PJM officials said last week that the RTO’s payments to frequently mitigated units (FMUs) jumped significantly over the winter, lending urgency to efforts to reduce the number of such units receiving “adder” payments.
Adder payments “suddenly became a much larger problem than it was before as a result of conditions that occurred in the winter,” PJM’s Tom Zadlo told the Markets and Reliability Committee Thursday. “We have seen a lot more units being frequently mitigated not because of thermal problems but for units running for reactive and automatic load rejection [black start] support.”
As a result, instead of the typical FMU profile — a combustion turbine running 300 hours per year — payments are going increasingly to generators running 1,000 to 3,000 hours yearly, which are operating “more like intermediate units,” Zadlo said.
PJM Executive Vice President for Operations Mike Kormos said the dynamics changed because rising gas prices made coal units more competitive.
The disclosure came on the first read of a proposal by PJM and the Independent Market Monitor that would limit the adders to units whose net revenues are not covering their avoidable cost rate (ACR). 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.
Zadlo said the proposal will be flexible enough to “self-correct” if capacity market revenues increase, reducing the need for adders.
FMUs were allowed adders of $20 to $40/MWh to ensure that they cover their avoidable, or going-forward, costs. Market Monitor Joe Bowring said the adders became unnecessary for most units since the introduction of the capacity market in 2007 and changes to scarcity pricing rules in 2012.
The PJM-IMM proposal will be brought to a vote at the MRC’s next meeting. It appears to face strong opposition from generators, having won only 27% support in a poll of a generation-heavy Market Implementation Committee subgroup that has been considering alternatives. (See PJM-IMM Plan on FMUs Faces Generator Opposition.)
Ed Tatum, of Old Dominion Electric Cooperative, said the change in the FMU profile suggested a need to consider transmission upgrades.
“We are,” responded Kormos. “Unfortunately, transmission is always playing catch up.”
The proposal would eliminate all adders for fixed resource requirement (FRR) units, which prompted a protest from Dana Horton of AEP. “Why are FRRs getting picked on?” he asked.
The fixed revenue requirement allows load-serving entities to meet their capacity obligations by using their own resources rather than participating in the capacity auction. PJM officials said FRRs get going-forward costs from another revenue stream.
The PJM/IMM proposal is one of six packages on which the MIC subgroup — 22 responders representing 138 members — were polled. Two of the proposals (packages D and E) have since been withdrawn, Zadlo said.
The remaining three alternatives to the PJM/IMM plan each received support of at least two-thirds of those polled.
Package F has been “slightly tweaked” since the polling, Zadlo said.
The bill for cleaning up coal ash from decades of operations in North Carolina could approach $10 billion, a Duke Energy executive told state lawmakers last week. In February, a broken pipe at an impound pond dumped tons of ash into the Dan River.
Coal ash pile at Duke Energy’s retired Dan River Steam Station in Eden, N.C. (Source: Duke)
Duke said two weeks ago that cleaning up that spill could reach $15 million but would not affect earnings.
But in a meeting with lawmakers last week, Duke’s North Carolina President Paul Newton said cleaning up the estimated 100 million tons of ash at 33 coal ash dumps at 14 coal-fired plants in the state could approach $10 billion unless the company is given some flexibility in how it approaches the problem. Newton said a large part of that cost could fall on ratepayers. “We are doing, and will continue to do, what it takes to make this right,” said Newton, who repeated his earlier public apologies for the spill.
Molly Diggins, the director of the N.C. Sierra Club, scoffed at Duke’s presentation. “Despite being a Fortune 500 company, with profits of $2.7 billion last year, Duke Energy has successfully been allowed to manage its wet coal ash waste as if the clock had stopped half a century ago,” Diggins said.
Time is running out for policy makers to recognize the value of nuclear generation as an “always-on source of carbon-free energy,” Exelon Senior Vice President and Chief Strategy Office William Von Hoene Jr. told the United States Energy Association Public Policy Forum last week.
“The loss of 25% of existing nuclear facilities would cut U.S. progress toward achieving its 2020 climate change goals in half. In fact, closing even a few nuclear plants could make achieving state and national carbon reduction goals difficult or impossible,” Von Hoene said, citing government energy policy and market structures. “The unfortunate reality for nuclear right now is that, despite being the largest, most reliable and lowest-emitting power plants — and among the lowest cost — they are not getting recognized or compensated for those attributes.”
Von Hoene said nuclear generation helped prevent a threat to grid reliability during last winter’s brutally cold weather. Nuclear generation came through when other generation sources, such as coal- and natural gas-fired plants, experienced high outage rates.
Exelon’s Handley Generating Station, Fort Worth, Texas (Source: Exelon)
A combination of plant retirements, nuclear plant uprates, energy efficiency and other programs helped Exelon reach its goal of eliminating 17.5 million tons of greenhouse gas emissions seven years before its 2020 target, the company said last week.
Exelon said it reduced its GHG emissions by 9.8 million tons through fossil plant retirements and company energy-efficiency programs. It chalked up another reduction by adding 316 MW of emission-free generation through uprates to its nuclear fleet. Customer energy-efficiency programs through its BGE, ComEd and PECO utilities counted for a 3.3 million ton reduction, it said.
The Federal Energy Regulatory Commission last week approved NRG Energy’s plan to sell stakes in a collection of co-generation plants in California while obtaining full ownership of a 586-MW natural gas-fired plant in the state. It is the latest in a series of reallocations and consolidations by the company.
NRG, which already owned 50% of Sunrise Power Co. LLC, purchased the other 50% of the natural gas plant from affiliates of oil-producer Chevron, which in turn will assume NRG’s 50% ownership in the co-gens. NRG had assumed the ownership of the co-gens as a result of its recent purchase of Edison Mission Energy.
Xcel Energy ranked as the nation’s top utility in wind energy for the 10th straight year, according to a study from the American Wind Energy Association. Xcel produces more than 5,000 MW through its wind facilities, 15% of its total capacity.
“We embraced wind energy early because it’s clean, cost-effective and will protect our customers against rising fuel prices in the future,” said Xcel CEO Ben Fowke in a written statement. The company said it is ahead of its goal of cutting its carbon emissions by 20%, predicting a 31% reduction over 2005 levels by 2020. Last year Xcel announced plans to expand its wind power use by another 40% over the next several years. The company is finalizing approvals and agreements to participate in nine new projects that will add a total of 1,900 MW throughout its service territory, enough to serve about 900,000 homes.
FirstEnergy Waives Polar Vortex Charges for Residential Customers
FirstEnergy Solutions is backing off plans to assess residential customers a surcharge for spiking energy prices during this winter’s polar vortex. The move came after Ohio regulators announced an investigation into the charges, which would have cost customers $5 to $10 each.
FirstEnergy earlier said it would pass through wholesale energy charges originating from PJM after the RTO had to resort to expensive emergency procedures to ensure system reliability.
Although FirstEnergy’s Ohio residential customers are off the hook, aggregation customers are still subject to it. One Ohio aggregator town, Parma, has filed a complaint with the Ohio regulatory agency about the surcharge, which would average about $7 per customer.
ComEd’s Grand Prairie TX Line Plan Greeted with Opposition
About 300 people attended a public meeting last week to discuss ComEd’s plan for a 60-mile transmission line between Exelon’s Byron Nuclear Generating Station and a substation in Wayne. The Grand Prairie project, intended to relieve transmission congestion in the area, would save customers about $500 million over the course of the first 15 years, said Fidel Marquez, ComEd’s senior vice president for governmental and external affairs. “We fully recognize that people have concerns and questions,” he said, adding, “We understand that no route will satisfy all constituents.”
Many residents said they were opposed to the $250 million aerial transmission project and asked if it could be constructed underground. A ComEd representative said it would cost about $50 million to bury power lines on a single 1.8-mile stretch. The Illinois Commerce Commission is expected to make a decision about the project by mid-July.
High Power Prices, High Demand Push Up AEP’s Earnings, Guidance
Higher demand and increased power costs pushed American Electric Power Co.’s first-quarter earnings up 54% over 2013. The company increased its 2014 earnings guidance to $3.35 to $3.55 a share from $3.20 to $3.40 a share. The company posted earnings of $560 million, or $1.15 per share, up from $363 million, or 75 cents a share, a year ago.
“Solid regulated business results and strong performance from our competitive energy businesses, bolstered by favorable weather and high power prices, resulted in a very positive first-quarter 2014 performance,” CEO Nicholas Akins said in a statement. “Our competitive Generation and Marketing business performed incredibly well during the extreme weather and helped meet record demand in the PJM Interconnection.”
Ameren Illinois is seeking a $69 million rate hike it says follows the mandate to set up a “smart grid” program. If approved, it would mean increases of between $6.37 and $9.55 a month for the average residential customer.
Illinois’ smart-grid law calls for the state’s utilities to invest millions in the electric grid in exchange for a formula-based rate process that lets companies recoup costs quickly. “Rates have decreased significantly through the formula rate process,” Craig Nelson, the company’s senior vice president of regulatory affairs and financial services, said in written testimony submitted to the commission. “As a result, even with the full impact of this rate increase, most residential customers will be paying less in 2015 than they did in 2011.”
Utility watchdogs vowed close scrutiny. “We will do our best to eliminate unjustified spending and reduce the proposed increase as much as possible,” said David Kolata, executive director of the Citizens Utility Board, an Illinois consumer group.
INDIANA Indianapolis Electric Car Program Spurs Call for $16 Million Rate Hike
(Source: Wikimedia)
The city of Indianapolis joined Indianapolis Power and Light in a request for a $16 million rate hike to fund the city’s proposed electric car sharing program.
The rate hike, which would cost the typical residential customer about 44 cents monthly, would go into effect January 2018.
IPL said it would cost about $16 million to build and power 1,000 charging stations for the cars, which residents could rent for as little as 15 minutes at a time. Bollore Group, a French concern, would provide 500 plug-in cars and will invest $35 million in the program.
The electric car sharing service would be the largest in the United States and would complement Bollore’s plan to convert the city’s 3,100-vehicle fleet to electric, natural gas or hybrid vehicles by 2025.
Pepco is asking regulators for a $43 million rate hike, its third increase request in three years. The increase, which would go into effect July 4, would raise the average monthly bill for customers in Montgomery and Prince George’s counties by $4.80. This would come atop a 2013 increase of $27 million.
Pepco has been a magnet for criticism for several years, primarily due to its reliability record. “Pepco should not be allowed to request a rate increase from the [Public Service Commission] until it can prove that it can keep power on consistently for one month,” said Abbe Milstein, founder of Powerupmontco, a group that advocates for ratepayers’ rights.
Pepco CEO Joseph Rigby has said the company plans to file a rate increase request every year for the next couple years.
NEW JERSEY Fisherman Wind Project May Not Be Dead Yet
Fishermen’s Energy said it will appeal the Board of Public Utilities rejection of its proposed 25-MW offshore wind farm. “We are disappointed in this decision but not surprised,” said Paul Gallagher, Fishermen’s chief operating officer following a second BPU defeat last week. “We are grateful that New Jersey has an independent judiciary and look forward to having the merits of our application finally heard.”
Fishermen’s wanted the BPU to delay its ruling until the U.S Department of Energy came out with the final round of grants for demonstration offshore wind projects. Fishermen’s has complained that the BPU overestimated the end-price of the energy its project would generate. The board said last month that the $188 million project would be too risky for electric ratepayers.
The project’s five turbines would have generated about 25 MW of electricity, but the project depended on a mixture of subsidies and federal grants to make sure ratepayers didn’t get stuck with sky-high bills.
PENNSYLVANIA Polar Vortex-Related Rate Spikes Spur Retreat to Default Suppliers
Spiking power rates following the polar vortex spurred nearly 50,000 Pennsylvania electricity customers to back away from competitive suppliers, the Public Utilities Commission said last week. The PUC reported that the retreat from competitive suppliers came after wild price swings for variable rate customers. The PUC said that 2,177,499 customers are signed up with competitive suppliers, down 49,368, or 2.2%, from early March.
The Public Utility Commission agreed to consider a PPL Electric Utilities request to increase customer fees to cover storm damage costs.
On April 3, the PUC approved a rider allowing the company to bill customers for any storm-related damage not covered by the $14.7 million already collected in base rates. The order limited the rider to 3% of PPL’s 2012 distribution revenue, or $25.5 million.
The PUC agreed last week to consider PPL’s request to base the cap on all distribution, transmission and generation fees. “We are seeking clarification on how that 3% cap is calculated,” said Bryan Hay, a PPL spokesman. “We don’t oppose the concept of a cap. We believe the cap is set too low.”
Sunoco Pipeline L.P.’s application to become a public utility, which would exempt its planned 299-mile Mariner East pipeline from local zoning codes, has environmental groups up in arms. Four groups — the Delaware Riverkeeper Network, the Clean Air Council, the Pipeline Safety Coalition and the Mountain Watershed Association — filed requests to intervene in the case before the Public Utility Commission. The groups argue that Sunoco doesn’t qualify as a public utility.
Sunoco is converting a refined-oil pipeline to carry natural gas liquids from the state’s Marcellus Shale fields to an energy hub Sunoco is building at its former Marcus Hook Refinery.
Senate Majority Leader Dominic Pileggi supports shale-gas development but says he is against granting Sunoco’s exemptions. “The economic benefits of the Marcellus Shale industry must be carefully balanced with the potential burdens to our communities and the environment,” Pileggi wrote. “Requiring Sunoco to respect local ordinances related to pipeline construction will help to achieve this balance.”
WEST VIRGINIA Marshall County Approves Combined Cycle Plant
The Marshall County Commission gave its go-ahead for the construction of a $615 million natural gas combined cycle generating plant. The 549-MW plant would be built on a 37.5-acre plot currently owned by Honeywell International.
The plant will need state and federal approvals, but developer Moundsville Power LLC says it is confident of a 2015 construction start, with the plant going into operation by 2018.
Adopting the Market Monitor’s proposed changes to capacity market rules could almost triple auction revenues, the Monitor said in a report last week.
The Monitor said the $5.5 billion generated during the 2016/17 Base Residual Auction last year would have been $6.9 billion if the Short-Term Resource Procurement Target had been eliminated. The target cuts the amount of capacity acquired in the base auction by 2.5%, setting it aside for purchase in incremental auctions for the delivery year.
The 2.5% reduction removed 4,153 MW from the RTO demand curve, the Monitor said in an analysis of last year’s BRA. The target, which reduced clearing prices and quantities for all regions in the auction, should be eliminated, the Monitor said.
“The 2.5% demand reduction is a barrier to entry in the capacity market for both new generation capacity and new DR capacity,” the Monitor said. “The logic of reducing demand in a market design that looks three years forward, to permit other resources to clear in incremental auctions, is not supportable and has no basis in economics.”
‘Inferior’ Demand Response
The Monitor said revenues would have been $10.1 billion if only generation and Annual DR were offered, and Limited and Extended DR were eliminated.
The Monitor said Limited and the Extended Summer DR should be eliminated, and the restrictions on the availability of Annual DR ended, so that DR has the same obligation as generation to provide capacity year round.
“The Annual DR product definition is the only one consistent with being a capacity resource,” the Monitor said.
Eliminating both the 2.5% holdback and “inferior” DR would have produced $15.8 billion in revenues, the Monitor said, almost three times what capacity resources actually received.
Import Impact
The report also looked at the impact of generation imports on clearing prices.
It found that excluding external generation without firm transmission would have boosted revenues to $6.8 billion, an increase of almost $1.3 billion.
Reducing external generation offers by 25% would have increased revenues by $637.5 million, the report said.
The Federal Energy Regulatory Commission last week approved a rule change that will reduce capacity imports by as much as 17% from what cleared in the 2013 auction. (See related story, FERC Clears Capacity Import Limits.)
PJM rules are making it difficult for banks to purchase capacity providers’ revenue streams, Citigroup Energy told the Markets and Reliability Committee last week.
Citigroup Energy’s Barry Trayers presented a first read of a proposed problem statement to consider changing the rules, which require PJM to wait until after the third incremental auction (IA) before reassigning revenue streams from one PJM member to another.
Trayers said Citigroup purchases revenue streams at a discount from capacity providers who prefer to receive their proceeds in a lump sum. “I have customers out there who want to do it. It’s just very difficult to do it,” under current rules, he said. “I’m only [seeking to change] when PJM approves the transaction.”
Trayers said the rule will need to be changed because a proposed Tariff change now pending before the Federal Energy Regulatory Commission would eliminate the third IA, potentially putting such deals in limbo. (See Second Time Not the Charm.)
Harry Singh, of Goldman Sachs, also supported consideration of the rule change but asked for further clarity on whether PJM considers these “auction specific capacity” transactions to be “physical transactions” or simply a reassignment of receivables.
Stu Bresler, vice president of market operations, said the RTO supports “opening discussion” on the issue. PJM Chief Financial Officer Suzanne Daugherty said the change proposed by Citigroup should not increase risks to PJM members because the capacity provider will remain liable for capacity deficiency charges. PJM will retain the capacity provider’s posted collateral and could tap into the reassigned cash flow if needed to cover any shortfalls, she said.
Trayers’ request to waive first read and have an immediate vote on the problem statement was rejected by MRC chair Mike Kormos when several members objected. The issue will be brought to a vote at the MRC’s next meeting.
PJM will ask stakeholders to consider changing the historical allocation of Auction Revenue Rights, Executive Vice President for Markets Andy Ott told members last week.
Ott told the Members Committee webinar that the number of facilities resulting in ARR infeasibilities have increased steadily since 2012, largely due to transmission outages (see chart).
(Source: PJM Interconnection, LLC)
“We’ve seen constraints come up that we haven’t seen before,” Ott said. “… PJM can build its way out of it, but it’s going to take years.”
Ott said PJM will begin discussing Stage 1A ARR allocations at the end of May or early June in hopes of making changes before the next allocation in spring 2015.
ARRs are allocated annually to firm transmission service customers, entitling them to receive a share of the revenues from the annual auction of Financial Transmission Rights. The infeasibilities, in turn, contribute to shortfalls in FTR revenues.
Total ARRs are capped based on historical generation capability and zonal base load. For the 2014/15 allocation, the zonal base load was based on the minimum daily peaks for the year beginning Oct. 22, 2012.
Infeasibilities have increased due in part to uncompensated power flow (loop flow) and additional market-to-market flowgates, but increased transmission outages is the primary factor, Ott said.
Generation retirements — which were not anticipated when the Stage 1A process was designed — also have played a role. More than 15% of Stage 1 historical generation (25,544 MW) has retired or submitted deactivation notices.
The retirements require PJM to remap historical resources to an equivalent generator or create a “dummy” generator for ARR and pricing purposes. This can create additional Stage 1A infeasibilities, PJM says.
“The system seems to be able carry less and less of” the historic, “grandfathered” rights, Ott said. “We really need to take a fresh look at this. The solution is a high-level solution: Change the way things are allocated.”
In June, the Federal Energy Regulatory Commission rejected a complaint (EL13-47) by FirstEnergy Solutions Corp. that sought to bill all transmission users to make up FTR shortfalls. Since then, market participants say, the problem has only gotten worse with cumulative shortfalls exceeding $1.1 billion. (See FTR Holders Seek Shortfall Fix.)
Members agreed to consider an easier method for transmission owners to access real-time generator data, an effort to improve situational awareness and emergency response.
The Markets and Reliability Committee last week approved a problem statement by AEP’s Dana Horton to ease TO access to real-time MW output and MVar data. The data would be used as inputs to the TOs’ state estimators.
Horton said TOs are discouraged from obtaining the information under the current process, which he said is “burdensome and time-consuming.”
The information will improve TOs’ ability to “assess the impacts of external conditions and be able to develop effective plans or implement corrective actions to maintain reliability,” the problem statement said.
Under an issue charge approved by the MRC, the Operating Committee will consider developing new access rules and determine “the appropriate uses, storage and protection of the data.”
The Federal Energy Regulatory Commission approved PJM’s plan for selecting transmission projects that can easily and cheaply resolve constraints in Locational Delivery Areas (LDAs).
The new rules require PJM staff to identify — before posting the planning parameters for each Base Residual Auction — Locational Deliverability Areas in which the Capacity Emergency Transfer Limit is less than 1.15 times the Capacity Emergency Transfer Objective (See Quick Fix Transmission Upgrades Ok’d).
Upgrades that increase the ratio to more than 1.15 would be added to the Regional Transmission Expansion Plan (RTEP) if they cost less than $5 million and can be completed prior to June 1 of the Delivery Year. Projects that duplicate upgrades whose cost is already assigned to an interconnection customer would be excluded.
Such projects are unlikely to be common. PJM told the commission that it had identified no circumstances that would justify such projects in the last three years.
FERC approved the proposal over the objections of Utility Risk Management Corp. (URMC) and NextEra (ER14-456).
URMC said the proposal would hurt merchant transmission developers by allowing PJM to supplant merchant upgrades. NextEra argued that the proposal would disguise price signals and reduce transparency and innovation.
FERC said the narrow scope of these quick-fix projects was enough to alleviate these concerns and ensure consistency with Order 1000.
FERC endorsed PJM’s contention that, in relieving minor constraints that are unlikely to return in future years, it prevent misleading price signals.
As a condition of the approval, FERC required that PJM post an annual list of quick-fix proposals and recommended that the RTO and its stakeholders devise operational procedures in case such a project cannot be completed by June 1 of the relevant delivery year.
Below is a summary of the six requirements included in the draft reliability standard for physical security of the grid.
Transmission owners should perform a risk assessment of transmission stations and substations to determine which ones, if disabled or damaged, could result in “widespread instability, uncontrolled separation, or cascading within an Interconnection.” Assessments should be repeated every 30 months if such a vulnerability is identified and every 60 months if not.
Transmission owners should have an unaffiliated third party verify the risk assessment. Such third parties can be a registered planning coordinator, transmission planner or reliability coordinator, or “an entity that has transmission planning or analysis experience.”
Transmission owners with stations or substations identified under Requirements 1 or 2 that are not under their direct control must notify the operator of a primary control center that does control the stations of their critical status.
Operators of stations, substations or primary control centers identified as critical under Requirements 1 through 3 must conduct an evaluation of potential threats and vulnerabilities of those facilities. The evaluation must consider the characteristics of the facilities and any prior history or attack of similar facilities, and incorporate any threat intelligence provided by NERC, law enforcement or other authorities.
Operators of facilities identified during the threat analyses must develop within 120 days a physical security plan for the facilities, incorporating security measures, law enforcement contact information, a timeline for implementing the security plan and ways to conduct ongoing threat evaluations.
Transmission owners and operators must have a third party evaluate the threat analysis in Requirement 4 and the security plan developed in Requirement 5. The evaluation must be completed within 90 days of the security plan completion, and any changes suggested by the third party must be performed within 60 days.
PJM last week withdrew a proposal to develop a generic transition mechanism to hold capacity providers harmless for future rule changes.
The RTO’s proposed problem statement and issue charge was withdrawn from the agenda of the Markets and Reliability Committee without explanation. There was no indication why the issue was withdrawn or whether it will be added to a future agenda.
The proposal was prompted by the transition mechanism approved by members to protect generators whose installed capacity ratings are reduced by seasonal verification tests.
As a result, instead of the typical FMU profile — a combustion turbine running 300 hours per year — payments are going increasingly to generators running 1,000 to 3,000 hours yearly, which are operating “more like intermediate units,” Zadlo said.
