Whitley, who retired last October after seven years at the ISO, emphasized the importance of wires and pipelines in his keynote speech Wednesday at the Northeast Energy and Commerce Association’s 23rd Annual New England Energy Conference.
He reflected on his career, which also included 30 years of operations and management positions at the Tennessee Valley Authority before he moved to the Northeast. His personal highlight reel seemed to be a solid string of crisis management. Nuclear shutdowns at TVA in the late 1980s. The 2003 blackout. A horrific New England cold snap in 2004. Hurricane Sandy. The polar vortex.
“It seemed like these problems followed me around,” he joked.
A common theme was “the need for transmission” to navigate through these near-disasters.
Five-Year Shutdown
In 1985, the Nuclear Regulatory Commission ordered shutdowns of the Brown’s Ferry plant in Alabama and the Sequoya station in Tennessee over safety concerns.
“It was 6,000 MW of capacity and we thought it would be three or four months, but it turned out to be five years,” he said.
The TVA hydro system simultaneously suffered through two droughts, so 4,000 MW of hydropower were reduced to 2,500 MW for much of that time, causing “a few tough years.”
“The way we got through it most of the time was through the transmission grid,” Whitley said.
Whitley said the system survived through imports from areas with greater fuel diversity, an experience that would be repeated in his later jobs in New England and New York.
7,000 MW out of Service
In 2004, New England — less reliant on natural gas for power generation than it is now — suffered through five days with minus 10-degree temperatures and 45-mph winds, recalled Whitley, who was ISO-NE’s chief operating officer at the time. “One day I went to the control room and one of the operators told me we had 7,000 MW of power plants that couldn’t come online.”
The crisis was eased when some New York generators switched to oil-fired generation, which freed up some gas pipeline capacity.
“That’s when you see it’s not just the electric system that is so important, it’s the infrastructure of the gas supply system and the diversity of the generation capacity,” Whitley said.
Transmission, fuel diversity and imports also got NYISO through Hurricane Sandy in 2012 and the polar vortex in early 2014.
Whitley said he worries the next crisis could result from the Northeast’s switch to “all renewables and gas” without, he says, adequate infrastructure to support it. He said the recent suspension of the Northeast Energy Direct pipeline was disappointing. (See Kinder Morgan Board Suspends Work on Northeast Energy Direct Pipeline.)
Without diverse energy supplies and robust infrastructure, he said, the system will be stressed.
“Each region is going to have to be more capable of carrying its own load,” Whitley said. “As all these coal plants shut down, there just isn’t going to that much surplus available.”
VALLEY FORGE, Pa. — Interconnection customers would face a stricter submittal process for their projects beginning Nov. 1 under Tariff changes unanimously approved Thursday by the Planning Committee.
The revisions were recommended by the Earlier Queue Submittal Task Force, which was convened to figure out ways to incent earlier participation in the process after current rules failed to influence behavior. (See “Stricter Rules Proposed for Queue Submittal Process,” PJM Planning Committee and TEAC Briefs.)
In general, the changes require earlier submittal of documentation in order to secure a place in the project queue. PJM would perform a deficiency review only after all elements, aside from site control, were in hand.
Applications would have to clear their deficiencies by the close of the queue window or be terminated.
The revisions also would allow project deposits to become chargeable immediately, and PJM would spend the refundable portions first.
In addition, the opening of queue windows would be moved up to April from May and to October from November, which will improve the chances for large generators to participate in the May Base Residual Auction.
Typical TO Upgrades Would be Excluded from Competitive Window Under Proposal
PJM is proposing to exclude typical transmission substation equipment violations from the Order 1000 competitive window process. The Planning and Markets and Reliability committees will be asked to approve new Operating Agreement language in June.
A historical look at the Regional Transmission Expansion Plan revealed that such fixes rarely yield greenfield proposals. If analysis showed that a greenfield project is possible, PJM would open a proposal window.
The exclusion would not apply to supplemental or market efficiency projects. (See “Proposal Would Exclude TO Upgrades from Order 1000 Window,” PJM Planning Committee and TEAC Briefs.)
IRM Study Assumptions Presented for First Read
The Resource Adequacy Analysis Subcommittee is recommending that PJM retain its current load model selection process for the installed reserve margin (IRM) study with one minor change: The procedure will be modified to recognize that the annual peak can only occur in the peak summer week.
PJM’s Tom Falin said that had the change been implemented for the 2015 reserve requirement study, it would have resulted in the same load model being chosen and produced the same IRM and forecast pool requirement.
The Planning Committee will be asked to endorse the study assumptions at its next meeting.
“It’s really a minor change with no consequence,” Falin said.
Planners will continue to model a 2,500-MW ambient derating in the summer period.
The RAAS met six times over five months to study all of the assumptions used in the IRM study after PJM’s methodology was questioned. (See “IRM, FPR Rising; PJM Methodology Challenged,” PJM Planning Committee Briefs.)
The group identified three assumptions that warranted in-depth investigation: the load model selection process, world modeling and the capacity benefit of ties, and the ambient derating of generators in the summer period.
“It’s essentially the same as last year, but the subcommittee is more comfortable with those assumptions after having drilled into them,” Falin said.
PJM-MISO to Create ‘Targeted Market Efficiency Projects’
PJM and MISO are working to revise their joint operating agreement to create a category of “targeted market efficiency projects” that could be undertaken quickly and relatively inexpensively to remedy historical congestion. These would be treated separately from traditional market efficiency projects, which look at projected model conditions under future assumptions, said PJM’s Chuck Liebold.
“These projects would be very targeted in nature,” he said. They probably would consist of upgrades to terminal equipment, and an aggressive in-service date would be assigned to them.
The upgrades would be recommended on an annual basis, with proposals going before the boards of each RTO in December.
He said the study process will be similar to an effort the RTOs undertook last year, when they were unable to approve any projects. (See MISO-PJM ‘Quick Hit’ Projects Shrink to Two.)
The projects would be evaluated based on five years of benefits at a benefit-cost ratio of 1.0.
Planners Choose Project to Relieve APSouth Congestion
Planners intend to recommend a $340.6 million APSouth market efficiency project to the Board of Managers, despite some stakeholders’ recommendations that they take another look at three other proposals.
LS Power’s Sharon Segner said that the 9A (without capacitors) proposal is not necessarily the most feasible and that it faces permitting problems.
“We’ve been [evaluating proposals] for more than a year now, and I am confident with what we’re proposing now,” PJM’s Tim Horger said.
He said the project provides the most congestion savings to PJM and APSouth as well as the most production cost savings.
The project would tap the Conemaugh-Hunterstown 500-kV line and build a new 230-kV double circuit line between Rice and Ringgold. The plan also calls for building a new 230-kV double circuit line between Furnace Run and Conastone and rebuilding the Conastone-Northwest 230-kV line. (See “Planners Select Dominion-Transource Project to Address APSouth Congestion,” PJM Transmission Expansion Advisory Committee Briefs.)
It is projected to be in service by 2020.
Two Dominion Zone Reliability Projects Recommended
PJM presented two reliability projects it intends to recommend to the Board of Managers out of more than two dozen it received in the first proposal window of the year.
Both are in the Dominion transmission zone in Virginia, with projected in-service dates of June 1, 2020.
One addresses the overload of the Chesterfield-Messer Road-Charles City Road 230-kV circuit. The $22 million project consists of rebuilding 21.3 miles of existing line between Chesterfield and Lakeside.
The other addresses the overload of the Carson-Rogers Road 500-kV circuit. The $48.5 million project would rebuild the circuit.
Cogentrix Hopewell Units to be Deactivated
PJM has received a deactivation notice from James River Genco for Units 1 and 2 of Cogentrix Hopewell in the Dominion zone.
Together, the units represent 92 MW. The requested deactivation date is May 31, 2017.
PJM is conducting a reliability analysis.
Preliminary CPP Compliance Analysis Presented
PJM presented some of the first findings of its study of Clean Power Plan compliance to Transmission Expansion Advisory Committee members.
The review continues to indicate that regional compliance is cheaper. In addition, it showed that mass-based compliance provides more certainty in emissions levels than rate-based but that the latter approach can lead to fewer retirements.
Rate-based compliance also reduces wholesale energy market prices. (See “Reference Model for CPP Study Introduced,” PJM Planning Committee and TEAC Briefs.)
VALLEY FORGE, Pa. — About 1,900 MW of behind-the-meter generation may be unavailable because of tightened environmental rules, PJM told the Operating Committee last week.
PJM shared with the committee new EPA guidance issued in response to an appellate court decision last year that voided a rule exempting diesel generators providing demand response from air emissions limits.
EPA had exempted reciprocating internal combustion engines providing “emergency demand response” from emissions limits for up to 100 hours each year. The D.C. Circuit Court of Appeals ruled that the agency had “cavalierly sidestepped its responsibility to address reasonable alternatives” to the use of the generators. (See Appellate Court Rejects EPA Rule on Back-Up Generators.)
As a result of the ruling, EPA said such an engine “may not operate … for any number of hours per year unless it is in compliance with the emission standards and other applicable requirements for a nonemergency engine.”
That means behind-the-meter generation may only be used if it can respond when dispatched by PJM and comply with local, state and federal laws, including environmental permits, PJM said. Demand response that fails to perform when dispatched by PJM will be penalized, and there are no exceptions for the status of environmental permits.
“We have reached out and talked to our [curtailment service providers], and virtually everyone we talked to has made arrangements so they can meet their commitment for the summer,” PJM’s Pete Langbein said. “We at PJM do not see an impact going into the summer on capacity.”
Generators Employing Best Practices for Winterization
ReliabilityFirst Corp. gave the Operating Committee a lessons learned presentation resulting from its plant winterization visits since 2014.
PJM members have deployed “inventive solutions,” including additional enclosures to prevent freezing, portable heaters and a downspout system to divert rain and moisture away from inlet air filters, ReliabilityFirst said.
It identified just three areas for improvement: routinely operate any idle or standby equipment; make sure heat “tracing” or freeze protection is installed on any vulnerable equipment; and ensure the plant instrument air system is continuously supplying moisture-free air.
PJM Proposes to Sunset SIS, Move Topics to DMS
PJM is proposing to sunset the Systems Information Subcommittee and move some of its discussion topics to the Data Management Subcommittee, whose charter would be expanded.
Those topics relate to inter-control center communication protocol data links, Manual 01 changes and phasors.
The proposal also includes creating an “implementation forum,” which will be the primary venue for PJM to communicate technical changes to members and vendors.
Summer Base Case Study Yields No Reliability Issues
No reliability issues were identified in the 2016 summer base case study.
Off-cost generation re-dispatch and switching was required to control local thermal or voltage violations in some areas.
All voltage violations on networked transmission were controlled by capacitors, and all other such violations were caused by radial load, PJM said.
PJM energy market prices dropped 47.4% in the first quarter compared with a year earlier because of lower fuel prices and demand, the Independent Market Monitor reported in its quarterly State of the Market report.
LMPs averaged $26.80/MWh for the quarter versus $50.91/MWh in the first three months of 2015.
Net energy revenues — a measure of market performance and investment incentives — decreased by 62% for a new combustion turbine, 51% for a new combined cycle plant, 38% for new wind and 62% for a new solar installation.
Mild weather and low fuel prices contributed to a 79% drop in uplift costs, to $39.1 million from $186.4 million in 2015. Congestion costs decreased by almost 54% to $292.2 million.
Below is a summary of the issues scheduled to be brought to a vote at the Members Committee on Thursday during PJM’s Annual Meeting. Each item is listed by agenda number and description, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Cambridge, Md., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
CONSENT AGENDA
Members will be asked to approve revisions to Manual 34: PJM Stakeholder Process as a result of a periodic review. The changes update language and formatting for clarification and graphics for better readability.
Revisions to the governing documents involve non-substantive reorganization and relocation of definitions.
PJM proposes to change the emergency energy default customer baseline (CBL) from the “hour before” methodology to the current default economic CBL. (See “Members Endorse New Way to Measure Emergency DR,” Market Implementation Committee Briefs.)
Analysts are predicting lower clearing prices for PJM’s 2019/20 Base Residual Auction, which began Wednesday and concludes today. Results are to be published May 24.
Last year’s auction, held in August, saw prices of $164.77/MW-day for Capacity Performance in most of the RTO, with the ComEd zone at $215/MW-day and Eastern MAAC hitting $225.42. Base capacity priced about $15/MW-day lower. (See PJM Capacity Prices up 37% to $165/MW-day.)
Morningstar analyst Jordan Grimes forecasts a price of $160/MW-day for the Capacity Performance product in the RTO and MAAC regions and $180/MW-day in EMAAC and SWMAAC. He predicts base capacity will price at a discount of $10/MW-day.
Julien Dumoulin-Smith of UBS Securities reduced his forecast CP price from $140/MW-day to $125/MW-day for the RTO region, with prices higher in EMAAC, DPL-S, PS-N and PSEG ($200/MW-day) and ComEd ($225/MW-day).
“PJM participants fear a similar fate,” Grimes wrote. “We believe this fear is unwarranted. PJM will have to clear a significant amount of coal and peaking gas capacity in the upcoming auction.”
In a note to investors last week, Dumoulin-Smith said new gas generators, a lower load forecast and the Supreme Court ruling upholding FERC jurisdiction over demand response compensation will likely keep prices from rising in most of the region.
Dumoulin-Smith also said he expects a larger differential between CP and base capacity than last year. “We believe we could well see a base print for the RTO region below $100/MW-day. This pricing pressure could help limit any increase in demand response product availability.”
The RTO plans to acquire 157,092 MW of capacity for delivery year 2019/20, 80% of it Capacity Performance. This year’s price cap is $448.95/MW-day, compared with $450.86/MW-day for the 2018/19 auction.
This is the second and last year that the auction will offer two products. The base product will be eliminated beginning in the 2020/21 delivery year.
UBS predicts “price compression” in EMAAC, with Talen Energy’s Sapphire portfolio clearing at least partially.
Morningstar’s model predicts Exelon’s Quad Cities nuclear plant will not clear. Exelon CEO Chris Crane said earlier this month that the company will close Quad Cities if it doesn’t clear the auction and Illinois legislators don’t approve measures to shore up the money-losing plant. (See Absent Legislation, Exelon to Close Clinton, Quad Cities Nukes.)
UBS predicted disappointment for “more RTO-exposed generators” such as Dynegy, NRG Energy and FirstEnergy. It said that although it expects new capacity resources to clear the auction, their ability to obtain financing is in question.
“We have noted a meaningful slowing in development activity in recent months. Banks appear to be increasingly cautious to lend against assets given the wider pullback in power valuations and cumulative exposures to merchant PJM increasing. We expect this slowing to principally impact the 2020/21 auction next May 2017.”
Consolidated Edison will stop using the “PSEG wheel” next April, following through on a promise it made late last year in a dispute with PJM over transmission upgrade costs.
The company said it would not renew two point-to-point transmission agreements under which Public Service Electric and Gas takes 1,000 MW from Con Ed at the New York border and delivers it through New Jersey to Con Ed load in New York City.
Con Ed, which said it has identified less costly alternatives, informed the New York Public Service Commission of its decision in a letter May 2 (12-E-0503).
The company says that renewing the wheel after its April 30 expiration would expose it to $680 million in cost allocation charges for two transmission projects that it says primarily benefit New Jersey customers.
“Con Edison no longer requires power sources from the PJM wheel for reliability purposes, and unfair cost allocations have become too costly for our customers,” spokesman Bob McGee said. “Other electric projects added in recent years that already serve our customers will help us maintain reliability. We will continue to have access to the PJM wheel in an emergency.”
PJM assigned Con Ed $629 million of the costs of PSE&G’s $1.2 billion Bergen-Linden Corridor upgrade to address a short-circuit problem. PSE&G was allocated $52 million of the cost. Con Ed was also assigned $51 million of PSE&G’s $100 million Sewaren storm-hardening project.
Paul McGlynn, PJM general manager of system planning, told the PJM Planning Committee on Thursday of Con Ed’s intentions.
“We will need to make changes to the procedures we use in planning and operations,” he said. “This is just a heads-up that we’re going to need to be discussing it in the future. As plans take shape, we will be doing analysis on them. The goal is to discuss and determine how we will manage that interface without the wheel.
“When that wheeling agreement is canceled, we will need to redo cost allocations for any and all of the projects that Con Ed has allocation for, and we’ll have to file them at FERC. They would become effective when the agreement actually terminates in the spring of 2017,” McGlynn added.
“NYISO is working with PJM to develop an effective going-forward approach for the border,” ISO spokesman David Flanagan said. “In addition, NYISO will include this change in the full range of system information currently being gathered for the 2016 Reliability Needs Assessment that will study potential reliability needs for the period of 2017-2026.”
Bergen-Linden Corridor Upgrade Source: PSEG
Identification of the transmission projects that allowed Con Ed to cancel the wheel began in 2012, although for an entirely different reason. New York regulators at that time began discussions about transmission alternatives that would be needed if the Indian Point nuclear plant closed because its licenses were not renewed.
The NYPSC approved several projects in 2013 for that contingency, including three named the Transmission Owner Transmission Solutions. FERC in March accepted a cost allocation formula submitted by state regulators and New York transmission owners, including Con Ed. (See FERC OKs Settlement for NY TOTS Projects.)
One of the alternative projects, the $274.3 million “Staten Island Unbottling” would make 440 MW of generation available to the New York grid through Con Ed’s substations in a two-phase project.
However, in a February order, the NYPSC accepted a Con Ed motion to cancel the second phase. Con Ed said that once the wheel expired, transmission limitations caused by it would be eliminated and that only the $51.3 million first phase was necessary.
EPA said rules it issued Thursday to reduce methane emissions from oil and gas development will raise wholesale natural gas prices by less than 1%, but the industry’s leading trade group warned the “unreasonable and overly burdensome” regulations could depress shale gas development.
Infrared image of emissions from natural gas storage tank Source: Texas Commission on Environmental Quality
The agency said the rules will cost a net $320 million annually through 2020, with a $390 million total cost reduced by $70 million in revenue from sales of methane now lost into the atmosphere. By 2025, the estimated total cost increases to $640 million, offset by gas sales of $110 million, for a net cost of $530 million. The estimates, in 2012 dollars, assume a price of $4/Mcf.
EPA estimated that the rules will reduce gas well drilling by about 0.% and production by about 0.03% between 2020 and 2025, compared to the baseline. The agency estimated wellhead prices for onshore lower-48 production will increase during that period by about 0.2% and net imports will rise by about 0.11%.
Reduced Innovation?
The American Petroleum Institute said the costs will be more than twice EPA’s estimate, pegging them at $806 million per year in 2025.
“It doesn’t make sense that the administration would add unreasonable and overly burdensome regulations when the industry is already leading the way in reducing emissions,” Kyle Isakower, API’s vice president of regulatory and economic policy, said in a statement. “Imposing a one-size-fits-all scheme on the industry could actually stifle innovation and discourage investments in new technologies that could serve to further reduce emissions.”
The new rules are designed to reduce fugitive methane emissions from compressor stations, gas processing plants and well sites, including fracking operations. The rules also cover pneumatic pumps and controllers, centrifugal compressors and reciprocating compressors. Well site compressors are exempt.
Monitoring
The rules — which cover new and modified operations — are stringent, requiring substantially greater monitoring and emissions control than before across all areas of the extraction and production process. Well sites will be required to conduct biannual monitoring using either an infrared camera or a vapor “sniffer” and must repair leaks within 30 days. Compressor stations must be quarterly. Natural gas processing plants are already checked this way for other emissions, but they now must include methane.
Gas Separator Source: EPA
After fracking a well, operators will need to install equipment that separates gas from the fluid that flows back to the surface and collect or combust it. Wildcat, exploratory and low-pressure wells are required to have combustion devices but not the separation equipment.
Many of these operations were already regulated for volatile organic compounds (VOCs) and hazardous air pollutants (HAPs) — but not methane — under the 2012 New Source Performance Standards, which regulate pollutant emissions from new or modified sources. The new rules also include several edits to the NSPS, including how flares can be done, leak detection and repair, and monitoring and testing of storage-vessel control devices.
EPA said the rules are justified because the costs will be outweighed by “monetized climate benefits” of $360 million in 2020 and $690 million in 2025. Such benefits were calculated in relation to greehouse gas emissions only, but the agency said there will be additional benefits from the associated reductions in VOCs and HAPs.
Methane is second only to carbon dioxide in its overall contribution to global warming. A ton of methane traps 25 times as much heat in the atmosphere as the same amount of CO2 over a 100-year period.
The changes to the NSPS were released along with two other rules affecting the industry. One requires emissions reductions for operations on certain Native American lands. The other clarifies what equipment should be grouped together to calculate whether a site is a major or minor emissions source.
EPA estimates about 270 full-time equivalent workers will be needed to meet compliance. The agency estimates that will increase to about 1,800 in 2025.
The Public Utilities Commission of Ohio agreed Wednesday to hear FirstEnergy’s arguments for why it should be able to withdraw its controversial power purchase agreement and substitute a new plan.
It also granted all of the applications for rehearing sought by opponents of the PPA, including the Electric Power Supply Association, the Ohio Consumers’ Counsel, the Environmental Defense Fund, the Sierra Club, the Retail Energy Supply Association and the PJM Power Providers Group.
“Because of the number and complexity of the assignments of error raised in the applications for rehearing, as well as the potential for further evidentiary hearings in this matter, we find that it is appropriate to grant rehearing at this time,” the commission said (14-1297-EL-SSO). “This will allow parties to begin discovery in anticipation of potential further hearings.”
Although its rehearing request also was granted, the EDF protested the ruling.
“So, without listening to the arguments against the deal, the PUCO rubberstamped [FirstEnergy’s] request for a rehearing,” the EDF’s Dick Munson wrote in a blog post that went up within minutes of PUCO’s order.
Both FirstEnergy and American Electric Power were granted eight-year PPAs after more than a year of legal wrangling. But their victories were short lived, as FERC ruled that the agreements would require a review that could nullify them.
Opponents Sound Off
On Thursday, PUCO received a stream of filings against the modified FirstEnergy plan, including those from the Ohio Energy Group, the Northeast Ohio Public Energy Council, the Sierra Club, the PJM Power Providers Group (P3) and the Electric Power Supply Association.
P3 and EPSA accused FirstEnergy of doing an end-around play to avoid review by FERC. FirstEnergy, they said, is wrongly “attempting to use the commission’s application for rehearing process to circumvent the FERC order.”
“FirstEnergy, however, has made a mistake in how it presented its new PPA proposal to this commission,” they wrote. “FirstEnergy did not include or mention its new proposal in its application for rehearing, robbing the commission of jurisdiction over the proposal in this proceeding. This means that the commission cannot grant rehearing on the proposal and, contrary to its May 11, 2016, action, cannot reopen this proceeding to allow discovery on the proposal. The proposal is dead on arrival and the commission must follow the law by not exercising jurisdiction through rehearing.”
The Sierra Club also filed in opposition to the FirstEnergy plan.
“While FirstEnergy is trying to put old wine in a new bottle to escape review under federal customer protection standards, its latest shareholder bailout proposal is the same bad deal for Ohio customers,” said Shannon Fisk, managing attorney at Earthjustice, which represents the Sierra Club. “FERC smartly put a hold on FirstEnergy’s bailout so that customers would not be losing money while the legality of the bailout is fully reviewed. PUCO should not sign off on FirstEnergy’s brazen effort to evade FERC’s order.”
Thursday was also the deadline for arguments against AEP Ohio’s request to modify its PPA, and that docket also swelled with filings from opponents.
FERC ruled April 27 that the PPAs — in which AEP’s and FirstEnergy’s regulated utilities would purchase output from the companies’ merchant generators — must be reviewed under the Edgar affiliate abuse test (EL16-33 and EL16-34).
AEP CEO Nick Akins said after FERC’s ruling that the company would either lobby Ohio lawmakers to reregulate the state’s electricity market or sell off its Ohio fleet rather than submit to FERC review. FirstEnergy CEO Chuck Jones has also said he would welcome reregulation. (See All Eyes on AEP, FirstEnergy with Ohio PPAs in Doubt.)
Both utilities then filed for rehearing with PUCO. FirstEnergy asked the commission to withdraw its PPA and replace it with a customer charge that would still protect its aging power plants. Munson called FirstEnergy’s new plan “sleight of hand” and said PUCO’s decision Wednesday “suggests commissioners care more about appeasing a politically connected company than protecting customers or considering both sides of an argument.”
AEP Request
AEP scaled back its original request for PPAs for all of its 3,100-MW Ohio merchant fleet, asking PUCO for an agreement covering only its 440-MW share of the Ohio Valley Electric Corp. (14-1693-EL-RDR, 14-1694-EL-AAM). AEP said it will stand by its commitment to develop 900 MW of renewable energy — a promise that convinced the Sierra Club to sign on to its plan — with certain provisos.
On Thursday, the Office of the Ohio Consumers’ Counsel and the Appalachian Peace & Justice Network jointly filed a memorandum urging PUCO to deny AEP’s request to change its “electric security plan” (ESP).
“Even though AEP Ohio appears to have shuttled its plans for an affiliate PPA, in light of FERC’s rulings, it nonetheless has come up with another way to extract money from customers,” the two organizations wrote. They said AEP Ohio’s idea to seek a PPA covering only the OVEC portion of its generating fleet was already denied once by PUCO in a 2015 decision. “There is no reason to stray from that decision,” they wrote. PUCO at that time, they said, ruled that a OVEC-only PPA rider “would not provide a sufficiently beneficial financial hedge, or other commensurate benefits, to AEP Ohio’s customers to justify approval.”
“The PUCO should also consider that when AEP Ohio negotiated the OVEC contract, it agreed to an allocation of risk regarding Capacity Performance penalties and bonuses,” the groups argued. “The PUCO should not undo the deal that AEP Ohio itself struck by bailing it out from the agreed-to risk allocation and imposing the risk on customers.”
The groups also argue that PUCO’s rules don’t allow AEP Ohio to modify the ESP. It only allows it to accept PUCO’s modifications or withdraw and terminate its entire request, they said.
P3 and the Electric Power Supply Association also argued that AEP’s rehearing request and “rehashed proposal” should be denied, also noting PUCO’s 2015 ruling.
“With the affiliate PPA removed from the PPA rider, AEP Ohio is left with only its OVEC entitlement — a construct this commission expressly rejected in 2015,” they wrote. “The commission should deny AEP Ohio’s application for rehearing, reverse its approval of the stipulation and terminate this hearing.”
The Mid-Atlantic Renewable Energy Coalition filed a memo supporting AEP’s rehearing request, saying it is necessary to “preserve the significant public policy benefits” of the original renewable energy agreements.
FERC late Tuesday rejected multiple rehearing requests on PJM’s Capacity Performance rules, but ordered the RTO to revise Tariff language regarding auction revenue rights and clarify language on several other issues, including risk premiums and “nonphysical” constraints.
The ruling, on the eve of PJM’s Base Residual Auction Wednesday, granted only one rehearing request, ordering the RTO to change its force majeure rules regarding load-serving entities’ ARRs (ER15-623, EL15-29, EL15-41).
The commission rescinded its approval of Tariff language allowing the RTO to deny financial transmission rights awards for an “unanticipated event outside the control of PJM.” The commission had agreed that PJM should have some discretion in determining when to relax a binding constraint in allocating FTRs. (FTRs can be purchased or converted from ARRs, which are allocated to network and firm point-to-point customers.)
American Municipal Power, Old Dominion Electric Cooperative and Southern Maryland Electric Cooperative complained that the change could affect LSEs’ shares of stage 1A ARRs and thus their abilities to hedge transmission costs.
The complainants said the language was different from PJM’s other force majeure changes because it applied to PJM’s obligations to LSEs rather than market participants’ performance obligations.
They argued the revised Tariff lacked any limits on PJM’s exercise of its discretion. In most cases, they added, FTR allocations will have already been made or be underway before PJM makes its decisions, leaving them facing “the prospect of an unlikely post-settlement remedy.”
FERC agreed.
“Upon further consideration, we agree that PJM has not adequately explained why its existing rules are unjust and unreasonable regarding its duties to load-serving entities as they relate to the allocation of ARRs and FTRs,” it said, ordering the RTO to reinstate “its prior just and reasonable” Tariff language.
Nonperformance Charges
The commission also required several revisions to PJM’s July 29, 2015, compliance filing in response to FERC’s June 9 order conditionally approving Capacity Performance. (See FERC OKs PJM Capacity Performance: What You Need to Know.)
One required change concerns whether a capacity resource will be subject to nonperformance charges if PJM does not schedule it solely because of operating parameter limitations in the resource’s offer.
FERC said a literal reading of the Tariff suggests that a provision exempting resources from the nonperformance charge if the resource is not scheduled through PJM’s security-constrained economic dispatch takes precedence — meaning a resource’s undelivered megawatts would not be counted as a performance shortfall even if it would otherwise be needed.
“This outcome is inconsistent with the commission’s finding in the Capacity Performance order,” it said.
It directed PJM to revise the Tariff “to make clear that, notwithstanding PJM’s determination that a scheduling action was appropriate to the security-constrained economic dispatch of the PJM region, any undelivered megawatts will be counted as a performance shortfall if such megawatts otherwise would be needed but for an operating parameter limitation specified in the market seller’s energy offer.”
Fixed Resource Requirement Phase-in
The commission also found fault with PJM’s proposal to apply the Capacity Performance rules to all fixed resource requirement (FRR) entities beginning with the 2019-20 delivery year.
FERC said the proposal to apply Capacity Performance rules to FRR entities with no ongoing five-year election commitment beginning with delivery year 2020/21 was “reasonable in concept.”
But it said its intent was that the rules would not apply to an entity that was within its initial five-year FRR commitment period when the CP order was issued, meaning an entity that first elected to use the FRR option for delivery year 2015/16 would not become subject to the rules until delivery year 2020/21.
“PJM’s proposed compliance to apply the Capacity Performance requirements to all fixed resource requirement entities beginning with the 2019/20 delivery year is therefore not consistent with the commission’s intent,” it said.
Quantifiable Risk
NRG Energy, Dynegy, Public Service Enterprise Group, the PJM Power Providers Group and the Independent Market Monitor won their requests for clarification of Tariff language regarding “quantifiable risks” of becoming a capacity resource.
The commission said it disagreed with complaints that PJM’s language narrowed sellers’ ability to include quantifiable, reasonably supported risks in their offers.
But it required the RTO to clarify that the method it described for justifying such risks was not all-inclusive “and that a capacity market seller may use other methods or forms of support for a risk premium to meet the ‘reasonably supported’ threshold.”
“The risk that market sellers face from becoming capacity resources under the new capacity market construct requires a complex calculation that depends on the company-specific nature of valuing performance risk,” the commission said.
PJM had said a risk would be considered reasonably supported “if it is based on actuarial practices generally used by the industry to model or value risk and … used by the capacity market seller to model or value risk in other aspects of the capacity market seller’s business.”
Nonphysical Constraints
FERC also said PJM went too far in requiring that gas generators seeking to qualify for consideration of “legitimate, constraints unrelated to the characteristics of the unit” — which PJM calls nonphysical constraints — must obtain the most flexible gas pipeline transportation contract.
The commission said PJM’s filing went beyond the scope of its compliance directive requiring the RTO to allow parameter limitations for operational constraints.
“PJM’s proposal also is unclear since operational constraints imposed by a gas pipeline may have little relationship to the underlying flexibility of a transportation contract, but are related to pipeline operational characteristics, and cannot be eliminated by contract term or service choice,” the commission said.
“Furthermore, we find that provision unduly discriminatory as it establishes a prerequisite applicable only to gas generators. We also agree with protesters that the language is vague and would require PJM to exercise significant discretion in determining whether a generator has obtained the most flexible contract available.”
It ordered the RTO to remove the offending language from its Operating Agreement and Tariff and to “make explicit that the revisions here do not preclude resources other than natural gas generators from establishing legitimate, nonphysical constraints.”
Bay Again Dissents
Chairman Norman Bay, who voted against the original Capacity Performance order, also opposed the latest ruling, issuing an 11-page dissent reiterating his position that the construct’s “multi-billion-dollar cost to consumers exceeds the benefits.”
“Furthermore, and equally important, the market design itself is flawed. Compensation for capacity resources is so generous, and the penalties for nonperformance are so weak, that resources can profit even if they are unable to perform when they are most needed, thereby undercutting the very purpose of the program,” he said.
