PJM’s controversial Capacity Performance plan was turned back Tuesday by the Federal Energy Regulatory Commission, which deemed the filing deficient and gave the RTO 30 days to provide additional information (ER15-623).
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.
PJM said Wednesday it will respond to FERC’s questions “promptly and seek expedited review” to allow the new rules to be in effect for the Base Residual Auction scheduled for May 11-15.
“We recognize that process may require a delay to conduct an orderly auction process,” Dave Anders, director of stakeholder affairs, said in an email to members. “While PJM clearly would have welcomed approval, we appreciate the FERC’s thoughtful consideration of our proposal and the commission’s demonstrated commitment to reliability and enhanced generator performance.”
Anders said PJM has never delayed a BRA before.
The commission compared aspects of the PJM proposal with ISO-NE’s “pay-for-performance” design, which it approved last year and on which PJM’s proposal was in large part modeled.
PJM’s proposal was expected to result in both 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.
It 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 — as ISO-NE has — 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.
Moeller: Delay Creates Uncertainty
The commission’s order drew a rebuke from Commissioner Philip Moeller. The RTO’s filing “already contains sufficient information to permit the commission to issue an order on the merits of PJM’s proposal in advance of the May 2015 Base Residual Auction,” he said in a statement.
“Markets provide the best prices for both buyers and sellers when participants know the market rules. Regardless of whether the commission ultimately decides to accept or reject PJM’s Capacity Performance proposal, by failing to act, the commission is creating market uncertainty on issues that need clarity now,” he added.
Dynegy and NRG Energy shares fell sharply April 1 on the news of the ruling, with Dynegy down 2.1% and NRG falling 5.6%. Dynegy recaptured its losses April 2 while NRG only partially rebounded.
More than 60 entities filed comments and protests in response to the plan.
States and load-serving entities (LSEs) were skeptical about the need for a major overhaul, while generators split over elements they liked and others they said must be changed. (See States, LSEs Skeptical, Utilities Split Over Capacity Performance.) Many generators complained the penalties were too harsh; others, including Exelon, said the penalties were too lax.
LSEs feared the product redesign was overkill and would result in unnecessary price increases.
As proposed, the changes would have begun to take effect for the 2016/17 delivery year and be fully implemented in 2020/21.
The details are outlined in nearly 1,300 pages filed in two dockets:
EL15-29 contains proposed changes to PJM’s Operating Agreement and Tariff “to correct present deficiencies in those agreements on matters of resource performance and excuses for resource performance.”
ER15-623 proposes changes to the Reliability Pricing Model in the Tariff and Reliability Assurance Agreement.
Exelon would retain Pepco Holdings Inc.’s D.C. headquarters, not forcibly reduce the workforce for at least two years and match any commitments it has made to New Jersey, Delaware and Maryland if it is permitted to buy Pepco in a proposed $6.8 billion deal, CEO Christopher Crane testified Monday before the District’s Public Service Commission.
Those promises include customer bill credits, grid reliability improvements, renewable energy projects, energy efficiency programs, help for low-income consumers and the creation of trails.
D.C. and Maryland are the last holdouts to the transaction, which Crane agreed Monday is an acquisition rather than a merger, given the size of the Chicago-based energy giant. The evidentiary hearings, which are being webcast, continue through April 8 in D.C. and are scheduled for April 15-17 in Maryland.
The direction of questioning followed opening statements delivered by the D.C. Office of People’s Counsel and the D.C. government, who strongly oppose the deal. Crane was grilled on Exelon’s commitment to renewable and distributed energy, protecting ratepayers’ interests over the profitability of its nuclear generators, retaining a true local presence and how Exelon would be held accountable to its promises.
“We hope to, within the District and other districts, to enter settlement negotiations to satisfy stakeholders in the process if we could,” Crane said.
Regarding jobs, Crane said, “There will be no reductions of the utility staff for two years — there’s actually a commitment to hire.”
In part, that’s because about 400 employees are eligible for retirement, he said, and Exelon wants to bring some of the work currently being contracted in-house. While Exelon can’t promise to preserve staff “in perpetuity,” Crane said there was nothing viewable in today’s landscape that would indicate the need for future layoffs.
Crane said Exelon cannot alter its proposal to D.C. without resetting the clock for the decision timeline, but he welcomed additional concessions either through a negotiated settlement or a unilateral decision by the commission.
When asked by People’s Counsel attorney Jason Gray what would be the “tipping point” that would make the acquisition unprofitable, Crane said that to his knowledge, Exelon had not conducted such an analysis.
“You don’t have any concern that applying any of these provisions would put you over the tipping point?” Gray asked.
“I don’t believe any of these do,” Crane responded.
In his opening statement, John Coyle, an attorney representing the D.C. government, noted that the transaction involved a premium of more than 24% over the current market value of Pepco stock, when in essence, he said, “Exelon is proposing $6.8 million for a $4.3 million balance sheet.”
“The mere size of the premium begs the question of why it is being offered,” Coyle said, suggesting that commissioners engage in what he called an old D.C. tradition and “follow the money.” (See Consumer Advocate Seeks Delay in Exelon-Pepco Proceedings.)
Md. County Reps Want More from Deal
Leggett
Meanwhile, Exelon continues to encounter opposition in Maryland, where the Montgomery County Council has split from County Executive Ike Leggett, arguing that the settlement he reached with Exelon doesn’t go far enough to protect ratepayers and encourage renewable energy.
The nine-member Council on Tuesday unanimously passed a resolution asserting that Leggett’s settlement “does not adequately address the overarching issues that have led the state, the Office of People’s Counsel, the environmental community and other public interest organizations to maintain that the merger is contrary to the public interest.”
The resolution, spearheaded by energy attorney Roger Berliner, cites fears that Exelon will seek to raise rates to offset losses at its nuclear plants and will favor that generation at the expense of renewable and distributed energy resources.
“If the serious risks the proposed merger poses to the public interest can be mitigated, it can only be mitigated by very strong, verifiable and financially accountable commitments by Exelon to holding down costs and to clean, renewable, distributed energy, including energy efficiency, values at the heart of Maryland’s energy policy,” the resolution states.
Patrick Lacefield, a spokesman for Leggett, toldBethesda Now that the executive took the council’s position into account before signing the settlement with Exelon.
“The alternative to this settlement is not necessarily something better. The alternative could well be no deal at all. … We made this decision in the public interest to change the status quo. It is an executive decision.”
The Maryland Public Service Commission is set to finish reviewing the takeover on May 8.
The acquisition has been approved by the New Jersey Board of Public Utilities, the Federal Energy Regulatory Commission, the Virginia State Corporation Commission and the staff of the Delaware Public Service Commission.
Exelon hopes to close the deal in the second or third quarter of this year.
The Mercury and Air Toxics Standards (MATS) at issue before the U.S. Supreme Court last week are the result of a quarter century of legislation, regulation and litigation that began with the 1990 amendments to the Clean Air Act.
Congress amended the act to give the Environmental Protection Agency the authority to regulate 189 hazardous air pollutants (HAPS), including mercury, arsenic and cadmium that had not been previously controlled.
The law, signed by President George H.W. Bush, required EPA to develop emission standards for the pollutants, and then identify, categorize and regulate the sources that emitted them in large amounts.
The act expressly forbade EPA from considering cost when deciding whether to regulate sources other than electric generating plants; cost would only come into play in setting the level of regulation.
Other provisions of the 1990 amendments specifically targeted power plants, including the acid rain program, which required regulations on sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions from the largest coal-fired generators.
Appropriate and Necessary
Congress ordered EPA to perform a study evaluating whether the acid rain and other programs had addressed all public health concerns from generators. It ordered EPA to develop additional regulations if the agency determined it was “appropriate and necessary.”
EPA submitted the required utility study in 1998, concluding that the acid rain program would not significantly reduce HAPS emissions. In 2000, EPA announced it would regulate mercury, other metals and acid gases, noting that power plants were the biggest source of mercury emissions in the U.S.
EPA said mercury is a health hazard because it enters the food stream through fish and shellfish. Mercury can impair neurological development for fetuses, infants and children.
Reversal by Bush Administration
In 2005, however, the George W. Bush administration attempted to withdraw the listing, a decision that was voided by the D.C. Circuit Court of Appeals. The court said the government hadn’t met the criteria for delisting.
The Obama administration reaffirmed the decision to regulate mercury in 2012, saying it was necessary because other Clean Air Act regulations would not eliminate the health hazards posed. EPA said it interpreted Congress’ instructions in section 112 of the act as prohibiting the consideration of cost when it made the “necessary and appropriate” determination.
The MATS rulemaking sparked numerous challenges. While all parties agreed that section 112 was silent on the issue of costs, they disagreed on how that silence should be interpreted.
Last April, the D.C. Circuit upheld the MATS rulemaking in a 2-1 decision, with Judge Judith Rogers writing that section 112 “neither requires EPA to consider costs nor prohibits EPA from doing so.”
Judge Brett Kavanagh provided the ammunition for challengers to appeal to the Supreme Court, writing that the term “appropriate” required a cost-benefit consideration.
Dayton Power & Light is protesting a $106 million transmission project by Dominion Resources under PJM’s 2015 Regional Transmission Expansion Plan because of a change in how the project’s costs will be allocated (ER15-1344).
The 500-kV Cunningham-Elmont end-of-life project (Project b2582) initially was designated a supplemental proposal, for which Dominion, as the incumbent utility, would bear the full cost.
“That was the correct designation for this project because it is simply a replacement for an existing transmission line for which Dominion has always had 100% cost responsibility,” DP&L said in a March 24 filing with the Federal Energy Regulatory Commission.
But after changing its local planning criteria last year, Dominion asked PJM to study the need for the project and received permission to change its designation to baseline, categorizing it as a new line and allowing Dominion to export more than half of its expense.
The new allocation scheme will charge DP&L about $1 million, the Ohio utility said, noting that larger PJM stakeholders such as Commonwealth Edison and American Electric Power will be expected to pay six to seven times that much. While AEP has filed a motion to intervene in the case, DP&L is the only entity to have submitted a protest.
The Dominion project was described as a supplemental project in a reliability analysis update at PJM’s July 10, 2013, Transmission Expansion Advisory Committee.
The criteria PJM used to redefine the transmission project, DP&L said, “was not developed by PJM for consistent application across PJM, but was instead based solely on ‘Dominion Planning Criteria.’ In other words, Dominion’s unilateral change of its own criteria for construction within its own zone has resulted in a recharacterization of this project from a supplemental project for which it would bear 100% of the costs to a baseline project for which about 52% of costs are exported to other zones.”
DP&L is asking FERC to reject the project or defer consideration to allow PJM transmission owners time to revise the Tariff to prevent them from unilaterally revising local planning criteria to secure baseline status for their projects.
DP&L said Dominion is exploiting what it called a loophole resulting from an Order 1000-related filing by PJM TOs that permits a portion of the costs of new 500-kV baseline projects to be shared by load-serving entities throughout the RTO.
WILMINGTON, Del. — The MRC endorsed the following Thursday:
Manual 11: Energy & Ancillary Services Market Operations — Updates manual to include a method for screening of demand bids by load-serving entities, as approved by the Federal Energy Regulatory Commission in November (ER14-2976). Bids are limited to the LSE’s calculated zonal peak demand reference point for the day plus whichever value is more, 30% of the reference point or 10 MW. PJM said the need for such limits was illustrated by the default of a retail provider in January 2014 after it mistakenly entered a demand bid about 100 times its actual load. (See MIC Briefs.)
Marji Phillips of Direct Energy said the change is requiring her company to confirm its loads daily by phone with Pepco Holdings Inc. because of problems with Pepco’s electronic system. “Every day, we have no idea whether we will be able to meet the obligations we have to meet,” she said. “It is killing all the LSEs in the Pepco area — Delaware, New Jersey, D.C. It’s a tremendous problem.”
Manual 12: Balancing Operations — Revisions describe the required regulation range, specifying that resources are required to symmetrically provide the total amount of regulation assigned. The changes also detail how performance evaluations are conducted and further define the basepoint around which the resource will be regulating.
Non-substantive revisions regarding financial transmission rights. The changes concern clearing deadlines, bilateral trades and Tariff references.
A change to demand response modeling assumptions used in load deliverability analyses for the Regional Transmission Expansion Plan. The new method would use the average of the last three years of committed DR for each zone. (See Change Proposed in PJM Demand Response Modeling.)
Revisions to Manual 18 Address Capacity Performance
The MRC discussed manual changes needed to implement PJM’s Capacity Performance proposal, which is pending before FERC (EL15-29). The proposal would penalize underperforming units and reward those that over-perform. (See PJM Defends Capacity Performance Proposal; Drops Change for LSEs.)
The revisions, which affect Manual 18: PJM Capacity Market, would allow capacity resources to avoid performance penalties by requesting approval of retroactive replacement transactions within three business days after a delivery day that includes a performance assessment hour.
That would allow a participant with over-performing uncommitted capacity to replace underperforming committed capacity in the same account, Vice President of Market Operations Stu Bresler said.
Market Monitor Joe Bowring said the changes present an opportunity for economic withholding. “It is an incentive to withhold, and that is one of our concerns,” he said.
Members will be asked to endorse the revisions at the next MRC meeting if FERC has approved the proposal by then.
Members Committee
CTS Product, Fee for $20M-plus Projects Approved
The Members and Markets and Reliability committees endorsed a $30,000 non-refundable fee for studying proposed transmission improvements with estimated costs of $20 million or more. The fee, which PJM would evaluate for two years, would apply to both greenfield projects and upgrades by incumbent transmission operators. FERC last month rejected an earlier proposal to exempt transmission upgrades from the study fee. (See FERC Rejects Fee on Greenfield Transmission Projects.)
The MC also endorsed Tariff and Operating Agreement revisions to implement Coordinated Transaction Scheduling (CTS) with MISO. The objective is to improve interchange scheduling efficiency by aligning energy scheduling with interface prices and adding the option for market participants to schedule energy transactions using an interface bid. (See PJM, MISO Reach Agreement on New Interchange Product.)
Little Rock Operations Center Opened to Serve MISO’s Southern Expansion
MISO has opened a $22 million regional operations center in Little Rock.
The 50,000-square-foot facility works in concert with MISO’s control facilities in Carmel, Ind., and Eagan, Minn.
The facility was needed after MISO expanded its territory into the Gulf Coast states following Entergy’s decision to join the RTO.
The facility initially will employ 42 people. “We hope to use our presence here not only as a resource to the greater Little Rock community but as a magnet for other energy-sector firms,” MISO President and CEO John Bear said.
Crowd Attends Hearing on Refinery’s Bid for Permit on Cooling Water
More than 500 people showed up for a hearing on Delaware City Refinery’s bid to renew permits governing its cooling water intake and discharge. The majority of the crowd was made up of refinery workers and supporters, although a vocal group of environmentalists — some in fish costumes — gathered outside the hearing room at Gunning Bedford Elementary School. They objected to the state Department of Natural Resources and Environmental Control’s issuance of the permit, which granted refinery owner PBF an extension to assess options.
“DNREC has clearly compromised its ability to be an independent arbiter over this matter,” Delaware Riverkeeper Network Director Maya van Rossum said. “They need to step back and request that the Environmental Protection Agency take the lead in order to remove both the actual and appearance of bias. This sweetheart deal needs independent agency review.”
The Energy and Public Utilities Committee on March 26 endorsed Senate Bill 1585, which would establish a “Low Carbon Portfolio Standard.”
Under the proposed legislation, beginning next year, 70% of the electricity delivered by Commonwealth Edison, which is owned by Exelon, and Ameren would have to be generated by “clean energy” sources: solar, wind, hydro, nuclear, tidal, wave and clean coal.
The fee to customers, which would average $2/month, would fund low-carbon energy credits to be auctioned by the Illinois Power Agency.
The legislation is one of three clean energy measures before the General Assembly. Environmental and consumer advocates are backing the Clean Energy Jobs Bill (SB1485, HB2607).
Meanwhile, ComEd has proposed legislation to foster growth in clean energy for households and microgrids (HB3328, SB1879).
Regulators Again Probing IPL After Two More Downtown Blasts
The Utility Regulatory Commission has opened an investigation into Indianapolis Power and Light’s downtown underground network after blasts sent manhole covers flying downtown.
Two incidents that occurred in March were the latest in several well-publicized explosions dating back four years.
In 2011, the IURC commissioned a study by Atlanta-based O’Neill Management Consulting that found IPL can expect three to five such incidents per year if it didn’t improve maintenance procedures for its downtown electrical network.
Under the nervous gaze of civic leaders, IPL recently installed manhole cover restraining devices in high-traffic areas downtown in anticipation of the NCAA Men’s Basketball Championship in April.
The underground blasts come at a time when IPL is seeking a rate hike that would generate $68 million more in annual revenues. It’s IPL’s first base rate case since 1995.
In light of the recent incidents raising safety and reliability concerns, Citizens Action Coalition, a group representing IPL ratepayers, said it is “unconscionable” that regulators allowed IPL to operate for nearly 20 years without a base rate case.
A former IPL executive, Dwane Ingalls, has alleged that IPL skimped on network maintenance to maximize the dividend the utility sent to parent AES.
House Bill Would Protect Property Owners from ‘Merchant’ Tx Lines
A House committee passed a bill that would protect property owners from losing their land to transmission line developers. The main targets of the bill, offered by House Government Oversight Committee Chairman Bobby Kaufmann, are transmission lines linking out-of-state utilities or companies. Clearly targeted is the Rock Island Clean Line, a proposed $2 billion line that would run from northwest Iowa to Illinois.
House Democrats opposed House Study Bill 222, saying it takes away power from the Utilities Board. “We have a process in place,” Rep. Phyllis Thede said. “We want to make sure people are safe with their land but we also want to make sure the process works.”
Westar Wants Small Generators to Pay Higher Fixed Rates
A case before the state Corporation Commission could mean higher fixed rates for those who produce their own power through solar or wind generation at their homes or businesses. Topeka-based Westar Energy is targeting those smaller generators for higher fixed rates, rather than raising such rates for all customers.
“We just want to make sure it’s fair to any customers, whether they decide to generate some of their own power or not,” said Jeff Martin, the company’s vice president for regulatory affairs.
But solar advocates see it as aimed at small-scale renewable energy. “This is another attempt by the utility to kill solar in Kansas,” said Aron Cromwell, who co-owns a solar installation company.
The Public Service Commission has ordered refunds to some former customers of People’s Power and Gas, a competitive supplier that operated in Emera Maine’s territory in 2013 and 2014. The commission found that People’s charged a $25 monthly “service fee” without notifying customers that it would do so. An investigation revealed that the company collected about $128,070 from about 2,800 customers.
The company filed for bankruptcy shortly after collecting the fees, so the PUC is using People’s security deposit to refund the money.
Another Chicken Poop-to-Power Plan for Maryland’s Eastern Shore
Poultry giant Perdue wants to team with a New Hampshire firm to build a $200 million plant that will be fueled by chicken manure, something that is abundant on the Eastern Shore, a major poultry producing region in the country.
AgEnergyUSA, a firm that is already building a similar plant in Colorado, said its plant would put the manure to good use and keep it out of the waste stream, where it has been identified as a polluter of the Chesapeake Bay. AgEnergyUSA is teaming up with Perdue and French power company EDF Renewable Energy. The plant would use “anaerobic digestion” to break down 200,000 tons of poultry “litter,” a combination of chicken manure and organic bedding, a year. Methane would be extracted, which could then be used for power generation and other industrial uses. The remaining waste would be mined for its nitrogen and then sold back to farmers as fertilizer.
Wind Energy Translates into 30 Billion Gallons of Water Saved Since 2004
Wind energy continues to grow not only as an important source of emission-free electricity, but as a means of saving water as well.
According to the state Department of Revenue and Department of Natural Resources, wind energy production in the state has saved 30 billion gallons of water since 2003. Studies from the departments say that energy production from fossil fuels needs 541 gallons of water for each megawatt of energy produced. Since 2004, wind facilities in the state have produced more than 56 million MW.
“Minnesota wind development is in many ways attractive, because it’s a form of industrial development where the primary alternatives are typically focused on agricultural processing, which is generally water intensive,” said Mark Lindquist, program manager for Energy and Biofuels with the state Department of Natural Resources. “So here’s a new industry that puts zero pressure.”
Senate Approves Duke’s Purchase of NCEMPA Generating Assets
The state Senate last week approved Duke Energy’s bid to buy the generating assets of the North Carolina Eastern Municipal Power Agency in a deal valued at more than $1 billion. NCEMPA holds partial ownership in a number of Duke power plants in the state. The $1.2 billion deal includes plant shares, fuel and parts inventories at Brunswick Units 1 and 2, Mayo Plant, Roxboro Plant Unit 4 and the Harris Nuclear Plant. Combined, the ownership interests amount to about 700 MW. The deal received approval from the Federal Energy Regulatory Commission in December. NCEMPA said the deal will mean lower electricity prices for its customers in 32 cities and towns in eastern North Carolina. The House is expected to vote on the measure soon.
State’s Rig Count Falls Below 100 for First Time in 5 Years
The slump in oil and gas prices is spurring exploration companies to shut down operating rigs, leading to a drop in the number of rigs operating in the state to fewer than 100 for the first time in five years. A recent count showed 98 rigs drilling in the state, 100 fewer than there were at the same point a year ago. The state is the No. 2 oil producer in the U.S., behind Texas.
Wind Farm Developers Have to Start Over After Applying for Wrong Permits
The developers of a wind farm in Lincoln County will have to start the permitting process over after the county commission ruled that they applied for the wrong permits for five test towers. Dakota Power Community Wind should have applied for a temporary-use permit for its five test towers, not conditional-use permits. The ruling gives opponents of the planned 500-MW wind farm another chance to convince the county commission to rule against the project.
County Fights Plan to Switch Pipelines from Gas to ‘Gas Liquids’
The Greater Dickson County Gas Authority is teaming with other utility districts in the state and in Alabama to fight a plan by a pipeline company to switch its operations from carrying natural gas to “natural gas liquids.”
Tennessee Gas Pipeline Co., a subsidiary of Kinder Morgan, wants to abandon nearly 1,000 miles of natural gas pipeline and then sell them to Utica Marcellus Texas Pipeline, another Kinder Morgan affiliate. The new owners would use the pipelines to transport natural gas liquids, a different product. The switch to natural gas liquids will mean a need to upgrade compressors and other parts of the pipelines, and that would translate into higher costs for customers all along the route, according to the Greater Dickson filing.
The city of Georgetown’s municipal utility announced plans to cut the cord to all fossil-generated electricity and use wind and solar only to meet its energy needs. It will be the state’s first city-owned utility to do so.
The city announced a deal with SunEdison to provide 150 MW of solar starting next year. Last year, it signed a contract that runs through 2039 for 144 MW of wind energy. The city said it recognizes that the two agreements will mean fewer emissions for the region but that it was the numbers that made them appealing. “It was really primarily a price decision,” city spokesman Keith Hutchinson said.
Both the wind and solar agreements locked in cheaper prices than what it was paying to the Lower Colorado River Authority, Hutchinson said. He also said it provides a hedge against increases from fossil generation going forward. “We don’t know what’s going to happen in the future for regulations for fossil-based fuels,” Hutchinson said. “This really removes that element from our price costs going forward.”
PSC Approves Controversial 180-mile Tx Line After Xcel Joins
The Public Service Commission approved a 180-mile, $580 million transmission line that it previously blocked when it was proposed by non-utility company American Transmission Co. Xcel Energy’s Northern States Power Co. joined the 345-kV line project as partner after it was initially rejected, and MISO endorsed it and designated it a critical path for providing power and reliability to the state. Because of that designation, state residents will pay about 15% of the line’s cost. It is to run from Madison to LaCrosse and is crucial for moving wind power generated from Iowa and Minnesota.
“Construction of the line is critical for the development and delivery of several thousand megawatts of clean, low-cost wind power,” said Beth Soholt, who runs Wind on the Wires, a renewable energy advocacy organization representing clean energy groups and wind energy companies. “The new line will also reduce congestion in the MISO energy market and add to the reliability of the overall MISO grid.”
WILMINGTON, Del. — The PJM Markets and Reliability Committee on Thursday tabled voting until next month on a proposal to tighten rules on lost opportunity costs for combustion turbines.
PJM and Independent Market Monitor Joe Bowring supported the change, saying that current rules provide incentives for units to offer and clear in the day-ahead market but not in the real-time market.
Under the proposal, units with start-up and notification times of no more than two hours and minimum run-times of two hours would be paid lost opportunity costs if they are not dispatched. Resources with real-time startup and notification times or minimum run-times of more than two hours will not receive lost opportunity payments unless PJM bars them from running in real time to avoid transmission overloads.
PJM would use the generator’s energy schedule to calculate opportunity costs except for self-scheduled units, for which the higher of the available cost- or price-based curves would apply.
“The two-hour start notification and two-hour minimum run are designed to be aligned with what the dispatch operators can see,” said Stu Bresler, PJM vice president of market operations.
Bowring called the proposal “clearly an improvement.”
But Ed Tatum of Old Dominion Electric Cooperative raised an objection to limiting LOC compensation to units with minimum run times of two hours or less, saying it was too restrictive.
Susan Bruce of the PJM Industrial Customers Coalition said dropping the restriction would be “cherry picking” on a compromise that stakeholders agreed to at the Energy Market Uplift Senior Task Force, where the proposal won 84% support last month.
With two objections and one abstention, the MRC decided to send the issue back to the task force for additional discussions at its meeting tomorrow. The MRC will vote on the current proposal at its April meeting, considering any friendly amendments or alternate motions developed at the task force meeting.
Separately, members approved a proposal that was unanimously approved by the task force, instructing the Planning Committee to treat uplift as an input to analyses under the Regional Transmission Expansion Plan.
Opponents of a pipeline that would move shale gas from northeastern Pennsylvania to New York and New England markets made good on a promise Friday to go to court to force a rehearing of federal regulators’ approval of the project.
The Federal Energy Regulatory Commission issued a rehearing order on Jan. 27, but the Stop the Pipeline group says that is merely a procedural move as the regulator avoids its petition “to grant, deny or otherwise act on the merits of STP’s Jan. 2, 2015, request.” The group wants FERC to hold a rehearing by May 1, it said in its plea for a writ of mandamus from the U.S. District Court of Appeals for the Second Circuit in New York (15-926). (See Constitution Pipeline: Headed to Completion or to Court?)
The proposed 124-mile Constitution Pipeline won a certificate of public convenience and necessity from FERC on Dec. 2. The commission issued its Final Environmental Impact Statement on Oct. 24.
The actions were taken before the project received other regulatory approvals, including water quality permits under the Clean Water Act’s section 401, which opponents say is a violation of the law.
The project is currently under review by the New York Department of Environmental Conservation, which closed its public comment period on Feb. 27.
Without action on the rehearing, STP says it is in “administrative limbo” while it also is denied the opportunity to challenge FERC’s order in court. STP said Constitution started more than 120 eminent domain proceedings in mid-December, and by Feb. 21 a district court had given Constitution the right to condemn the properties and enter potential pipeline sites without the owners’ permission.
“The commission has caused, and continues to cause, significant injury to STP’s members … before it has even been determined that the pipeline project will ultimately be authorized to proceed,” the petition states.
Constitution is on an aggressive schedule, with construction scheduled to start this year and the pipeline in operation by late 2016. It would connect the Pennsylvania gas fields with an interstate pipeline that runs from the Southwest to New England.
“FERC has already thoroughly evaluated the project and approved this vital infrastructure, agreeing that the plan we have developed minimizes environmental impacts. We are looking forward to obtaining final clearances so we can begin construction this summer,” Constitution spokesman Christopher Stockton said.
Multiple stakeholders have asked the Federal Energy Regulatory Commission for a rehearing of its Feb. 19 ruling involving MISO’s system support resources agreements at a trio of aging power plants in Michigan’s Upper Peninsula.
The February ruling affirmed FERC’s previous finding that MISO could no longer allocate broadly within the American Transmission Co. pricing zone the SSR costs of keeping open three aging plants — most notably the Presque Isle generating station near Marquette. (See FERC Upends MISO’s SSR Cost Allocation Practice.)
The March 23 filings seek rehearing on several parts of the commission’s February order that required MISO to file a new study method to identify entities that benefit directly from the three plants and allocate costs of the agreements directly to them.
Double Recovery
One of the requests was filed jointly by Tilden Mining and Empire Mining Partnership, which last October filed a protest alleging Presque Isle owner We Energies was recovering SSR costs through the utility’s retail rates as well as through MISO’s SSR surcharges. Last November, FERC acknowledged the double recovery issue was raised by several stakeholders. It accepted a replacement SSR but said it would be subject to refund.
But the mines complain FERC declined to address concerns about double recovery of fixed capital costs through We Energies’ retail rates.
“FERC failed to engage in reasoned decision making and abdicated its statutory responsibility to assure that MISO’s federally regulated SSR rates are just and reasonable in the context of shared state and federal regulatory responsibility,” the mines said (ER14-1242).
“Whether or not the commission likes it, the fact is that the state-authorized recovery of [Presque Isle] costs through [We Energies’] 2014 Wisconsin retail rates included full recovery of the Wisconsin share” of the utility’s Presque Isle costs.
The Sault Ste. Marie Tribe of Chippewa Indians made the same argument in a separate filing (ER14-2952-002).
The City of Mackinac Island also requested rehearing, also citing the mines’ reasoning. The city also alleges that MISO should not have authorized an SSR agreement for Presque Isle because the plant’s owner had not made a “definitive” retirement decision (EL14-103).
Michigan PSC
The Michigan Public Service Commission filed a 20-page request saying FERC should reverse its retroactive allocation of SSR costs for Presque Isle, White Pine and Escanaba plants (ER14-2952). FERC established April 3, 2014, as the retroactive date.
FERC’s Feb. 19 order was a win for the Wisconsin Public Service Commission, which last year alleged MISO improperly allocated SSR costs on a pro rata basis to all load-serving entities in the ATC footprint.
The Wisconsin PSC argued that 92% of the projected $52.2 million in annual fixed costs under the original Presque Isle SSR would be allocated to load serving entities in Wisconsin even though they would receive only 42% of the benefits from the plant’s continued operation.
The city of Escanaba, Mich., asked the commission to clarify that its rejection of MISO’s cost allocation proposal does not bar “a methodology using all or part of either an optimal load shed methodology or some use of [local balancing authority area] boundaries under certain circumstances, if MISO’s compliance process fails to produce a suitable substitute” (EL14-34).
Challenge to Rate Design
But the order has also drawn additional opponents, including Integrys Energy Services. In its rehearing request, it alleges the commission erred by applying a new rate design methodology to the ATC zone different than that applied in MISO previously and by applying that new rate design retroactively (ER14-1242).
“On rehearing, if the commission is going to require a new methodology for allocating SSR costs throughout MISO, it should apply these changes prospectively and only after the methodology has been shown to be just and reasonable,” Integrys said.
The recent filings are just the latest in the ongoing Presque Isle saga. In mid-March officials announced that a deal to sell Presque Isle to Upper Peninsula Power would be scrapped. We Energies will retain the plant now that Tilden and Empire will come back as customers of Presque Isle. The mines decided two years ago to purchase power from other providers under Michigan’s partially deregulated electricity market.
WILMINGTON, Del. — PJM members were asked last week to consider allowing generators to revise their offers hourly to reflect changes in gas prices.
ISO-NE graphical description of self-dispatch unit using pricing flexibility.
PJM is the only RTO in the U.S. that does not allow generators to vary their cost- or market-based offers hourly, GT Power Group’s David Pratzon, representing Calpine, said in a proposed problem statement presented to the Markets and Reliability Committee on Thursday.
That means gas-fired generators must submit a single price for the day-ahead and real-time energy markets even though gas prices can change in midday. More flexible pricing would allow generators to reduce the risk premiums they include in their offers because they would have greater assurance that their prices reflected fuel costs, Pratzon said.
The most recent RTO to allow hourly price changes is the gas-dependent ISO-NE, which adopted the new rules in December.
In addition to benefiting gas-fired generators, Pratzon said, the flexibility also would be useful to energy storage resources and industrial customers whose opportunity costs for cutting loads can vary based on the hour of the day. “I can see a variety of different classes of resources that this would be useful to,” he said. “We don’t know all the ways this optionality could be used.”
PJM currently requires generators to select a single cost schedule for each unit’s day-ahead offer.
In February, PJM introduced an improvement to eMKT allowing gas-fired generators to make limited intraday changes in price schedules.
The change allows generators that did not receive day-ahead commitments and were not picked up in the reliability assessment and commitment (RAC) run to update their fuel prices three hours in advance of the operating hour. Units with day-ahead commitments and those selected in the RAC run can switch prices after the end of their last committed hour. Units committed in real time remain unable to change their cost schedules until released.
Previously, there was no way for generators to change their prices once PJM locked them at 6 p.m. the day before.
Stakeholders at the MRC meeting expressed support for the additional flexibility sought by Calpine.
“We think this is a critically needed improvement to the energy market,” Dominion’s Lisa Moerner said. “It has been working incredibly well” in ISO-NE, she added.
The proposal “will do a lot to harmonize gas-electric coordination that we’ve been trying to achieve,” said Marji Phillips of Direct Energy.
Dan Griffiths, executive director of the Consumer Advocates of PJM States, said his members “don’t have a principled objection” to the potential change but are concerned about generators claiming unreasonably high gas prices.
Independent Market Monitor Joe Bowring echoed Griffiths’ concern. “Let’s not forget what the reason was for the rule requiring only one offer per day by generating units,” Bowring said. “It was to prevent the exercise of market power.
“It’s important this doesn’t become a tool for the exercise of market power, which it easily could be used to do. There are good ways to implement this and bad ways to implement it.” Nevertheless, Bowring said, “it’s clearly a worthy discussion” to have, calling it “potentially efficiency enhancing.”
The MRC will vote on the problem statement next month. Pratzon suggested a new senior task force consider the issue.
Pratzon said it took ISO-NE about 18 months to implement its changes from the beginning of discussions. By learning from the RTO’s experience, he said, PJM might be able to make the change before next winter.
However, even if stakeholders agree quickly on new rules, Pratzon acknowledged, required software changes could delay implementation.
