MISO has FERC’s permission to end a system support resource agreement in Michigan’s Upper Peninsula effective Nov. 26 (ER16-2528).
The order allows a transmission reconfiguration plan from American Transmission Co. to take the place of the White Pine Electric Power SSR agreement, which has cost local ratepayers about $6 million per year.
FERC’s decision cuts off revenue to the utility’s 20-MW coal-fired unit, which had been operating under the SSR designation since mid-2014. Under ATC’s plan, the transmission network in the western Upper Peninsula will be split into two separate load pockets. (See MISO Will Use ATC Plan to End Upper Peninsula SSR.) The dual, radial-fed configuration would only be used during planned maintenance on the area’s two 138-kV transmission lines.
Map shows ATC’s transmission system in the western Upper Peninsula. Orange circles indicate how the load pocket will be split into two radially-fed areas. White Pine Unit 1’s location circled in blue. | MISO
Some MISO stakeholders argue that the plan introduces an increased risk of consequential load loss following a subsequent contingency, but the RTO maintains the risk is within NERC standards.
The Michigan Public Service Commission noted that while White Pine Unit 1 was called on only a “handful” times during its SSR agreement, it was entitled to receive about $4.7 million in 2014-2015, $7.3 million in 2015-2016 and $6.6 million in 2016-2017. The PSC also asked FERC to take the high poverty rates of Upper Peninsula ratepayers into consideration.
In a protest, White Pine accused MISO of a “hurried” reliability analysis that did not adequately study the possible “adverse reliability impacts” of severing the SSR agreement. The utility argued that Unit 1’s retirement would lead to more load curtailment, overloads in summer peak conditions and risk of voltage collapse. White Pine also said the SSR termination was not properly discussed in stakeholder meetings.
FERC rejected White Pine’s protest. It said it found “MISO appropriately studied and determined that the ATC transmission reconfiguration plan is a feasible alternative to the second revised White Pine SSR agreement and adequately involved stakeholders in that determination.”
BOSTON — Quebec hydropower already supplies about 12% of New England’s electricity and its exports are expected to grow considerably over the next decade. So there was plenty to talk about at the 24th U.S./Canada Energy Trade & Technology Conference last week.
The Massachusetts Energy Diversity Law, passed over the summer, commits the state to acquire 9,450 GWh of new large-scale hydropower contracts annually by 2027 — a 73% increase from the nearly 13,000 GWh that ISO-NE imported from Quebec in 2015.
“For the first time, the Commonwealth of Massachusetts is designating large-scale hydropower, like the kind we generate in Quebec, as a source of clean energy that can help meet the objectives of the Global Warming Solutions Act,” Hydro-Quebec CEO Eric Martel said during a keynote speech. That law commits Massachusetts to a 25% reduction in greenhouse gases by 2020.
Matt Beaton, Massachusetts’ Secretary of Energy and Environmental Affairs, said expanded imports will both reduce emissions and help maintain system reliability.
“We have always looked kindly on the import of hydroelectricity and recognize that it is one of the few resources that help us reach all three of the targets we are trying to accomplish: It’s a reliable resource, it’s affordable and it’s one that helps us meet our climate goals,” he said.
Entergy’s decision to close the 680-MW Pilgrim nuclear plant in 2019 is a major setback for the state’s climate goals, said David O’Connor, senior vice president for energy and clean technologies at ML Strategies.
“The Pilgrim nuclear plant by itself produces 85% of the [carbon-free] energy consumed in Massachusetts,” O’Connor said. “When it goes away, there’s going to be a dramatic alteration of the carbon profile in the state.”
Ed Krapels, CEO of transmission developer Anbaric, is looking at what he called the Greater Northeast — including New England, New York, Quebec and Ontario — where a massive buildout of renewable generation is needed to achieve climate reduction targets.
“For us, we look at this as a 5,000- to 10,000-MW transition, so there’s room in that for many different things. Distributed energy will be a large part of that, as well as batteries, solar microgrids, all of that will have a big impact. But we still have bulk power needs,” he said.
Anbaric is proposing stand-alone transmission development, as well as collaborations with wind generators to pair with hydropower in cross-border projects throughout New York and New England.
Marcy Reed, president of National Grid Massachusetts, joked that although she heads an electric utility, she spends most of her time talking about natural gas.
“You talk about a balanced approach. We need pretty much everything. We need renewables, we need efficiency, energy storage, natural gas; we need a full platter of solutions to get us where we ultimately need to be,” she said.
Natural gas analyst Richard Levitan said the failure of pipeline projects to overcome litigation and community opposition leaves the system vulnerable in the winter, when gas generation must compete with gas heating for fuel supplies.
ISO-NE has incentivized generators to provide dual-fuel power sources, but that fails to solve the underlying problems, he said.
“The Winter Reliability Program is chipping away at a fundamental problem of the region’s great reliance and growing reliance on natural gas,” he said. “Is it enough? Well, this winter it probably is enough, if ISO-NE’s 50-50 load forecast materializes. And that the pipeline and storage infrastructure linking us to the Marcellus region is fully available and nothing bends or breaks.”
Over the longer term, the addition of solar and wind resources presents serious challenges that are only now starting to be addressed, said Peter Rothstein, president of the Northeast Clean Energy Council.
Rothstein said the modernized grid that’s needed to enable renewable integration and two-way power flows must join the conversation along with cleaner generation.
“We can deploy a great amount of solar resources over the next five or 10 or 15 years, but we’re going to hit a wall and it’s going to become inefficient and not at all cost-effective, so we have to modernize the grid,” Rothstein added.
Election Talk
The election of Donald Trump as president creates much uncertainty, many speakers said. But they agreed that clean energy will likely lose federal support and climate issues will be confronting a hostile federal administration.
“If you look at the election, it’s easy to get discouraged because we need a lot of policy support, and it’s not going to be there,” said Joshua Paradise of Current, GE’s LED, solar, energy storage and electric vehicle business. “But as a skeptic [of conventional wisdom] as I think of what’s happened, this train [of strong support from the states and the public] has left the station. … We’re already at the tipping point.”
Jon Norman, vice president of business development for Quebec-based Brookfield Renewable, was a bit more circumspect. He said he feared climate change deniers becoming more entrenched in government under Trump.
“It’s unquestionable that the need for state action is far more urgent than it was [before the election]. And that need for action has to happen and I don’t think we can delay it until we have all the right answers [on technology]. But I’m optimistic, especially in New England because you have states with very aggressive targets and they’re taking actions to implement them.”
What appears likely is that the federal governments of the U.S. and Canada will take divergent paths on global climate initiatives. Former Prime Minister Stephen Harper was aligned with fossil fuel interests and was hostile to international climate accords, said Monica Gattinger, director of the Institute for Science, Society and Policy at the University of Ottawa.
Prime Minister Justin Trudeau “has taken a very balanced approach to energy. On fossil fuels, [Trudeau’s Liberal Party] is quietly supportive. They’re visibly supportive of clean renewable energy,” she said. “When it comes to the environment, from a bragging perspective, they wanted everyone to know Canada was back in Paris last year [for the 21st Conference of Parties’ climate agreement], and with a commitment to moving on a carbon tax.”
FERC on Thursday approved a rate settlement for a transmission project that may never happen.
The agreement settled a dispute over how much profit LS Power’s Northeast Transmission Development should receive for building transmission infrastructure across the Delaware River to address stability issues at New Jersey’s Artificial Island (ER16-453).
It was brokered between Northeast Transmission and several objectors in the case: Delaware Public Service Commission, American Municipal Power, Old Dominion Electric Cooperative and Delaware Municipal Electric Corporation.
However, the decision may be moot. Following complaints over cost allocation and a near doubling of the estimated cost, PJM suspended the project — PJM’s first Order 1000 competitive solicitation — pending a “comprehensive” staff analysis to be completed by February. (See PJM Board Halts Artificial Island Project, Orders Staff Analysis.)
The settlement includes a base return on equity, an equity cap and a three-year moratorium on any involved party petitioning for modifications to the deal:
Northeast Transmission’s base ROE will be 9.85%, retroactive to February 1.
A hypothetical capital structure of 50% equity/50% debt approved in an order issued by FERC in April will remain effective until PJM assumes control of the project.
The equity component used by Northeast Transmission to calculate its weighted average cost of capital will be the lesser of 54.75% and the actual ratio of equity as a percentage of total capital.
The moratorium is in effect until three years after PJM takes control of the project. It includes prohibitions on making Federal Power Act Section 205 or 206 filings or supporting others’ filings. Northeast Transmission also is barred from petitioning to include construction work in progress in its rate base.
Artificial Island is the site of three nuclear power plants owned by Public Service Enterprise Group. The proposed project would address stability issues that prevent PSEG’s Hope Creek and Salem 1 and 2 units from maximum generation. It would include a 230-kV line from the existing Salem substation in Lower Alloways Creek on the New Jersey side to a newly constructed Silver Run 230-kV substation in Delaware. The Delaware substation would connect the project with the existing Red Lion – Cartanza and Red Lion – Cedar Creek 230-kV transmission lines.
VALLEY FORGE, Pa. — PJM’s efforts to hammer through manual revisions ahead of FERC action on fuel-cost policies were stymied at last week’s Markets and Reliability Committee meeting.
Despite PJM’s desire to implement the changes as soon as FERC approves PJM’s hourly offers compliance filing, stakeholders shrugged off the urgency and insisted on perfecting the language.
The revisions to Manual 15 were approved by the Market Implementation Committee on Nov. 2 following months of debate. At the MRC meeting, stakeholders said there are still unresolved issues with how the changes are worded. Of particular concern at last week’s meeting was the requirement that generators “immediately” replace a revoked policy. (See “Fuel-Cost Policy Revisions Approved,” PJM Market Implementation Committee Briefs.)
“It makes it sound like we need to be at the ready every day” with a new policy, said Steve Lieberman of Old Dominion Electric Cooperative. “I think everyone here would agree it’s a bit of a challenge to get one approved initially.”
PJM’s Jeff Schmidt responded that the intent is that generators should already have a policy approved, but stakeholders were not swayed.
“We do need to make some change to address that ‘immediately’ business,” American Municipal Power’s Ed Tatum said. “When things get going, people refer to the governing language.”
Catherine Tyler Mooney of Monitoring Analytics, PJM’s Independent Market Monitor, reiterated concerns that “confusing language” is creating “a problematic process.”
“The proposed M15 language creates a PJM fuel-cost policy review that overlaps the timing and scope of the Market Monitor’s independent review. There’s a potential where we have a PJM-approved version of a fuel policy that can’t be accepted by the Market Monitor,” she said.
Schmidt said PJM continues to bring the revisions forward because it will have 45 days after FERC’s approval to implement the rules, which might not be enough time to secure all the committee endorsements. Several stakeholders acknowledged this concern, including Bob O’Connell of PPGI Fund A/B Development, who said continuing to put off the vote might put stakeholders in the position of having to make changes within an unattainable deadline.
PJM’s Suzanne Daugherty, who chairs the MRC, said the committee can convene over the phone for a single-issue conference call if it becomes necessary to send an advisory vote to the board prior to the January MRC. The revisions will be returned to December’s Market Implementation Committee meeting to address the wording issues.
Citigroup Wins Change on Capacity Resales
Citigroup Energy’s Barry Trayers sparred with PJM’s Stu Bresler over Trayers’ proposed revisions to Manual 18, but Trayers’ changes were endorsed without PJM’s additions.
Trayers’ manual change eliminates PJM rules for how “early replacement” of capacity obligations can be made. He noted that the rules’ deadline of Nov. 30 for performing replacement transactions isn’t supported by language in the Tariff.
Bresler, PJM’s senior vice president of operations and markets, had proposed language changes that Trayers had originally accepted as a “friendly amendment.” However, he rescinded that approval at the MRC, saying he had received advice that the amendment strayed from his intent. That meant Bresler’s amendment would only be considered if Trayers’ original proposal failed.
At issue is how quickly capacity sold during the Base Residual Auction can be replaced through Incremental Auctions. Trayers said the change allows him to reconcile his books much sooner. Bresler said it widens a loophole that allows participants to arbitrage price differences between the Base and Incremental Auctions by reselling the replaced capacity.
Both Bresler and the Independent Market Monitor said they preferred the status quo over Trayers’ motion. Because Trayers’ proposal was approved, PJM’s amendment was never considered.
DASR Approved Despite Slight Change
The proposed day-ahead scheduling reserve for 2017 was approved despite being “slightly different” than what PJM outlined to the Operating Committee earlier this month, said PJM’s Tom Hauske. The change came because not all performance information had been collected at the time. The approved figure was 0.04 percentage points less than originally proposed, from 5.52% to 5.48%.
| PJM
Manual 35 Retired; PJM Promises Further Consolidation of Definitions
Members endorsed retiring Manual 35: Definitions and Acronyms but only after confirming that a document consolidating all definitions will be developed.
PJM said Manual 35 hasn’t been properly maintained in years, raising the risk of legal disputes over members using incorrect and outdated definitions. Going forward, the legal definitions will be maintained in a single section within the Tariff, Operating Agreement and Reliability Assurance Agreement.
Only informal definitions — “layman’s terms,” as PJM’s Janell Fabiano called them — will be included in the glossary on PJM’s website. Staff deleted more than 400 outdated terms from the glossary and added an expanded disclaimer noting that it is for reference, and that the formal definitions in the governing documents are legally binding.
Fabiano said RTO officials will discuss creating a consolidated legal definitions document at a Dec. 2 meeting of the Governing Document Enhancement & Clarification Subcommittee.
Venue for DER Discussions to Change
PJM’s Dave Anders said the special MRC meetings on distributed energy resources have gone into stasis while two key issues get hashed out elsewhere.
The Planning Committee is continuing work begun in August on an alternate queue process and the allocation of upgrade costs less than $5 million while discussions on potential market rule changes will be conducted in special sessions of the MIC.
The venue of future discussions will be determined by how resources plan to connect. “You have to make a choice: You have to be in front of the meter or behind it,” Anders said.
Resources that plan to be in front of the meter will follow the process being developed by the PC to secure capacity injection rights. Behind-the-meter resources, which can both reduce load and inject power, will be governed by the process developed through the MIC. The special MRC sessions will reconvene as necessary once those routes are finalized.
MRC Endorses Manual Changes
Members also unanimously approved the following manual changes:
Manual 3: Transmission Operations. Revisions, the result of a periodic review, include updating voltage control at nuclear stations, certain special protection scheme references and the BC/PEPCO operating procedure.
Manual 18B: Energy Efficiency Measurement & Verification. Revisions, the result of a periodic review, include updates to incorporate the implementation of Capacity Performance.
Manual 28: Operating Agreement Accounting. Revisions made to align with recent Manual 1 revisions. It clarifies metering language and defines a “fully metered EDC.”
Members Committee
Guerry Applauded at Final MC
In her final act as the chair of the Members Committee, EnerNOC’s Katie Guerry gave an emotional farewell, saying the two-year position “has been a wonderful thing that happened in my life.”
PJM CEO Andy Ott sat between her and Susan Bruce of the PJM Industrial Customer Coalition, who will transition from vice chair to chair in January. “I’m flanked by two very accomplished women,” Ott said, before reviewing the major issues Guerry presided over during her time in office. “Through all of that, I think you’ve done a fantastic job,” he said.
Ott presented her with a ceremonial gavel, and they shared a laugh about the inscription. He explained that it hadn’t been updated yet and still read “chairman’s gavel” as it did when she first took the position.
Guerry wasn’t fazed. “I only wanted the girls’ version if it was encrusted with diamonds,” she explained.
Elections
The Members Committee elected the designated slate of candidates to fill expired and vacated positions. O’Connell quickly cut off any potential for additional nominations by making a motion, which was seconded by Dan Griffiths of the Consumer Advocates of PJM States. The candidates were approved by acclamation.
Elected were:
American Municipal Power’s Chris Norton, Dynegy’s Jason Cox and Calpine’s David “Scarp” Scarpignato to the Finance Committee.
Lieberman, Bruce, Guerry, Gabel Associates’ Michael Borgatti and Public Service Enterprise Group’s Jodi Moskowitz as sector whips.
Borgatti as the Members Committee’s new vice chair.
| PJM
Preview of Security Committee Receives Tepid Response
PJM Chief Information Officer Tom O’Brien introduced plans for a new, non-decisional Security and Resiliency Committee. O’Brien said members of the public and the media will be barred from the sessions so that members can openly discuss sensitive security issues and potential solutions. External government and private sector attendees will be allowed by invitation only.
“It’s cutting across more than control systems,” O’Brien said. “It’s cutting into the Internet of Things.”
Jason Barker of Exelon said it’s an initiative his company sees as “a duplicative effort” it “struggles to support” because it “taxes limited resources that could be addressing concerns instead of attending another meeting.”
“The objectives are very broad. We struggle with how they’d be roped into something that is administratively efficient for us to staff and attend,” he said. “We don’t see where the topics you’ve just described are PJM-specific. … We see this as another place where we have to drag the same people who are having the same discussions elsewhere.”
To be truly non-decisional, he said, the charter’s key work activities would need to be modified to eliminate creating subcommittees or delegating assignments.
O’Brien said the point is “very well taken” about staffing. “That’s kind of how we got to where we are. The key is to have discipline around who staffs what,” he said.
VALLEY FORGE, Pa. — PJM’s Markets and Reliability Committee on Thursday rejected two proposals members said threatened the Capacity Performance construct, but it approved two others that would investigate potential changes in the rules.
A proposal to change rules on penalties for underperformance failed in a sector-weighted vote with 47.6% support, well below the two-thirds threshold. Nearly three-quarters of the Generation Owners sector supported the proposal, but other sectors were split or strongly opposed.
The proposal would have changed the nonperformance assessment charge rate and ownership requirements for making retroactive replacement transactions. It also would have introduced a way to offset underperformance with overperformance and a new monthly stop-loss provision while changing the annual stop-loss rule.
Reduced Incentives
Opponents said the changes reduced incentives for generators to meet their commitments.
Because prices in PJM’s Base Residual Auction are much higher than those for incremental auctions in which the RTO sells excess capacity, load has recognized little savings for the reliability benefits it has forgone. | PJM
“Every one of these proposals is designed to undermine those incentives,” said Howard Haas of Monitoring Analytics, PJM’s Independent Market Monitor.
PJM’s Stu Bresler also voiced concerns with the proposal and said the RTO couldn’t support it.
A proposal to extend Base Capacity another year through the 2020/21 Base Residual Auction in May fared better but also fell short in a sector-weighted vote, receiving 58.6% in favor.
Direct Energy’s Jeff Whitehead presented the proposal as a stop-gap to allow seasonal resources to continue participating in the market pending a FERC ruling on PJM’s plan to make it easier for them to qualify as CP.
The proposal had near-unanimous support from the Electric Distributor and End Use Customer sectors but was opposed by most Generation Owners and Transmission Owners.
PJM Filing
PJM filed its plan with FERC on Wednesday, requesting a Jan. 19 implementation date to ensure the new rules are in effect for the BRA on May 10 (ER17-367). It would make it easier for summer- and winter-only resources to aggregate for the year-round deliverability required under CP. (See No End in Sight for PJM Capacity Market Changes.)
Stakeholders said extending Base Capacity would impede the full implementation of CP. Both PJM and the Monitor rejected Whitehead’s proposal, but they said they were open to further discussion on how to incorporate seasonal resources.
Brock Ondayko of American Electric Power said those who supported the Base Capacity proposal but not the proposal to relax underperformance penalties were being “disingenuous” and called the extension “poor irony” because it creates competition to CP offers.
“There’s no such thing as Base Capacity in the year 2021, so this is essentially a new product that will take away from the existing products,” he said.
Exelon’s Jason Barker opposed the proposal, saying his company is “eager” to see if CP reforms are effective.
Talking Past Each Other
Dan Griffiths of the Consumer Advocates of the PJM States immediately responded, saying stakeholders “continue to talk past each other” based on differing perspectives on CP. He portrayed his ongoing back-and-forth with Barker on the topic as one holding a sign that read “A” and the other holding one that says “Not A.”
“I don’t see how this reduces the incentives for performance,” he said.
Following his proposal’s failure, Whitehead retained the floor to propose a problem statement and issue charge on how PJM should offer back excess capacity purchases in the incremental auctions that balance out supply and demand in the run up to a delivery year.
“If you didn’t like that last one, maybe you’ll like this one,” he said.
He was right: Stakeholders eventually approved them by acclamation with objection only from Calpine’s David “Scarp” Scarpignato.
Scarp initially appeared supportive, but he backed off when stakeholders demanded additional language in the issue charge that limited its scope to the auction’s structure and PJM’s actions only when it is a capacity seller.
Later in the meeting, stakeholders also approved by acclamation a problem statement and issue charge on investigating adequacy and capacity requirements for winter-season resources. The proposal passed despite 10 objections and four abstentions. It was presented by economist James Wilson on behalf of the Maryland Office of People’s Counsel, the New Jersey Division of Rate Counsel and the Delaware Division of the Public Advocate.
In a rulemaking reflecting both reliability concerns and the technological advances of renewable generators, FERC on Thursday proposed revising the pro forma Large Generator Interconnection Agreement (LGIA) and Small Generator Interconnection Agreement (SGIA) to require all newly interconnecting facilities to install and enable primary frequency response capability (RM16-6).
The commission said the existing pro forma LGIA may be unduly discriminatory because its primary frequency response requirements apply only to synchronous generating facilities “and do not account for recent technological advancements that have enabled new non-synchronous generating facilities to now have primary frequency response capabilities.”
The proposed changes will “ensure fair and consistent treatment for all types of generating facilities, help balancing authorities meet their frequency response obligations pursuant to NERC reliability standard BAL-003-1.1 and help improve reliability during system restoration and islanding situations,” the commission said.
FERC said the rules would not apply to nuclear generators and would not impose “headroom” requirements for new generators. The commission said it would not require that generators be paid for complying with the frequency response requirement.
Declining Frequency Response
Acknowledging concerns over declining frequency response performance, the commission asked for comment on whether the Notice of Proposed Rulemaking is sufficient “to ensure adequate levels of primary frequency response, or whether additional reforms are needed.”
“While the three [contiguous] U.S. interconnections currently exhibit adequate frequency response performance above their interconnection frequency response obligations, there has been a significant decline in the frequency response performance of the Western and Eastern Interconnections,” FERC said.
The commission noted declining frequency response was identified as early as a 1991 study by NERC and the Electric Power Research Institute.
It also cited a 2010 NERC survey of generator owners and operators that found that only 30% of generators in the Eastern Interconnection provided primary frequency response and that only 10% provided sustained primary frequency response. “This suggests that many generators within the interconnection disable or otherwise set their governors or outer-loop controls such that they provide little to no primary frequency response,” the commission said.
“The commission’s pro forma generator interconnection agreements and procedures were developed at a time when traditional synchronous generating facilities with standard governor controls and large rotational inertia were the predominant sources of electricity generation. However, the nation’s resource mix has undergone significant change since” the pro forma rules were issued in 2003 and 2005.
“This transformation has been characterized by the retirement of baseload, synchronous generating facilities and the integration of more distributed generation, demand response and natural gas generating facilities, and the rapid expansion of non-synchronous variable energy resources (VERs) such as wind and solar,” the commission said.
It cited U.S. Energy Information Administration data that the U.S. added 13 GW of wind, 6.2 GW of utility-scale solar photovoltaic and 3.6 GW of distributed solar PV generation in 2014 and 2015. “Conversely, NERC has reported that almost 42 GW of synchronous generating facilities (e.g., coal, nuclear and natural gas) have retired between 2011 and 2014, and the EIA recently reported that nearly 14 GW of coal and 3 GW of natural gas generating facilities retired in 2015.”
The commission said that although wind and solar generators now have the technology to provide primary frequency response, “this functionality has not historically been a standard feature that was included and enabled on non-synchronous generating facilities. Moreover, wind and solar generating facilities typically operate at their maximum operating output, leaving no capacity (or ‘headroom’) to provide primary frequency response during under-frequency conditions.”
RTO Rule Changes
The commission acknowledged it was playing catch up with RTOs that have already begun changing the rules for asynchronous generators:
ISO-NE and NYISO have adopted provisions to their LGIAs that establish more specific requirements for governor operation.
PJM has implemented governor requirements for non-nuclear generators and required new non-synchronous generators to have “enhanced inverters” allowing the provision of primary frequency response. (See Enhanced Inverters Clear MRC.)
MISO requires governor operation as a condition for providing regulating reserves but does not require specific settings.
The commission recently accepted CAISO Tariff rules on governor settings and provisions for sustained primary frequency response.
In a big boost to the energy storage industry, FERC on Thursday proposed a sweeping order aimed at knocking down market barriers to storage and distributed energy resources.
The Notice of Proposed Rulemaking would require RTOs to allow aggregated distributed energy resources and storage resources of 100 kW and above to participate in capacity, energy and ancillary services markets. It also would allow storage to provide services not procured through markets, such as black start, primary frequency response and reactive power (RM16-23, AD16-20).
Myersdale PA Energy Storage | NextEra
“As the costs of electric storage resources continue to decline and their technical potential expands, the ability of these resources to provide operational and economic benefits to the organized wholesale electric markets will increase,” the commission said. “We preliminarily find that it is important to remove barriers to participation now so that the competitive benefits are realized without delay.”
In a separate order, the commission also issued a NOPR proposing to require all newly interconnecting large and small generating facilities to install and enable primary frequency response — a requirement new to renewable generators (RM16-6). (See related story, FERC Proposes Frequency Response Requirements for Renewables.)
FERC’s Heard Enough
In the rhythm of FERC rulemaking, staff-led technical conferences are part of a process that is followed by post-conference comments and months of deliberation before the issuance of a NOPR.
Not so with the commission’s deliberations on RTOs’ rules on energy storage and DERs.
Thursday’s NOPR came only eight days after a daylong technical conference at which representatives of RTOs, utilities and technology companies debated the breadth of storage’s potential uses and ways to avoid overcompensating resources performing multiple functions (AD16-25). (See FERC Panelists Debate Storage Uses, Compensation.)
It’s now apparent that FERC had already heard enough even before convening the conference. The 139-page NOPR was likely the result of months of internal debate and negotiations.
In April, the commission issued data requests to the six jurisdictional RTOs and ISOs seeking information on their rules on storage and DER participation. The RTOs’ responses were followed by dozens of comments from other stakeholders.
“As numerous commenters state, existing RTO/ISO rules that govern participation of electric storage resources in some organized wholesale electric markets fail to ensure that electric storage resources that are technically capable of providing specific services are permitted to do so,” the commission said Thursday.
FERC said outdated and inflexible market rules have hampered innovation. “For instance, some electric storage resources have chosen to participate as demand response resources simply because, absent other participation models, that is the participation model that more closely resembles the manner in which electric storage resources might participate in the organized wholesale electric markets.”
‘Participatory Model’
The NOPR would require RTOs to revise their rules to create a “participation model” that accommodates “the physical and operational characteristics” of storage to allow them to provide any services they are physically capable of.
Gridbank Energy Storage | Alevo
“Where compensation for these services exists, electric storage resources should also receive such compensation commensurate with the service provided,” the commission added.
One key change would be the requirement that RTOs’ bidding parameters reflect storage’s unique characteristics, including allowing storage to de-rate its capacity to meet minimum run-time requirements to provide capacity or other services.
In addition, RTO criteria for qualifying storage resources “must not limit participation to any particular type of electric storage resource or other technology,” FERC said.
“For example, resources such as thermal storage that can both increase and decrease their energy consumption could aggregate with other distributed energy resources with common physical or operational characteristics and qualify as a market participant using the participation model proposed here.”
In addition to batteries, the commission said the rules also must accommodate “flywheels, compressed air [and] pumped hydro … whether located on the interstate grid or on a distribution system.”
State-of-Charge
The commission said bidding parameters must take into account storage’s state-of-charge to ensure resources are dispatched in a way that maximizes their operational effectiveness.
AES Laurel Mountain in Elkins, W.Va. | AES
“While some existing bidding parameters were developed for older electric storage technologies (such as pumped hydro facilities), newer storage technologies (such as battery storage) have greater flexibility to transition between charging and discharging. Therefore, bidding parameters designed for slower storage technologies or other types of generation resources that are not capable of charging and discharging energy may limit the opportunity for faster electric storage resources to participate in the organized wholesale electric markets.”
For RTOs with capacity markets, the commission proposed that the de-rated capacity value for electric storage “be consistent with the quantity of energy that must be offered into the day-ahead energy market for resources with capacity obligations.”
The commission said storage’s participation also should not be barred by requirements, designed for synchronous generators, that the resource be online and synchronized to the grid to be eligible to provide ancillary services.
“Newer technologies, particularly electric storage resources, tend to be capable of faster start-up times and higher ramp rates than traditional synchronous generators and are therefore able to provide ramping, spinning and regulating reserve services without already being online and running,” the commission said. “Therefore, we preliminarily find that participation in ancillary service markets should be based on a resource’s ability to provide services when it is called upon rather than on the real-time operating status of the resource.”
Energy Schedules
But the commission acknowledged that because RTOs co-optimize energy and ancillary services dispatch and pricing, they may require ancillary services providers to have an energy schedule. “As a result, it is not clear whether eliminating the requirement for a resource to be online and synchronized to the grid would be impactful given the continued need to have an energy schedule,” it said, asking for comment on whether the requirement for energy schedules could be relaxed.
“Specifically, we seek comment on whether dispatch and pricing of energy and ancillary services would continue to be internally consistent if a resource were not required to offer to provide energy in order to offer to provide ancillary services.”
Size
The NOPR says that the RTOs’ minimum size requirement for participation in the markets should be no more than 100 kW, a threshold the commission said “balances the benefits of increased competition with the ability of RTO/ISO market clearing software to effectively model and dispatch smaller resources often located on the distribution system.”
The limit would apply to any minimum capacity requirements, minimum offer requirements and minimum bid requirements.
Pricing
The NOPR proposes that the energy that storage resources purchases from RTO markets and then resells back to those markets must be at the wholesale LMP. It also said storage should be permitted to set LMPs both as buyers and sellers.
“This proposal includes the requirements that the RTOs/ISOs accept wholesale bids from electric storage resources to buy energy so that the economic preferences of the electric storage resources are fully integrated into the market, the electric storage resource can set the price as a load resource where market rules allow and the electric storage resource can be available to the RTO/ISO as a dispatchable demand asset. However, we note that these requirements must not prohibit electric storage resources from participating in organized wholesale electric markets as price takers, consistent with the existing rules for self-scheduled load resources.”
Smaller DER
The NOPR also acknowledged the expected growth of DER in requiring RTOs to “remove any unnecessary limitations on how the distributed energy resources that participate in such aggregations must be operated.”
“It is clear from the comments that the ability to meaningfully participate in the organized wholesale electric markets for these smaller distributed energy resources is through aggregations,” the commission said.
Energy Storage at Grand Ridge, IL | Invenergy
“For example, combining the discharge times of multiple electric storage resources and/or combining them with distributed generation resources could allow aggregated resources to meet minimum run-time requirements that individual electric storage resources may not be able to meet.”
Under FERC’s proposal, a DER aggregator could register as a generation asset “if that is the participation model that best reflects its physical characteristics.”
The commission expressed hope that price signals will encourage DER to locate in areas where new capacity is most needed, helping reduce congestion costs during load peaks and to reducing transmission investments for delivering energy into high-priced load pockets.
“Unlike larger fossil fuel generators that often are not able to locate in load pockets due to environmental or other citing concerns, distributed energy resources are more able to co-locate with load and provide associated benefits,” the commission said. “We also believe that the shorter lead time to develop many forms of distributed energy resources compared to traditional generators or transmission lines allows them to rapidly respond to near-term generation or transmission reliability-related requirements, further improving their ability to enhance reliability and reduce system costs.”
Transaction Costs
The commission said the changes should remove the commercial and transactional barriers to DER participation in wholesale markets.
“Owners and operators of individual distributed energy resources may be reluctant to incur the significant costs of participating in the organized wholesale electric markets, such as the costs of the necessary metering, telemetry and communication equipment,” it noted.
“The smaller a resource is, the more likely the transaction costs to sell services into the organized wholesale electric markets outweigh the benefits that the prospective market participant may realize from selling wholesale services. However, some of these costs can be reduced by participating in the organized wholesale electric markets through a distributed energy resource aggregation; for example, the time and resources necessary to learn the market rules and actively submit bids and/or offers into the organized wholesale electric markets.”
FERC said integrating DERs into the markets will help RTOs account for them in calculating installed capacity requirements and day-ahead energy demand, “thereby reducing uncertainty in load forecasts and reducing the risk of over procurement of resources and the associated costs.”
LaFleur Statement
Commissioner Cheryl LaFleur issued a statement saying that DERs “will play a critical role in the future of the grid” but noting that they present “unique issues since they are connected to the grid at the distribution level.”
She called for “close coordination among the RTO/ISOs, the distribution control centers that operate the systems to which they are connected and the distributed energy resource aggregators. … This coordination could include, for example, real-time operating procedures and software-enabled communications among the control centers.”
Dayton Power & Light Energy Storage in Moraine, Ohio | AES
The commission noted that it was awaiting an informational report from CAISO, which recently began implementing rules for DER aggregations.
CAISO’s Tariff also includes participation models for Generators, Proxy Demand Resources, Reliability Demand Response Resources and Non-Generator Resources.
Comment Period
The commission will accept comments for 60 days after the NOPR is published in the Federal Register. In particular, the commission solicited comment from the RTOs on the rule and software changes that would be required to implement the new requirements as well as the associated costs and how they can be minimized.
ALBANY, N.Y. — The New York Public Service Commission on Thursday approved Entergy’s sale of the James A. FitzPatrick nuclear plant to Exelon, a transaction needed to prevent the plant’s imminent closure (16-E-0472).
A year ago, Entergy announced it would close the money-losing plant in early 2017. Exelon began negotiations in the summer to purchase the plant for $110 million, contingent on the state’s approval of a subsidy to keep the plant operating and regulators’ approval of the transaction by Nov. 18. (See FitzPatrick Sale Filed with New York Regulators.)
“It’s the next step forward on the Clean Energy Standard,” PSC Chair Audrey Zibelman said at a news conference after the meeting. “We understood this transaction would have to happen” to keep the plant running.
Having pledged to acquire 50% of the state’s electricity from renewable sources by 2030, New York officials see nuclear power as an interim carbon-free source until renewables are deployed at scale. (See New York Adopts Clean Energy Standard, Nuclear Subsidy.)
The commission found the sale in the public interest, saying there were no adverse environmental consequences, Exelon has the financial wherewithal to maintain safe operations and the acquisition would not give it undue market power.
PSC economist Warren Meyers said the transaction means Entergy and Exelon swap places as the fourth- and fifth-largest owners of generation in the state. Before the transaction, Entergy controlled 7% of New York’s fleet and Exelon had 6%. After the sale, those numbers change to 5% and 8%, respectively. Entergy owns the Indian Point nuclear plant north of New York City.
Critics of the zero-emission credit (ZEC) say the 12-year subsidy could cost ratepayers up to $7.6 billion to keep FitzPatrick and two other upstate nuclear plants open. “This is part of a larger picture and that picture is that the Public Service Commission has moved in favor of a mandatory bailout from ratepayers in the entire state,” Manna Jo Greene, Hudson River Sloop Clearwater’s environmental director, said after the meeting. “Had they not agreed on the bailout, this transaction would not have occurred.”
Zibelman acknowledged the likelihood of the plant’s closure without PSC approval, but she emphasized the environmental benefits. The state can’t afford to step back from its low-emission commitments, she said. When nuclear plants have closed in Germany and New England, carbon emissions have risen as the lost energy was replaced by fossil fuel plants, Zibelman said. (See CO2 Emissions Increase in ISO-NE.)
The ZECs have been opposed by other environmentalists and they also say the companies’ petition for FERC approval of the FitzPatrick sale needed to include information about the subsidy. (See Public Citizen Challenges NY Nuclear Subsidy, FitzPatrick Sale.) Fossil-fuel generators have also challenged it in court, saying it interferes with wholesale power markets under FERC jurisdiction. (See Federal Suit Challenges NY Nuclear Subsidies.)
Exelon spokesman Marshall Murphy declined to comment on whether the company would seek to cancel the sale if the ZECs are voided by the courts. “The company is not going to speculate on any legal outcome with respect to the Clean Energy Standard,” he said.
Besides FitzPatrick, the ZECs would be paid to Exelon’s neighboring Nine Mile Point 1 and 2 plants, and its R.E. Ginna facility to the west.
“With a number of nuclear energy plants across the country at-risk for premature closure — or having closed already — New York is a bright spot on the map when it comes to recognizing and preserving the many benefits that these plants provide,” the advocacy group Nuclear Matters said in a statement. “While we will need to review the final order in order to fully evaluate the PSC’s decision, the approval of the FitzPatrick transfer preserves a host of benefits for all New Yorkers, allowing the continued operation of a reliable producer of carbon-free energy that is also a key driver of jobs and economic growth in the state.”
The Nuclear Energy Institute also praised the vote. “By its own cost-benefit analysis, the Public Service Commission recognized that the gross benefits of keeping FitzPatrick and the other upstate plants operating in the first two years of the Clean Energy Standard program are approximately $5 billion. This is weighted against a cost of less than $1 billion and thus hugely beneficial,” NEI said in a statement.
The 882-MW plant began operating in 1975 and is licensed through 2034.
The transaction must also be approved by the U.S. Department of Justice, the Nuclear Regulatory Commission and FERC. It is expected to close in the second quarter of 2017.
Market manipulation cases dominated FERC’s enforcement efforts in fiscal year 2016, responsible for more than two-thirds of the probes launched during the year, according to the Office of Enforcement’s 10th annual Report on Enforcement, released Thursday.
The report said the office’s Division of Investigations opened 17 probes in FY 2016, some of which involved multiple subjects: 12 involved potential market manipulation, 11 included potential tariff violations and one each involved potential violations of a commission certificate order, the Standards of Conduct and a commission filing requirement.
Enforcement closed 11 investigations during the year, about half of them because of insufficient evidence and the other half resulting in settlements. One of the companies involved in settlements, Berkshire Power, also pleaded guilty to a criminal violation of the Federal Power Act — the first conviction ever in the 81 years since the law’s enactment, according to FERC.
Among the settlements, about two-thirds involved market manipulation, one-quarter involved tariff violations and the remainder involved reliability standards.
In FY 2015, by contrast, reliability standards settlements and those involving market manipulation were about even at more than 40% each, with the remainder attributed to tariff violations.
The annual report includes several other highlights:
The commission said it spent more time in federal court last year because of two challenges to FERC orders assessing penalties, continuing litigation on four cases from prior years and a commission proceeding on an administrative law judge’s initial decision finding violations of the Natural Gas Act. In all, staff sought to recover $567 million in civil penalties and $45 million in disgorgement through litigation.
Staff received 110 new self-reports from electric utilities, generators and other market participants, including almost 60 from RTO or ISOs. Including those reports submitted in prior years, staff closed 126 self-reports.
The Division of Audits and Accounting conducted 14 audits of oil pipeline, utility and natural gas companies, issuing 214 recommendations and ordering refunds and recoveries of $5.3 million. The report highlighted an audit of SPP that found problems with the independence of the RTO’s Internal Market Monitoring unit (PA15-6). (See FERC Calls for Changes to Protect SPP Market Monitoring Unit Independence.) It also singled out its audit of Duke Energy’s compliance with conditions the commission set in approving the company’s acquisition of Progress Energy (PA14-2). The audit found that Duke and its subsidiaries overstated their wholesale power and transmission customers’ revenue requirements by $17.5 million by improperly including merger transaction expenses without making a Section 205 filing showing that the costs were offset by merger-related savings. Auditors also found the company improperly included $2.4 million of lobbying costs in operating accounts.
White Papers
Enforcement also issued two staff white papers based on its 10 years of experience since Congress gave the agency stronger enforcement powers under the Energy Policy Act of 2005.
One, Anti-Market Manipulation Enforcement Efforts Ten Years After EPAct 2005, includes lessons learned in four areas: factors the commission and courts have found to be indicative of fraudulent conduct under the Anti-Manipulation Rule, adopted under Order 670; types of conduct that the commission has found to constitute market manipulation (including cross-market manipulation schemes, gaming and misrepresentations); mitigating and aggravating factors the commission considers in assessing penalties; and examples of market manipulation investigations that staff closed without action and the reasons why.
Staff said it was impossible to provide an exhaustive list of all types of manipulation, “because determining whether certain conduct constitutes manipulation is a fact-specific inquiry.”
“Market participants are increasingly sophisticated,” the report said, quoting from a ruling by the 8th U.S. Circuit Court of Appeals: The “methods and techniques of manipulation are limited only by the ingenuity of man.”
The second white paper, Effective Energy Trading Compliance Practices, is an effort to respond to market participants’ requests for more guidance on creating effective compliance programs to prevent and detect market manipulation. It includes examples of compliance practices that staff found effective and those that it found lacking.
Among the best practices cited:
Hiring compliance personnel with a variety of professional and educational experience, including legal, operations, risk management and trading.
Integrating compliance personnel into the organization’s business units (for example, locating compliance personnel on the trading floor and regularly rotating business unit employees into compliance functions).
Performing background investigations on energy traders for evidence of criminal activity, civil lawsuits, drug abuse, excessive gambling or financial problems.
Implementing compensation structures that incentivize compliance.
Implementing rules discouraging traders from using price-setting instruments such as physical natural gas or electric products to benefit open financial positions. It also recommended conducting statistical reviews of position concentrations.
Recording and retaining all trader communications for at least five years, including emails, instant messages and phone calls.
In contrast, the report says an overreliance on standardized and long annual training is ineffective. It also cautioned against relying heavily on attorneys for training rather than including operational staff. “Operational staff can help tailor compliance trainings and make them more relatable to the traders receiving the training,” the report said.
It also said companies should have ways to resolve disputes between compliance personnel and traders. “Traders should not be permitted to decide which advice to heed and which to ignore,” it said.
Illinois lawmakers on Tuesday introduced a wide-ranging energy bill that would provide ratepayer-financed support for nuclear, coal, renewables and energy efficiency (SB 2814).
Dubbed the Future Energy Jobs Bill, it has one sponsor in each house of the General Assembly: Sen. Don Harmon and Rep. Robert Rita, both Democrats from the Chicago area. The legislation touches on almost every aspect of the electric industry:
Zero Emission Credits (ZECs) that utilities must buy from qualifying generating units.
A fixed resource adequacy plan (FRAP) that would put the state in charge of procuring capacity for its MISO region in Southern Illinois.
A tariff to recover costs for increasing the implementation of energy efficiency and demand response projects.
Revisions to the state’s renewable portfolio standard to fix an issue that advocates say hampers renewable investment.
Revisions to the retail rate structure, including implementing a “grid impact rate.”
Installation of up to six microgrids, restricted to specific utilities.
A version of the bill has been pushed by Exelon since it threatened in May to shut down its Clinton and Quad Cities nuclear plants if the state didn’t provide subsidies, such as the emissions credits proposed in the new bill. (See Absent Legislation, Exelon to Close Clinton, Quad Cities Nukes.)
The Clinton Nuclear Station is one of two nuclear plants in Illinois that Exelon has threatened to shut down if it doesn’t receive requested financial relief from the state. | Exelon
The bill had been opposed by Dynegy, which plans to shutter three 40-year-old coal-fired plants in central and southern Illinois, but the Houston-based power provider got on board once the FRAP was added. Dynegy says MISO’s market design allows power plants receiving regulated rates in states outside Illinois to suppress capacity and energy prices. The company and state legislators have expressed preference for PJM’s market over MISO’s. (See Dynegy Introduces Bill to Move All of Ill. Into PJM.)
“In the last six months alone, the flawed market design has resulted in Dynegy shutting down more than 15% of generation in Southern Illinois and additional plants could be at risk in the future,” Dynegy’s David Onufer said. “The legislation deals with gaps in the downstate market by providing a competitive process to secure generation for the future. It’s non-discriminatory and open to all fuel resource types that meet the required high standards of performance.”
“The legislation reflects the work of a broad group of stakeholders to achieve comprehensive energy legislation that is urgently needed to strengthen our economy and save and create tens of thousands of jobs,” Exelon’s Paul Adams said. “As with any piece of major legislation, it will continue to evolve as stakeholders weigh in. But at its core, we know the bill will bring significant benefits to consumers and the environment in Illinois. … There is broad agreement regarding the need to urgently address energy challenges in Illinois.”
The ZECs would start at $16.50/MWh, which is based on the U.S. Interagency Working Group on Social Cost of Carbon, and increase by $1/MWh per year, starting in 2023.
The number of credits that eligible facilities would receive is less easy to calculate. The amount is based on a complicated formula that limits the increase in retail customers’ bills to no more than 2.015% of the price per kilowatt-hour that consumers paid in 2009.
The bill is opposed by the BEST Coalition, which includes a wide variety of commercial and industrial ratepayers. Organizer Dave Lundy says that because Illinois is a substantial exporter of energy, saddling in-state customers with additional costs would subsidize out-of-state consumers. He pointed to grid operator studies showing that none of the plants threatened to be closed would impact reliability to the extent that transmission would need to be built or that they would need to receive reliability must run contracts.
He called the emissions credits and FRAP “bailouts” for nuclear and coal interests and said they would cause volatility in retail rates.
Consumers, particularly those on a budget, “can’t absorb wild swings from month to month,” he said. “You may be a winner three or four months out of the year, but if you’re a loser and you’re not in a position to pay that bill, you’re in trouble.”
Lundy said the microgrids could be useful in theory, but he criticized the fact that they were granted to utilities to build and not open to competitive bidding. He feared the utilities will “gold-plate” and overcharge for them.
He also applauded the long-awaited fix to the RPS policy, but he said packaging it with the rest of the bill’s initiatives made it come at too high a cost. “I can’t even call that a positive because [the RPS fix] requires the destruction of the entire market, and you’ll never be able to build anything else,” he said. “It’s a hollow victory.”
Despite the bill’s name, “it is undeniable that a massive rate hike will make Illinois less competitive. … You will kill jobs,” he said.
“Nobody’s advocating [closing] all the baseload units in the state. … You don’t need to shut down the coal plants if they’re economic to run,” he said. “We are not anti-nuclear; we are anti-bailout.”
