request, its Ohio utilities would have purchased power from the plants at a long-term contract and then passed that price on to customers. Opponents have called the arrangements bailouts for the generating companies.
Andre Porter, a 35-year-old Republican and former member of the Public Utilities Commission who stepped down from the state Department of Commerce to rejoin it, was named PUCO chairman by Gov. John Kasich. Porter’s five-year term begins this week. He replaces Tom Johnson, who announced his resignation as chairman earlier this month. Johnson will fill out his term as one of the five members of the commission. Porter was widely seen to be Kasich’s choice when Johnson resigned.
AG Urges OCC to Drop Mustang Replacement from OG&E’s Plan
The state Attorney General’s office said Oklahoma Gas and Electric has not provided enough information about its planned replacement of the aging Mustang power plant to justify its request for $344 million in replacement costs. An assistant attorney general requested that the Corporation Commission drop the Mustang replacement request from the company’s $1 billion rate case. The company, however, disagrees. “There is a huge record in this case, and much of it is related to Mustang,” said Bill Bullard, an attorney for OG&E. If all of OG&E’s rate case is approved, it would increase the average residential customer’s bill by about 15%. The plan would replace the aging units with seven 40-MW combustion turbines.
PECO, PPL Ask PUC Approval to Boost Fixed Customer Charges
PECO and PPL Electric have filed requests with the Public Utility Commission that include substantial increases in the basic monthly customer charges. PECO asked to increase its monthly customer charge 68%, from $7.13/month to $12. PPL wants to increase its monthly rate from $14.13/month to $20, a 42% increase. The charges remain the same no matter how much electricity the customer uses. Both companies say they want to raise the charges to fund maintenance and upgrade costs for their electric distribution systems. In PECO’s case, the new charges would result in $84.5 million in revenue, almost half of the $190 million of its overall rate hike request.
Consumer advocates are crying foul, though. “It’s poor public policy,” said Bill Malcolm, a senior legislative representative for AARP. “Raising the fixed monthly charge lowers the variable per-kilowatt charge, which creates a disincentive for conservation and energy efficiency and gives consumers less control of their bill.” Others say the fixed rates strip away any incentive to reduce power usage. “It gives consumers less control of their bill because more of their bill is fixed and not based upon their usage,” acting Consumer Advocate Tanya McCloskey said.
Customers of Pennsylvania Electric and Pennsylvania Power will pay more for electricity beginning next month — about 13% more for Penelec customers and 7% for Penn Power customers.
The increases are part of rate settlements approved last week by the Public Utility Commission for FirstEnergy’s four state subsidiaries: Penelec, Penn Power, West Penn Power and Met-Ed.
The rate hikes are lower than what FirstEnergy originally requested last August. The increases in the base distribution rates are effective May 19 and are the first for each of the four subsidiaries in at least 20 years, according to the PUC.
Duke Agrees to $2.5M Settlement over Dan River Ash Spill
Duke Energy has agreed to a $2.5 million settlement with state environmental officials to offset damage caused when 39,000 tons of toxic coal ash from a retired power plant spilled into the Dan River. The company has reached a $102 million settlement with federal authorities and was fined $25 million by North Carolina in connection with the spill, which fouled 70 miles of the Dan River. The Department of Environmental Quality said $2.25 million will fund environmental projects in communities affected by the spill, and the remaining $250,000 will be retained for a DEQ environmental emergency fund. Danville, perhaps the hardest hit of the communities, is still negotiating with Duke over the spill.
The three-member Board of Commissioners of Public Lands has enacted a state ban on its employees using the term “climate change.” The reasoning, according to State Treasurer and Republican Matt Adamczyk: Climate change is “not part of our sole mission, which is to make money for our beneficiaries. That’s what I want our employees working on. That’s it. Managing our trust funds.”
The term “climate change” must not enter into that specific conversation, Adamczyk and Attorney General Brad Schimel, the other Republican sitting on the board.
“Having been on this board for close to 30 years, I’ve never seen such nonsense,” said the third member, Democrat and Wisconsin Secretary of State Doug La Follette, who voted against the measure. “We’ve reached the point now where we’re going to try to gag employees from talking about issues. In this case, climate change. That’s as bad as the governor of Florida recently telling his staff that they could not use the words ‘climate change.’”
Wind Capital Group said it is selling its last two U.S. wind farms to a California company. Wind Capital said it will sell the 150-MW Lost Creek wind farm in Missouri and the 210-MW Post Rock facility in Kansas to San Francisco-based Pattern Energy Group. Wind Capital said the sales, for a reported $244 million, will allow it to focus on its wind developments in the United Kingdom and Ireland.
Entergy Spending $62.2M on 24-mile Tx Line in Arkansas
Entergy Arkansas said it is spending $62.2 million to build a transmission line and a new substation to improve grid reliability in Drew and Desha counties. The company said it is part of a $2.4 billion investment through 2017 on system upgrades. It is already constructing another 27-mile transmission line that will end at the same new substation. That project is estimated at $25 million.
Duke Finds Hairline Crack on Reactor Head at Harris Plant
Duke Energy Progress discovered a hairline crack in the reactor pressure head of Shearon Harris nuclear generating station, but the company told the Nuclear Regulatory Commission that the crack poses no danger. The crack will be repaired during the current refueling outage, the company said. “The unit is in a safe and stable condition,” Duke told NRC. “The flaw and repair have no impact to the health or safety of the public.”
The crack, measuring about a quarter-inch, is near a nozzle that penetrates the reactor head. It is similar to a crack that was missed during a 2012 refueling inspection and caught later during a data review. After that incident, NRC ordered Duke to ensure such an incident didn’t happen again.
NextEra Energy Resources is investing $640 million on two more wind farms in Colorado. The company already has invested about $2 billion on seven Colorado wind farms generating about 1,175 MW. The company said the two new wind farms should be ready to come online by the end of the year.
The first facility, a $240 million 150-MW wind project in Kit Carson County, has a 25-year contract to sell its output to Tri-State Generation and Transmission Association. The second facility, the $400 million 250-MW Golden West Wind energy Project, will be in El Paso County and will sell its output to Xcel Energy.
NextEra is the largest wind farm operator in the U.S., with 10 GW of turbines.
E.ON Starting Asset Management, Repair Businesses in US
E.ON, the world’s largest investor-owned utility, is branching out into the asset management and facility repair business in the United States. The company owns or operates nearly 3 GW of generation in North America, and now it’s starting up E.ON Energy Services. The new business will offer on-site repair and asset management operations for plants it does not own. “As we transitioned to an operations-focused company several years ago, we saw a large growing demand for qualified service providers,” E.ON’s North American chairman Patrick Woodson said. He pointed to the continent’s growing wind and solar industries as an area where the company could expand.
Advanced Power Gets Funding for $899M Combined-Cycle Plant
Advanced Power, based in Switzerland, has closed financing for an $899 million combined-cycle plant it will build in northeastern Ohio. The 700-MW natural gas-fired plant will sell energy, capacity and ancillary services into the PJM market. Advanced Power secured $411 million in funding from TIAA-CREF, Ullico and Prudential Capital Group, and a further $488 million from BNP Paribas, Credit Agricole and eight other banks. The Carroll County Energy Project will be in Carrollton, Ohio, close to both the Utica and Marcellus shale gas fields, as well as American Electric Power’s 345-kV transmission line.
The company did not say when construction would begin.
Duke Appeals $25 Million Ash Fine, Calls it Excessive
Duke Energy is appealing a $25.1 million fine levied by North Carolina environmental officials in connection with groundwater pollution from ash piles at a retired power plant. Duke says the fine is excessive and that it has taken corrective action.
The state Department of Environment and Natural Resources fined the Charlotte, N.C.-based company in March for failing to control ground water leaching from the coal ash lagoons at the now-retired L.V. Sutton Steam Electric Plant near Wilmington, N.C.
The fine is separate from a $102 million settlement the company agreed to pay federal authorities for the damage caused by a massive leak of toxic coal ash from another retired plant, near the Dan River. That event last year caused pollution in two states — Virginia and North Carolina — after a broken pipe allowed coal ash slurry to flow into the river. The company still faces litigation from Virginia and private property owners as a result of that leak. North Carolina, in response, enacted coal-ash legislation and formed a formal oversight committee.
Duke’s appeal of the Sutton fine notes that the company had already taken corrective actions to stop and remediate the leakage from the retired plant. It also claims that state environmental officials erred in fining the company for 1,822 days of violations, despite only taking samples for 27 days, using a new way of calculating the fine, making it $24 million higher than fines for earlier, similar events, and failing to take into account the possibility of other sources of contamination.
Northern Indiana Public Service Co., which filed a complaint in 2013 over its frustrations with MISO and PJM’s interregional planning process, says nothing much has changed since then.
“Close to one and one-half years have passed since NIPSCO filed its complaint in this docket, and the same pattern of a great deal of process with no results appears to be holding,” the utility said in a March 31 filing with the Federal Energy Regulatory Commission.
More than a decade after the MISO-PJM seam was formed, no cross-border projects have been approved and built, while hundreds of millions of dollars in market-to-market payments have been made, NIPSCO said, “including approximately $500 million since 2008.”
A MISO member, NIPSCO is located between two PJM transmission zones, Commonwealth Edison to the west and American Electric Power to the east.
NIPSCO’s filing was one of almost a dozen responses FERC received from MISO and PJM stakeholders in response for its request for comments on six rule changes proposed by NIPSCO. (See related story, FERC Floats Possible Orders on PJM-MISO Seam.)
FERC posed the questions as preparation for a yet-to-be-scheduled technical conference on the issues raised in NIPSCO’s complaint (EL13-88).
Three-Step Process
NIPSCO wants FERC to order the MISO-PJM cross-border transmission planning process to run concurrently with, rather than after, the RTOs’ regional transmission planning cycles.
Without such a change, NIPSCO said, it would take more than three years for a beneficial market efficiency project to navigate its way through the three independent processes currently in place.
As an example, NIPSCO pointed to its proposed Reynolds-Wilton Center project, which had been part of the market efficiency study process in MISO’s Transmission Expansion Plan (MTEP13).
Proposed in May 2012, the project was found by MISO to have a strong benefit-to-cost ratio and would have had significant benefits for PJM, NIPSCO contends.
The project was put on hold until it could be studied in the Interregional Planning Stakeholder Advisory Committee process. It didn’t pass; MISO re-evaluated the project a year later, but it didn’t pass MISO market efficiency metrics.
Had it passed IPSAC, however, it would have taken 42 months, NIPSCO estimates.
As it stands, a project would first have to pass through one regional process, with its specific metrics and an independent model built for that study year. Then it would have to pass an interregional process with specific metrics. Lastly, it would have to pass the final regional process again with its specific metrics and model, NIPSCO said.
“Over 10 years of history have verified that no developer has had the necessary foresight or fortitude to successfully run the gauntlet of the MISO-PJM interregional process. NIPSCO, therefore, does not believe that it is possible for a project to navigate all three existing processes.”
NIPSCO is not alone in that view. Southern Indiana Gas & Electric also faulted the three-step process in its response to FERC’s questions.
Other Views
But other stakeholders, including ITC Transmission, said they don’t believe that forcing the cross-border and regional transmission planning processes to run concurrently is the most effective approach. ITC recommends that FERC require MISO and PJM to eliminate the three-step approval process altogether.
Instead, ITC said that projects approved in the coordinated system plan under provisions of the MISO-PJM Joint Operating Agreement should automatically be recommended for approval by both RTOs for cost allocation in their respective regional transmission plans.
“MISO and PJM should also establish a new project category for ‘interregional projects’ in their respective regional planning processes,” ITC said.
Among other stakeholders weighing in is AEP, which maintains that modifying the JOA to conduct concurrent joint and regional studies with identical criteria “is simply untenable.”
AEP said each RTO has planning criteria to address its regional needs, plus has to coordinate with other transmission systems whose regional planning criteria may differ. AEP also said FERC Order 1000 specifically recognizes that regional differences are valid.
As for cross-border market efficiency projects, AEP suggests that each RTO use its regional study process to quantify its regional market efficiency needs and congested flowgates. They also should invite stakeholders to submit both regional and interregional proposals.
“If the sum of each RTO’s portion meets or exceeds the total cost of the interregional proposal, then the proposed interregional project would be included in the list of finalists from which the most efficient and cost-effective projects would be selected,” AEP said.
Cost apportionment of approved cross-border projects would be in proportion to the market efficiency benefits that each RTO derives, AEP said.
RTOs: Process is Improving
MISO and PJM rejected assertions that their regional transmission planning cycles are impeding cross-border projects.
In joint comments to FERC, the RTOs say they already have a “highly aligned” interregional planning cycle.
In a joint 2014 study, both RTOs evaluated cross-border transmission issues and identified opportunities for more than 80 projects “using a single model with a single set of mutually agreed upon assumptions.”
“Although no project passed the interregional or regional criteria, any interregional projects would have had timely approval in both the regional and interregional processes,” the RTOs said. “Accordingly, the respective planning cycle timing and synchronization was not an issue; rather, the fact that projects did not pass the cost/benefit analysis exclusively relates to the criteria themselves rather than any mismatch in the timing or lack of coordination between the interregional planning analysis and the respective RTEP and MTEP processes.”
‘Quick Hit’ Projects
Since NIPSCO’s complaint, the RTOs noted, they have proposed to build at least 26 “quick hit” transmission projects that could be done quickly and cheaply on lower voltage flowgates to address constraints on both sides of their seam. (See MISO, PJM Ponder List of ‘Quick Hit’ Upgrades).
PJM officials told the Transmission Expansion Advisory Committee last week that the projects could eliminate $280 million of the $400 million in annual congestion at the top 38 historical market-to-market constraints.
PJM’s Chuck Liebold said the quick-hit effort resulted after planners asked themselves, “Are we missing something that would be easy to do?”
“We’re trying to do the right thing,” he said. “We’ve had studies that haven’t produced any projects.”
PJM on Friday filed a 37-page response to questions raised by the Federal Energy Regulatory Commission about its Capacity Performance proposal and requested that the board accept the plan effective April 1 so that it may implement the changes in the Base Residual Auction scheduled for next month.
“Despite [their] success in retaining and attracting sufficient capacity to ensure resource adequacy requirements are met, the capacity markets are failing to incentivize adequate generator performance. Resources in PJM have not performed as expected,” PJM said.
“Simply, [the Reliability Pricing Model’s] current capacity market performance incentives and requirements are weak, and therefore require immediate reform,” PJM said, noting that the auction secures commitments on a three-year, going-forward basis.
“If PJM deferred these changes to the following BRA, held in May 2016 for the delivery year that starts on June 1, 2019, it would mean that the PJM region would let five more winters pass after 2014 without implementing a full remedy to the manifestly deficient performance requirements in the current rules,” it said.
Hoping to Avoid Auction Delay
While the RTO had 30 days to respond to FERC’s March 31 order deeming its Capacity Performance filing deficient, it expedited the reply in hopes it can avoid having to postpone the BRA — something it has never done. However, because of the uncertainty surrounding the new Capacity Performance product — and because the Tariff requires the auction be held in May — the RTO last week requested a waiver to delay the BRA. (See PJM to Respond on Capacity Performance Friday; Seeks Auction Delay.)
PJM said that if FERC does not respond to the waiver request by April 24, the RTO will consider it withdrawn. Meanwhile, it is advising stakeholders to prepare for the auction to be held as scheduled May 11-15.
FERC’s four-page order questioned 10 areas of the proposal, which was conceived to increase reliability expectations of capacity resources with a “no excuses” policy (ER15-623). PJM’s proposal called for larger capacity payments for over-performing participants and higher penalties for non-performers.
FERC asked PJM to explain its derivation of an appropriate competitive clearing price when no new capacity is required in a locational deliverability area (LDA), and to provide more detail on a default offer cap and how it would apply in several situations.
PJM responded in detail, saying “a default Capacity Performance resource offer cap, based on net [cost of new entry] times the balancing ratio, is reasonable and appropriate.”
Balancing Ratio
PJM introduced the balancing ratio to adjust a resource’s committed unforced capacity (UCAP) to reflect its expected performance during Performance Assessment Hours. The proposed ratio would be calculated by dividing total load and reserves on the system by total generation and storage capacity commitments during the Performance Assessment Hour.
Regarding concern raised by some interveners that the balancing ratio is too difficult to estimate in advance, PJM said that if the commission accepts the offer cap agreed upon by PJM and the Independent Market Monitor, it will use a historical weighted average based on the previous three delivery years. During that period, there were 70 hours — including 42 hours of RTO-wide emergency — that would have been Performance Assessment Hours.
“Capacity Performance provides extremely strong incentives for resource availability and therefore, over time, will eliminate occurrences like those seen in the winter of 2014,” PJM said. “As a result, the expected value of the balancing ratio is anticipated to increase over time to a value that is more indicative of the summer Performance Assessment Hours, which averaged around 93.5%.”
FERC also requested any analyses the RTO had conducted on expected performance charges and bonus payments under the proposal. The commission asked if it made sense to phase in the penalties and for ideas of how to provide incentives for resource performance. In addition, it asked PJM how it plans to evaluate the performance of external resources not pseudo-tied to the RTO.
PJM cited the transitional structure it proposed in the plan that would allow PJM and capacity market sellers to adjust to the new product over the two remaining delivery years before 2018/19.
“As such, PJM therefore believes that it is unnecessary to provide further transition into the Capacity Performance structure from the standpoint of the non-performance charge, because load should be assured that Capacity Performance resources have the full incentive to invest appropriately in their resources from the 2018/2019 delivery year forward,” it said. “Phasing in the non-performance charge rate beyond what PJM has already proposed in its transition mechanism would inappropriately dilute this incentive.”
PJM and utility officials said yesterday they are still investigating what caused the failure of a 230-kV transmission line that briefly cut power to the White House and much of the D.C. area Tuesday afternoon.
The incident caused a drop in voltage that led the Calvert Cliffs nuclear units to trip offline and federal agencies and other customers to transfer to their backup systems.
The incident occurred around 12:40 p.m. after a fault on a 230-kV transmission line in southern Maryland, PJM’s Chris Pilong told the Market Implementation Committee on Wednesday. Pilong said the failure was believed the result of “failed insulation.”
The Southern Maryland Electric Cooperative (SMECO) said the incident occurred at the Ryceville substation in Charles County when a PEPCO conductor “broke free from its support structure and fell to the ground.” CNN reported that local firefighters extinguished a small fire at the substation, which is jointly owned by PEPCO and SMECO.
“No other outside influences are expected,” Pilong said. “It was just a fault, a failed insulator.”
Maintenance Outage
Pilong said the incident occurred while several 230-kV lines in the area were out of service for planned maintenance and that the problem was exacerbated by a stuck breaker. Three remaining 230-kV lines and a 500-kV bus were lost, and the fault and voltage drop “rippled” to surrounding substations, he said.
SMECO said the failure cut power to its Ryceville and Hewitt Road stations as well as PEPCO’s supply to the Morgantown and Chalk Point interconnections. “No SMECO equipment was damaged and all protective devices operated correctly to isolate SMECO equipment from the PEPCO fault,” it said.
The grid recovered — returning its area control error to normal bounds — in about seven minutes, Pilong said.
The outage trapped people in elevators, darkened D.C.’s subway stations and caused some institutions — including a Department of Energy building, the main campus of the University of Maryland and some Smithsonian museums — to shut down for hours, The Washington Postreported.
Wholesale Prices Spike
In addition to causing disruptions to consumers and businesses, the incident resulted in a spike in wholesale prices, with real-time LMPs in the BGE zone rising from less than $38 at noon to more than $344 for the 1-2 p.m. hour. The other zones most affected were DOM, PEPCO and APS (see chart).
Initially, it was thought that up to 500 MW might have been lost, but later it was determined that customers had switched to off-grid power. About 300 MW returned to the grid within 40 minutes, PIlong said. By late afternoon, only the line that was the source of the fault was out of service.
“There was never a loss of permanent supply of electricity to customers,” PEPCO said.
Calvert Cliffs
Exelon, which operates the Calvert Cliffs units, said the plant shut down automatically as designed during significant electrical disturbances. However, Exelon told the Nuclear Regulatory Commission it is investigating why an emergency diesel generator serving Unit 2 did not start.
“Both reactors will remain in ‘hot shut-down,’ which means the reactor remains ready to resume power production, until the offsite grid disturbance can be addressed,” Exelon said.
As of Wednesday evening, the NRC still listed output at Units 1 and 2, which have a combined capacity of 5,474 MW, as zero.
VALLEY FORGE, Pa. — PJM plans to respond by Friday to the Federal Energy Regulatory Commission’s questions about its Capacity Performance proposal, Executive Vice President for Markets Andy Ott told the Market Implementation Committee Wednesday.
On March 31, FERC said PJM’s proposal to increase capacity resources’ compliance penalties and rewards was deficient and gave the RTO 30 days to provide additional information (ER15-623). (See FERC: PJM Capacity Performance Filing ‘Deficient.’)
The RTO is expediting its response in hopes of getting quick clarity into the rules that will govern its upcoming Base Residual Auction so that stakeholders have time to prepare, Ott said.
On Tuesday, PJM asked FERC to delay the May 11-15 BRA (ER15-1470). The RTO requested that the commission act on its request by April 24, with comments due by April 14. PJM’s filing Tuesday asked for permission to delay the BRA until 30 to 75 days after a commission order on the merits of the proposal, but no later than the week of Aug. 10-14.
If FERC does not respond by April 24, PJM will withdraw its waiver request and conduct the auction under current Tariff requirements in May.
“We’re trying to get a signal from FERC as to which approach we should take,” Ott said. “We’re looking for certainty.”
“Delaying the auction is not something we’ve done lightly,” he added.
Still hoping to win approval for its proposed revamp of capacity market rules, PJM asked the Federal Energy Regulatory Commission Tuesday to delay the May 11-15 Base Residual Auction.
PJM’s filing Tuesday asked for permission to delay the BRA until 30 to 75 days after a commission order on the merits of the proposal, but no later than the week of Aug. 10-14 (ER15-1470).
The RTO requested that the commission act on its request by April 24, with comments due by April 14.
Andy Ott, executive vice president for markets, will brief the Market Implementation Committee at about 10:30 a.m. Wednesday on the RTO’s plans for responding to the deficiency order.
Five transmission projects intended to serve New York City and respond to a potential nuclear plant closure suffered setbacks last week as a divided Federal Energy Regulatory Commission rejected the developers’ cost allocation proposals and reduced their requested returns on equity (ROE).
The commission granted some of the developers’ requests for ROE incentives but ordered settlement and hearing proceedings on proposed formula rates, protocols and the base ROE (ER15-572).
On Dec. 4, NYISO proposed a cost-of-service formula rate template and formula rate implementation protocols on behalf of New York Transco, comprised of affiliates of the New York Transmission Owners, Consolidated Edison of New York, National Grid, Iberdrola USA and Central Hudson Gas & Electric.
The companies submitted five projects in response to competitive solicitations issued by the New York Public Service Commission.
Two AC projects, the estimated $1 billion Edic-Pleasant Valley 345-kV line and the $246 million Oakdale-Fraser 345-kV line, are intended to alleviate congestion on transmission lines serving the New York metropolitan area. (See Tx Plan to Open NY Choke Points Without New ROWs.)
The other three “Transmission Owner Transmission Solutions (TOTS)” projects were designed to address reliability concerns expected if the Indian Point nuclear plant closes. NYISO and the transmission owners sought an April 3 effective date on their proposed formula rate, protocols, cost allocations and 10.6% base return on equity.
The commission:
Granted requests for construction work in progress, abandonment and pre-commercial cost recovery incentives, and a 50-basis-point ROE adder for membership in an RTO, subject to a cap within the “zone of reasonableness,” to be established through the hearing procedures.
Approved an ROE adder for risks and challenges for the Edic-Pleasant Valley 345-kV line while rejecting it for the Oakdale-Fraser 345-kV line and the TOTS projects.
Ordered the applicants to revise sections 3(e)(ix) and 4(b) of the formula rate protocols, as requested by the New York Association of Public Power, to provide more transparency. The commission said it was concerned with the allocations of shared plant or expense items between members of NY Transco and their parent companies.
Rejected the cost allocation for all five projects.
Denied applicants’ request for an ROE adder for being a transmission company. The commission said NY Transco’s members were not “sufficiently independent” to merit incentives, noting that they serve 84% of the state’s load and own 64% of its high voltage transmission and 4% of its generation capacity.
Ordered hearing and settlement procedures on NY Transco’s proposed formula rates, protocols and base ROE, including components of the formula rate and the allocation of various expenses between the TOs and NY Transco. The commission ordered appointment of a settlement judge within 15 days and a report on the status of negotiations by May 4.
Dissents on Capital Structure
The majority also rejected applicants’ request for a “hypothetical” capital structure incentive of 60% equity and 40% debt for all five projects, instead approving a 50/50 structure.
NY Transco said it would use its actual capital structure in the formula rate after the projects are placed into service but that the hypothetical capital structure would improve its credit rating, reducing financing costs by $168 million compared with a 50/50 structure.
The majority said it agreed with protests by the PSC and others that the 60/40 capital ratio is “excessive for an entity such as NY Transco, whose affiliates … will construct the projects and perform the maintenance and physical operation of the NY Transco assets.”
That sparked a partial dissent by FERC Chairman Cheryl LaFleur and Commissioner Philip Moeller. “Today’s order does not merely apply an overly rigid approach to evaluating these capital structures; the majority has failed to provide any criteria or guidance as to how the commission will evaluate these capital structures going forward,” they wrote. “We believe the applicants demonstrated the required nexus between the need for the requested hypothetical capital structure and the facts of this particular case, and we would have granted the requested transmission incentive.”
LaFleur and Moeller also said the additional proceeding adds “needless uncertainty” to efforts to expeditiously build transmission infrastructure.
Cost Allocation
The commission rejected the cost allocation method for the AC and TOTS projects because it imposed costs on the New York Power Authority and the Long Island Power Authority, both public entities that have not been allowed to join NY Transco.
The PSC said the cost allocation proposal it initially supported included the voluntary participation of LIPA and NYPA, and covered 18 transmission projects throughout the state. NY Transco was originally planned as a six-party Transco, which included NYPA and LIPA, but the New York state legislature refused to allow NYPA permission to participate.
NYPA serves municipal systems throughout the state, but NY Transco’s cost allocation proposal would have assessed its municipals located upstate at the same rate as downstate municipals. “Grossly inequitable situations would arise where a NYPA customer located in the Rochester region would be allocated 16.9% of the costs while another [Rochester Gas & Electric] customer located across the street … would be allocated only 8.9% of the costs,” the commission said.
Because NYPA and LIPA have not accepted the cost allocation method, it cannot be considered a “participant funding method,” the commission said.
The applicants had proposed to allocate the costs of the three TOTS projects using an adjusted load ratio share approach, with 75% of the costs allocated to transmission districts southeast of the UPNY/SENY constraint and 25% allocated to upstate districts, a departure from the default ratio for public policy projects (60% downstate, 40% upstate). The PSC adopted a 90% downstate/10% upstate cost allocation for the AC projects.
The commission said the AC projects could qualify for regional cost allocation if the PSC decides they should be evaluated under NYISO’s Order 1000 public policy transmission planning process and the ISO selects the projects in the regional transmission plan.
Because the TOTS projects were evaluated by the PSC before NYISO’s Order 1000 transmission planning process, the ISO must reevaluate and select them to be eligible for regional cost allocation, the commission said.
Alternatively, the commission said the applicants may submit a revised allocation shared only by entities that agree to pay, “either by renegotiating the cost allocation with LIPA and NYPA or by allocating the costs solely among those transmission developers participating in the NY Transco.”
AC Projects
The commission said the 153-mile, Edic-Pleasant Valley 345-kV line deserved a risk-reducing incentive because it would relieve transmission congestion on existing lines by 41% in 2022.
The project would connect National Grid’s Edic substation in Oneida County to Con Edison’s Pleasant Valley substation in Dutchess County, entirely within existing rights-of-way. The project, including three new substations, would move an additional 1,000 MW from central New York to the southeast region. The line is expected to reduce transmission congestion costs, line losses and installed capacity costs by a net present value of almost $1.3 billion to $4.5 billion over 10 years.
The commission rejected such a bonus for the Oakdale-Fraser 345-kV project, saying it was not convinced it relieved “chronic and severe congestion.” The project would add a second, 57-mile 345-kV line between the Oakdale and Fraser 345-kV substations.
Indian Point Contingency
The three TOTS projects were approved by the PSC as a contingency plan for the loss of Entergy’s Indian Point nuclear plant. Entergy told investors last year it would consider shutting down the plant’s two units if it can reach a “constructive” settlement with state officials.
The transmission projects, which have an in-service deadline of June 1, 2016, are the:
Fraser-Coopers Corner project, estimated at $66 million, which will increase power transfer by reducing series impedance over the existing 345-kV Marcy South transmission lines;
Ramapo-Rock Tavern project ($121 million), which will add a second 345-kV line from Con Edison’s Ramapo 345-kV substation to Central Hudson’s Rock Tavern 345-kV substation; and
Staten Island Unbottling Project ($262 million), which involves transmission upgrades to Con Edison’s interconnecting 345-kV transmission line with Cogeneration Technologies Linden Venture, to allow generating facilities located on Staten Island to export power to the rest of New York.
