A federal appeals court has halted the award of clean energy contracts sought by three New England states while it considers an appeal filed by a New York-based clean energy developer (16-2946).
The 2nd U.S. Circuit Court of Appeals issued a temporary injunction on Nov. 2 in response to Allco Renewable Finance’s emergency petition.
Connecticut, Massachusetts and Rhode Island last month announced they would commence negotiations with developers of solar and wind projects totaling 460 MW. (See New England States Move Toward Renewables Contracts.)
Solar Energy Project Schematic | Allco
“Defendants-appellees are enjoined from awarding, entering into, executing or approving any wholesale electricity contracts in connection with the current energy solicitation during the pendency of this appeal,” the court said.
The three-judge panel expedited the appeal, set up a briefing schedule and ordered oral arguments in New York City as soon as the week of Dec. 5.
In its motion for the injunction, Allco tried to establish parallels with the U.S. Supreme Court ruling earlier this year in Hughes v. Talen, in which the court invalidated a contract between Maryland and a natural gas generator. Allco said the Maryland contract was “just like what Connecticut plans to do here.” (See Supreme Court Rejects MD Subsidy for CPV Plant.)
In the schedule set up by the states, negotiations are supposed to be completed by mid-January. The solicitation imposed a 20-MW minimum on the contracts that could be considered.
Allco said the 20-MW minimum is arbitrary and violates the Public Utility Regulatory Policies Act and the Federal Power Act. The company develops small solar qualifying facilities under PURPA.
The company filed a lawsuit against Connecticut officials after the multistate solicitation was announced last year. (See Allco Challenges New England’s Renewable Procurement Plan.) A U.S. District Court dismissed Allco’s challenge over the summer, saying the company lacked standing. The company appealed to the 2nd Circuit and then filed its emergency motion last month as the states’ solicitation process was ending.
Edison International will continue upgrading its transmission and distribution networks to take advantage of recently enacted legislation requiring California to reduce greenhouse gas emissions to 40% below 1990 levels by 2030, company officials said during their third-quarter earnings call with analysts last week.
Through its primary utility subsidiary Southern California Edison, the company is seeking to become a “key enabler” of California’s goals by facilitating the adoption of rooftop solar, energy storage and electric vehicle charging, CEO Pedro Pizarro said.
| Edison International
“Grid modernization, which, by the [California Public Utilities Commission’s] estimate, will be an ongoing effort into the middle part of the next decade, is a very significant part of the needed solution” for reducing emissions, Pizarro said. Edison’s quarterly profit increased by 11.1% to $419 million partly on higher revenues stemming from a revenue escalation mechanism included in a rate case approved late last year.
Pizarro noted that state officials are turning their GHG reduction efforts from the power industry — accounting for about 20% of current emissions — to the transportation sector, which is responsible for more than a third.
“We believe the significant new efforts across all sectors of the economy will be needed and many of these efforts will require significant electrification of sectors that today rely on fossil fuels,” Pizarro said.
Edison anticipates about $4 billion in yearly capital spending and $2 billion in annual rate base growth next year and into “the foreseeable future,” with nearly all of the investment on the “wire side” of the business, according to CFO Maria Rigatti.
“We believe it has lower investment opportunity risk as compared to utilities with a high percentage of growth tied to generation investment,” Rigatti said.
Edison is seeking regulatory approval to roll $200 million of “early-stage” grid modernization into its 2016-2017 rates, but the company might have to delay that investment until 2018 if it does not receive a timely decision from the CPUC. The spending would focus on replacing aging infrastructure, adding new customer connections, upgrading information technology, maintaining SoCalEd’s generators and modernizing the utility’s distribution system to accommodate the growth of distributed energy resources.
The company’s $1.1 billion West of Devers transmission project — which will upgrade existing 220-kV lines to double-circuit lines — was approved by the CPUC in August but has been challenged on environmental grounds.
Edison has also proposed alternative designs — which require “significant re-engineering” — in the CPUC’s review of the company’s $600 million Mesa substation project, which would upgrade the existing facility in the western Los Angeles Basin from 220 kV to 500 kV.
“These permitting and approval challenges are increasingly typical of transmission planning and part of the process, although the need for these projects is not affected by the regulatory delays that impact initial timing,” Rigatti said.
Edison continues to engage with Mitsubishi Heavy Industries in arbitration over steam generator design flaws that forced the permanent closure of San Onofre nuclear generating station in 2013. Edison shares ownership of the plant with San Diego Gas and Electric.
In the event of a favorable outcome for the plant’s owners, SoCalEd will refund to its ratepayers 50% of any proceeds that exceed legal expenses, Pizarro said. The rest of the money would be used to pay down or reduce the short-term debt associated with the utility’s capital spending program.
Edison anticipates receiving a decision on the matter later this year or early next year.
ERCOT’s latest seasonal forecasts indicate the ISO will continue to have more than enough generation capacity to meet demand into next summer, continuing a recent pattern of rosy forecasts.
ERCOT Control Room | ERCOT
According to the winter Seasonal Assessment of Resource Adequacy (SARA), ERCOT expects to have almost 82,000 MW available December to February, more than enough to meet an anticipated winter peak of 58,000 MW. That would exceed the ISO’s winter peak record of 57,265 MW, set in February 2011.
The preliminary spring SARA (March-May) also projects nearly 82,000 MW of available capacity and a seasonal peak of 58,000 MW in May. The assessment takes into account the expected spring generation outages for routine maintenance; the final spring SARA report will be released in March.
Asked about the recent positive forecasts, ERCOT Senior Director of System Planning Warren Lasher said, “I believe we’re in a period right now where we have adequate resources. The emphasis here is proving that assessment back to consumers.”
“We’ve added resources, but we’ve also modified our load forecast methodology,” said Pete Warnken, ERCOT’s manager of resource adequacy. “I believe it’s a more accurate, more on-target forecast.”
Lasher and Warnken both cautioned that continued congestion in the Lower Rio Grande Valley, which resulted in conservation calls in early October, remains a subject of concern. The 524-MW Frontera combined cycle plant’s withdrawal from the ERCOT system Oct. 1 to dispatch into the Mexican market has complicated the task of meeting demand along the U.S.-Mexico border.
“Our current expectation is we won’t have a similar call for conservation,” Lasher said.
Weather is not expected to play a factor this winter. Senior Meteorologist Chris Coleman said Texas hasn’t seen an extremely cold day since Feb. 2, 2011, and its coldest month in recent history came in December 1989. Lasher warned a few very cold days could drive up demand during early morning and evening hours.
ERCOT serves about 24 million customers and 90% of Texas’ load. The ISO has added 600 MW of new capacity since the preliminary winter SARA was released Sept. 1, and an additional 800 MW are expected to be in operation by December. New natural gas, wind and solar resources are expected to provide another 1,700 MW of capacity for the spring.
VALLEY FORGE, Pa. — PJM has determined that it must keep a loop flow in place with NYISO when the Con Ed-PSEG “wheel” ends next year, but that by 2021 that “operational baseflow” will be reduced to zero.
Presenting at the Market Implementation, Operating and Planning committees last week, PJM staff explained that anything less than a 400-MW loop flow on the current system would “impact” system reliability and minimize transfer capability across the seam.
The baseflow is “allowing us the flexibility to operate the system until we get some experience operating without the wheel in place,” PJM’s Ken Seiler said.
Staff also said they don’t expect “widespread congestion impacts” outside of the northern New Jersey and southern New York area.
Dave Pratzon of GT Power Group asked that PJM provide an annual review to see if maintaining the 400-MW operational baseflow assumption was necessary for reliable, economic system operation.
At the Planning Committee meeting, Citigroup Energy’s Barry Trayers said NYISO has been explaining that the 400-MW loop is necessary to keep PSEG North’s territory from “voltage collapse” and asked if that was accurate.
“We’re going to have to circle back with New York,” PJM’s Paul McGlynn said. “We haven’t seen anything like that in our analyses.”
He said they would also check with PJM’s Operations Department to determine if they’re seeing “anything close to that.”
Manual Updates Endorsed
The Planning Committee endorsed updates to three manuals.
In Manual 21: Rules and Procedures for Determination of Generating Capability, an acceptance test is now required for newly constructed units for which a summer/winter verification test after the unit is in service previously was sufficient. “Not many people are doing this so what we have to do is go back and look at your verification tests,” PJM’s Jerry Bell said. “You have to do this before you can cap-mod your unit up,” he added, using the shorthand for a notice of a capacity modification.
In addition to an administrative cleanup, the changes add detail to the testing requirements, including an expanded section on capacity interconnection rights. It also adds rules for non-hydro storage and removes class average information for wind and solar resources that will instead be posted to the planning resource page on PJM’s website.
Manual 14B: PJM Region Transmission Planning Process is being amended to remove from the capacity import limit (CIL) procedure references to the Reliability Pricing Model, PJM’s capacity market design. Starting with the 2020/21 delivery year, the CIL will not be applied as part of the capacity process. Instead, the limits will be considered during interconnection studies for new transmission service requests, part of new study procedures approved in early 2016.
PJM’s Michael Herman explained how the CIL will be calculated and used to determine that the import capacity is sufficient to support PJM’s capacity benefit margin (CBM), the portion of the RTO’s emergency import capability that is deducted from total transfer capability to determine available transfer capability (ATC). CBM is reserved to import capacity assistance from external areas under emergency conditions.
Section G.11 states that the CIL “is used to confirm that import capability into the PJM system is sufficient to support the PJM [CBM] as well as confirmed long-term firm transmission service.”
American Municipal Power’s Ed Tatum questioned how “sufficient” is determined. McGlynn explained there is an annual study in accordance with NERC reliability standards. Stakeholders endorsed the intent of the manual changes but asked that that explanation be written into the revisions. Herman confirmed that they will be.
In Manual 14A: Generation and Transmission Interconnection Process, the word “interconnection” is being replaced with “new service” to ensure cost allocation will occur for all projects. The change addressed needs identified at special PC sessions regarding new service request cost allocation and study methods.
Too Soon to Include CO2 Pricing in Market Efficiency Analyses
PJM staff have decided not to incorporate CO2 prices into their analysis of market efficiency transmission projects, saying that accurately projecting the likely price depends heavily on how — or whether — states comply with EPA’s Clean Power Plan.
| PJM
“States have seven different compliance pathways and their choices will have very different impacts on resource entry and exit,” PJM said in a presentation.
“Right now, there’s not a clear driver that could be built into the market efficiency scenario,” PJM’s Muhsin Abdur-Rahman told the PC.
Load Voices Concern over Transmission Repair Costs
During a review of immediate-need projects, members of the Transmission Expansion Advisory Committee questioned the proposed solutions for the loss of the South Butler-Collingwood 345-kV line in American Electric Power’s transmission zone, which would result in a loss of more than 300 MW of load.
AEP Transmission Zone | PJM
The region, an industrial zone in which continued growth is expected, is partially served by local 69-kV lines built in the 1950s with wood poles and distribution-class cross arms. A wholesale distribution cooperative served by such 69-kV lines has experienced multiple forced and momentary outages recently, planners said.
One option, which was estimated to cost $76.5 million, would add a new 345-kV switching station near Steel Dynamics Inc. (SDI) in Butler, Ind., a tap of the Rob Park–Allen 345-kV line and the addition of about 17 miles of a double-circuit 345-kV line.
PJM recommended a second option, estimated to cost $108 million. It would add new 138-kV and 345/138-kV stations and reconstruct sections of the Butler-North Hicksville and Auburn-Butler 69-kV lines as 138-kV double-circuit lines. In addition, the 138-kV circuit between Dunton Lake and the SDI Wilmington substation would be reconductored.
When AMP’s Tatum asked why the project was needed immediately and could not be included in a competitive window, McGlynn explained that a data error had recently been found in the modeling, revealing that there is an overload on the line currently.
Tatum said AMP “has a problem moving forward with this.”
Carl Johnson of the PJM Public Power Coalition pointed out that this project is “exactly the kind of issue” that caused the formation of the Transmission Replacement Processes Senior Task Force. “You’re probably making the right choice, but … you couldn’t have handed us a better example,” he said.
Reimbursement through this process would distribute the costs throughout the RTO, despite the fact that part of project would replace aging infrastructure, which should stay with AEP, Johnson said.
“We’re seeing more and more examples of this,” he said.
Looking over all of the projects, Tatum commented that, “It looks like we have $520 million of projects that are immediate need. … I don’t know what we can do in the planning process to get out in front of that.”
“If we were all doing our jobs perfectly and properly, we wouldn’t have any immediate need projects,” McGlynn conceded.
Tatum then pointed out seven projects whose cost estimates had ballooned from $205 million originally to $372 million, about an 82% increase.
“We might need to do better than an 82% increase, and I’d like to see if PJM could help us with that,” he said. “I hope that as we move forward and continue enhancing our planning process and ability that our cost estimates might be a little bit more robust at the initiation of a project.”
SPP’s recent trend of sending market-to-market payments to MISO continued in September, but that trend figures to reverse itself in the months that follow.
SPP’s Gerardo Ugalde told the Seams Steering Committee on Wednesday that the RTO sent $1.66 million to MISO as a result of temporary and permanent flowgates with the ISO. It was the third straight month the M2M process has resulted in a payment from SPP to MISO.
| SPP
“We don’t foresee this showing up in November,” Ugalde said. “This seems to be a seasonal change, where the flows flip.”
Temporary flowgates resulted in 591 hours of binding M2M and $1.14 million in charges from SPP to MISO; permanent flowgates added another $517,000 in M2M charges to the RTO as a result of 441 hours binding.
SPP Interregional Coordinator Adam Bell reminded stakeholders of a Nov. 30 deadline to submit projects they would like to see included in a potential joint study with the ISO as part of the 2016 Coordinated System Plan. (See “SPP, MISO Shared Joint Study Needs List,” SPP Briefs.)
Bell said initial discussions have been held with MISO to use the targeted study as the “foundation” for a “much broader study” next year. He said progress has been slow in developing coordinated system plans with both the ISO and Missouri-based Associated Electric Cooperative Inc.
CenterPoint Energy continues to focus on its gas business even as its regulated electric business contributed to a strong third-quarter earnings report.
The Houston-based company, which owns electric transmission and distribution and natural gas distribution, sales and services subsidiaries, on Friday reported a third-quarter profit of $179 million ($0.41/share), beating a Zacks Investment Research consensus of $0.37/share.
| CenterPoint Energy
It was a marked reversal from the same period last year, when CenterPoint reported a $391 million loss after a taking an $862 million impairment charge due to its investment in struggling Enable Midstream Partners.
CenterPoint’s revenues for the quarter rose 16% to $1.9 billion, including $908 million from its electric transmission and distribution segment, an almost 10% increase over a year earlier. The company attributed the rise to customer growth and higher rates.
Earlier last week, CenterPoint announced its CenterPoint Energy Services had reached an agreement to acquire Atmos Energy Marketing for $40 million. Atmos, which manages assets for utilities, power plants and local distribution companies, will add six states to the 26 in which CenterPoint Energy Services already markets its energy packages.
“This deal will allow us to grow our customer base and revenues while maintaining a low operating model and a cost-effective organization,” Joe McGoldrick, president of CenterPoint’s gas division, said during a conference call with analysts Friday. “This deal will increase our scale, geographic reach and expand our capabilities.”
CenterPoint is also continuing to evaluate “strategic alternatives” for its Midstream partnership with Oklahoma-based OGE Energy, including a sale or spinoff, to “reduce exposure to commodity price influences,” CEO Scott Prochazka said.
CFO Bill Rogers told analysts the company is continuing its discussions with interested parties. If no deal is reached by mid-January, CenterPoint will be required to submit a right-of-first-offer to OGE — allowing OGE to buy out CenterPoint’s interest — before continuing discussions with other prospects, Rogers said. (See CenterPoint Abandons REIT Plan; Offers Stake in Gas Partnership to OGE.)
Duke Energy last week announced five executive appointments — effective at varying dates between now and year-end — with the goal of strengthening its regulatory and economic development initiatives.
Clark Gillespy, currently South Carolina state president, will become senior vice president of economic development. Alex Glenn, currently Florida state president, will become senior vice president of state and federal regulatory legal support.
Kodwo Ghartey-Tagoe, currently a senior vice president of state and federal regulatory legal support, will take over Gillespy’s role. Harry Sideris, currently a senior vice president of environmental health and safety, will take over Glenn’s role. Paul Draovitch, currently a senior vice president for fossil-hydro operations, will take over Sideris’ role.
PG&E Hit with Federal Lawsuit over Pension Benefits
Three Pacific Gas and Electric workers filed a lawsuit Nov. 1 in the U.S. District Court for the Northern District of California accusing the utility of wrongly classifying them as independent contractors to deny them pension benefits.
The lawsuit alleges that PG&E adopted different and conflicting interpretations of its pension plan and stopped asking its counsel for advice “when it did not like the results.”
Emails and memoranda that allegedly support the workers’ allegations are attached to the court filing. The internal documents came to light during another worker’s pension lawsuit settled by PG&E in 2013.
Swiss Companies to Supply Battery Storage System for PJM
Swiss Green Electricity Management Group, which invests in energy storage projects, has announced a partnership with fellow Switzerland-based company Leclanché to supply a 20MW/10MWh battery storage system for PJM’s frequency regulation market.
Leclanché will act as SGEM’s engineering, procurement and construction partner and supply the battery storage system, which will be constructed in Marengo, Ill.
In August, the two signed an agreement that gives SGEM right of first offer for Leclanché projects, which are expected to grow to more than 85 MWh in 2017.
Duke Energy, Siemens Team Up for Wind Farm Services
Duke Energy Renewables and Siemens’ wind power and renewables division are teaming up to provide operations and maintenance services for wind farms whose turbines have multiple manufacturers.
Under their agreement, the companies can bid separately on services at wind projects. If either company wins a contract, it will bring the other in for appropriate work.
The partnership establishes “one-stop shopping” for wind farm owners who would otherwise need to make separate contracts with each original equipment supplier, Duke Renewables spokeswoman Tammie McGee said.
GE to Supply Converter Stations For Plains & Eastern Clean Line
GE Energy Connections will supply three HVDC converter stations to Clean Line Energy Partners for its $2.5 billion Plains & Eastern project, which will deliver 4,000 MW of wind power generated in the Oklahoma panhandle over a 720-mile system to a terminal near Memphis, Tenn.
Clean Line selected GE as the exclusive provider of the stations, which will convert electricity from DC to AC. The stations will be located in Pope County, Ark.; Texas County, Okla.; and Shelby County, Tenn. Construction could begin in the second half of 2017.
GE described HVDC transmission as “the most efficient means of connecting wind generation to distant end-use customers.”
Marcellus Shale Partnership Ends For Noble Energy, Consol Energy
Noble Energy and Consol Energy announced last week that they have ended their shale exploration partnership in the Marcellus drilling region.
In 2011 the companies agreed to jointly explore and develop 669,000 acres across Pennsylvania and West Virginia, producing 1.07 Bcfd of natural gas equivalent.
Noble will keep 363,000 acres, producing about 450 Mcfd of natural gas equivalent and pay Consol $205 million. Consol will keep 306,000 acres producing 620 Mcfd.
Amazon Plans Ohio Wind Farm To Power Cloud Computing Business
Amazon announced last week that it is planning a wind farm in Hardin County, Ohio, to help power its cloud computing business.
The wind farm, scheduled to open in December 2017, will be the fifth renewable energy project undertaken by the company’s cloud computing division and its second wind farm in Ohio.
The new wind farm will generate 530,000 MWh of wind energy per year and feed into the grid connected to the division’s Ohio and Virginia data centers.
Utilities Partner to Share Equipment During Disasters
A group of utilities in the Southeast have created a program to identify spare transformers and other transmission equipment that they can obtain from each other if disasters should strike.
Southern Co., Louisville Gas and Electric and Kentucky Utilities, PPL Electric Utilities and Tennessee Valley Authority last week announced the Regional Equipment Sharing for Transmission Outage Restoration (RESTORE) program, which would make needed transmission equipment available for purchase by the participating utilities.
The companies are interested in expanding the voluntary program to include others in the region.
FirstEnergy Must Save $200M To Preserve Credit Rating
FirstEnergy must find cost savings of about $200 million to preserve its credit rating — and possibly stay independent after receiving about half of a special rate rider it requested from Ohio’s Public Utilities Commission.
“We’re evaluating everything we do as a company to try and find a way to close that gap. Because [what’s been done so far] is not enough to get us into the position with the credit rating agencies that we need to be in,” CEO Chuck Jones said.
FirstEnergy’s stock is trading at 12 times the company’s earnings, with many of its competitors’ shares trading at 20 times their earnings, Jones said.
With unprofitable power plants dragging down its bottom line, FirstEnergy says it is calling it quits on competitive generation. And its days as a competitive retail supplier may be numbered as well.
CEO Charles Jones said during the company’s third-quarter earnings call Friday that the company will seek to sell its 17,000 MW of competitive generation or persuade Ohio regulators to transfer them into rate-base units.
“After the election is over … we plan to begin legislative and regulatory efforts designed to preserve our remaining generation assets. We are looking to convert competitive generation to a regulated or regulated-light construct in Ohio,” Jones said. “We’re also open to exploring the sale of any or all of these assets, particularly the gas and hydro units at Allegheny Energy Supply. If we find that one or more of these options are not viable, we’ll also consider deactivating additional competitive generating units, similar to the ones we announced this summer at Sammis Units 1 through 4 and Bay Shore.”
Sammis Power Plant | Bechtel
He also raised the prospect of a bankruptcy filing for FirstEnergy Solutions, the company’s competitive retail arm.
The news came as FirstEnergy reported earnings of $380 million ($0.89/share), down slightly from earnings of $395 million ($0.94/share) for the same period last year. The company expects a loss of $1.30 to $0.90/share for the year.
Jones said the company would be seeking a “solution” for its nuclear units in Ohio and Pennsylvania “that recognizes the environmental benefits of these established baseload-generating resources.” New York regulators’ approval of a zero-emissions credits system to preserve the state’s upstate nuclear plants has been challenged in court. (See Federal Suit Challenges NY Nuclear Subsidies.)
$1.1B Loss
Jones’ announcement on the fate of FirstEnergy’s merchant generation was his most definitive yet. After posting a $1.1 billion second-quarter loss tied to the closure of five coal-fired plants, Jones said the company would not make any large investments to prop up the credit rating of its generation business. (See FirstEnergy Posts $1.1B Loss, Eyes Exit from Merchant Generation.)
Last month, the company was disappointed when Ohio regulators rebuffed its request for a $4.46 billion subsidy spread over eight years, approving instead $612 million over three years. (See PUCO Rejects FirstEnergy’s $558M Rider, OKs $132.5M.)
Jones last week blamed “weak” current prices and “anemic” demand forecasts for the poor financial performance of the generation fleet, which he said “is weighing down the rest of our company.”
“And while we have fought hard, we cannot continue to wait for an upturn,” he said. “We believe an accelerated timeframe is necessary so that we can remove lingering uncertainty, especially for our employees, and ensure that our company is singularly focused on the transition to becoming a fully regulated company.”
Jones estimated it would take 12 to 18 months for the company to execute its plans for its generation.
He also warned of deteriorating conditions at FirstEnergy Solutions, which sells retail energy to residential, commercial and industrial customers in the Northeast, Midwest and Mid-Atlantic regions.
“Further downgrades … by the rating agencies could require posting additional collateral of $355 million,” he said. “The continued viability of FirstEnergy Solutions is also pressured by some additional risks over the near term. These risks, which include an inability to implement our strategic alternatives in a timely manner, an adverse outcome related to a coal transportation contract dispute at FirstEnergy Solutions, or the inability for FirstEnergy Solutions to extend or refinance debt maturities of $515 million in 2018 could cause FirstEnergy Solutions to take additional actions, including restructuring its debt and other financial obligations or seeking bankruptcy protection.”
In West Virginia, meanwhile, FirstEnergy’s Mon Power subsidiary plans to issue a solicitation by the end of this year to address its generation shortfall.
VALLEY FORGE, Pa. — After months of debate, PJM’s Manual 15 revisions on fuel-cost policies and hourly offers won the approval of the Market Implementation Committee on Wednesday.
The changes are based on FERC’s approval of related Tariff changes that were filed in August (ER16-372).
Catherine Tyler Mooney of Monitoring Analytics, PJM’s Independent Market Monitor, questioned why some language on the review process that the Monitor and PJM had previously agreed upon had been struck from the revisions.
PJM’s Jeff Schmidt explained that elsewhere in the manual, the policy review was detailed as a “collaborative process” between the Monitor and PJM, so it needed to read that way everywhere in the manual. “The way we had it broken up before, it was staged,” he said. “It didn’t make sense for one [section] to be staged or stepped, and one to be at the same time.”
The section in question put generators on a five-day clock for responding to inquiries from the Monitor. “If the [Monitor] lets us know you want us to keep track of the clock, we’ll start the clock,” Schmidt explained. “If you have some specific question during the process about the fuel-cost policy, you have to let us know [to start the clock]. Then we’ll keep track of it.”
Mooney indicated that the explanation wasn’t satisfactory, but she declined to continue the debate. The exchange was the latest skirmish in an ongoing dispute between PJM and the Monitor. (See PJM Attempting to Usurp Market Mitigation Role, Monitor Says.)
Several stakeholders, including Mike Borgatti of Gabel Associates, had concerns with how that plan would be implemented to ensure a generator is aware whether it’s on the clock or not. Schmidt assured him that PJM would make them aware.
Schmidt’s efforts were good enough for Calpine’s David “Scarp” Scarpignato. “I’d like to do something I usually don’t do: I’d like to commend you,” he told Schmidt. “It’s pretty specific what this engineering judgment is referring to, and I think this is a well-written sentence.”
The revisions were endorsed with seven objections and two abstentions.
‘Fully Metered’ EDC Definition OK’d
Members endorsed by acclamation Manual 28 changes describing a “fully metered” electric distribution company.
The changes were developed in response to a stakeholder request for a definition of the phrase, which was added in a recent update to Manual 01: Control Center and Data Exchange Requirements.
The new language in Manual 28: Operating Agreement Accounting defines a fully metered EDC as one that “reports hourly net energy flows from all metered tie lines to PJM via Power Meter and revenue meter data for the hourly net energy delivered by all generators within that EDC’s territory via Power Meter, for the purposes of energy market accounting.”
PJM’s Tom Hauske had come to the MIC meeting hoping for endorsement of changes to the Tariff and Manuals 11, 12 and 28 relating to operating parameters. But the Monitor’s concerns about definitions and modeling shelved that idea and the item was changed from an endorsement to a first read. (See “Stakeholders Approve Last-Minute PJM-IMM Operating Parameters Collaboration,” PJM Market Implementation Committee Briefs.)
Monitoring Analytics’ Joel Romero Luna raised concerns with how the definitions were applied, specifically pointing to what he saw as an over-complication of how to handle facilities with multiple breakers. He suggested standardizing the language to “the last breaker” throughout the revisions.
“When there’s one breaker, that’s always the last one,” he said.
Based on Luna’s concerns, Dave Pratzon of GT Power Group suggested delaying the vote until the Monitor had revised the language. “Personally, I can’t see voting on something where the [Monitor] is going to come back and make changes,” he said.
More Adjustments for Five-Minute Settlement
PJM will transition from an hourly calculation to a five-minute calculation for balancing spot market energy charges in order to eliminate an imbalance created when values such as demand, generation, imports and exports are calculated on different time scales, PJM’s Ray Fernandez explained.
Additionally, PJM proposed including the value of the generation and load imbalance in the transmission loss charges calculation and the transmission loss credits allocation. (See “Order 825 Progress,” PJM Market Implementation Committee Briefs.)
“The key piece to remember in here is the five-minute [generation-to-load] imbalance component,” Fernandez said. “That component is part of the balancing spot-market charge.”
PJM’s shortage pricing proposals from Oct. 26 and Nov. 2. | PJM
Next, PJM’s Rebecca Stadelmeyer explained the RTO’s proposed adjustments to shortage pricing to integrate with five-minute settlement requirements. PJM’s plan would change the scarcity signal for the maximum $850 penalty factor from the economic maximum of the single largest contingency to the highest actual output of a single unit. Next, it would add two lower “steps” that would trip a $300 pricing level. One step would be calculated as the highest actual output plus 190 MW — a static number derived from the synchronous reserve mean of the Mid-Atlantic Dominion zone plus one standard deviation. The second step would be calculated as the previous step plus an extension.
Stakeholders had several concerns with the proposal. Direct Energy’s Jeff Whitehead questioned the value of additional penalty thresholds that would just trigger lower levels of scarcity pricing more often. “I’m still a little perplexed as to why the reserve requirement is even being discussed here,” he said.
PJM argued it would reduce volatility.
IMM Clarifies Fuel-Cost Policies
Bowring outlined fuel-cost issues he’s observed and how they should be handled. First, he addressed penalty gas — gas used by generators that exceeds the amount the generator committed to using that day.
“The basic issue with penalty gas is it’s intended to be an incentive to not use the gas,” he said. “It’s not appropriate to include that in the cost of your gas.”
Stakeholders took exception to that, saying not being able to recover those costs would make them less likely to respond if called by PJM.
Bowring also discussed how generators should account for the costs of “ratable take” gas — gas that is not guaranteed to be available. “If a generator chooses to take a less-firm service, that’s fine, but they should take the risk,” he said.
Again, stakeholders were less than enthusiastic with Bowring’s perspective. “We need to be able to recover the costs of responding to PJM’s request. If we can’t do that, we’re going to have issues,” Dynegy’s Jason Cox said. (See Heeding Stakeholders, PJM Reduces Proposed Fuel-Cost Penalties.)
Generators Displeased with FTR Adjustments
To comply with FERC’s order on assigning balancing congestion costs, PJM is proposing several changes to its financial transmission rights market. First, it plans to assign all real-time balancing congestion to load. Along with that, PJM proposed returning to auction revenue rights holders any FTR auction and day-ahead congestion surplus after ARRs and FTRs are fully funded.
“PJM believes the allocation of FTR surplus should change to align closer with allocation of balancing congestion,” PJM’s Asanga Perera said in his presentation.
PJM also proposed annual replacement of retired Stage 1 paths. “We would only consider any future replacements as units retire. in other words, we wouldn’t be doing this process over and over every year,” Perera said. PJM has proposed a hybrid plan that would replace merchant paths RTO-wide and zonal-wide rate-based paths only in that zone.
Calpine’s Scarp was concerned with this approach. “I think you need to go back to the original presumption, which is, ‘Those who pay for the transmission get the rights,’” he said. “To say I have [capacity injection rights] and don’t get some of the incremental ARRs doesn’t make sense.”
“Why would a generator need a congestion hedge?” asked PJM’s Tim Horger. “They have no load.”
“I think the generator deliverability analysis lines up directly with the load deliverability analysis,” Scarp said. “There’s a parallel here. You can ignore it if you want, but I’m telling you it exists.”
The Long Island Power Authority is inching toward New York’s first offshore wind farm, which would supply 90 MW of electricity on a site off the eastern tip, said Mike Voltz, director of energy efficiency and renewables for PSEG-Long Island, which operates the power grid for LIPA. “We expect that power purchase agreement to go to the LIPA board of trustees in December for approval.”
David Mooney, director of the Strategic Energy Analysis Center at the National Renewable Energy Laboratory, discussed how New York could meet its 50% clean energy mandate. Because the current hydropower penetration of 20% is not expected to increase substantially, wind and solar would make up the remainder.
“There’s enough flexibility that exists in the system to be able to manage 30% penetration of wind and solar, and that’s without adding storage to manage variability,” he said.
Charles Fox, senior director of regulatory affairs and business development for fuel cell manufacturer Bloom Energy, praised New York’s level of sophistication in discussing clean energy policy. But he said the state needs to proceed with caution.
“The process of implementation is absolutely critical. We all want to get to the promise of Reforming the Energy Vision, but it’s important to do that to recognize that not only customers but financial institutions have entrenched business models that are going to need to change to finance projects. With companies that may have power purchase agreements in seven to 10 states, and when you suddenly change the rules in one of those places, it has a reverberating effect through just the law of unintended consequences.”
Richard Kauffman, Gov. Andrew Cuomo’s chairman of energy and finance for New York, took on critics of the zero-emission credit program, which would subsidize upstate nuclear plants to keep their carbon-free generation available for another 14 years.
“It would be great, as some critics would have us do, to say ‘let’s replace the nuclear plants with renewable energy. Let’s do that right now.’ It’s just not practical,” he said. “We cannot snap our fingers and have it done. We need to recognize the role nuclear will play in a transition to a renewable energy future, as no one has put forth a credible plan for cost- and time-effective replacement.”
Jim Muscato, a partner at the Young/Sommer law firm, which has represented wind developers for 15 years, said permitting has become more difficult as state agencies like the departments of Health and Transportation become involved.
“The totality of the siting process is that it will take about three years. One of the specific challenges is that the government does not speak with one voice. When getting through the preapplication process, we’ve had more government agencies get involved in the process than have ever been involved before. We’ve had 15 years successfully siting projects, but now we are working with agencies that had never been involved before.”
Clark Gillespy, currently South Carolina state president, will become senior vice president of economic development. Alex Glenn, currently Florida state president, will become senior vice president of state and federal regulatory legal support.
Amazon announced last week that it is planning a wind farm in Hardin County, Ohio, to help power its cloud computing business.
FirstEnergy must find cost savings of about $200 million to preserve its credit rating — and possibly stay independent after receiving about half of a special rate rider it requested from Ohio’s Public Utilities Commission.
