NYISO and PJM officials discussed potential directions for their capacity markets and ways renewable energy producers could benefit from new market structures during a quick panel discussion during Greentech Media’s annual Power and Renewables Summit on Tuesday.
The panel featured questions about projected capacity market updates and their impact on prices, technologies and risk.
Logan said there will be “casualties” as a result of the orders, pointing out the burgeoning offshore wind sector in both grid operators’ markets. He also said they have sent state policymakers questioning their roles in creating their own energy mixes through legislation. He asked how NYISO and PJM have been working with states to determine what is appropriate bidding behavior by subsidized generators.
Emilie Nelson, executive vice president of NYISO, said the ISO experiences less complications when looking at policies because it only has to deal with one state government, one governor and one legislature. She said one of the benefits of a single-state grid operator is “clarity” in the environmental goals.
Anthony Logan, senior analyst with Wood Mackenzie (top left), speaks with NYISO’s Emilie Nelson and PJM’s Stu Bresler during GTM’s Power and Renewables Summit on Sept. 29. | GreenTech Media
Nelson pointed to the Climate Leadership and Community Protection Act (CLCPA) signed by New York Gov. Andrew Cuomo in July 2019 that set ambitious clean energy goals: 100% zero-emission electricity by 2040 and an 85% cut in emissions by 2050 from 1990. It also requires 70% of renewable energy production by 2030. (See ‘Astonishing’ Buildout Needed for Clean NY Grid.)
“Having the clarity on the direction that New York is trying to go allows us to contemplate some design approaches and different ideas to move ahead and explore things not quite as mainstream to see if they would work for our state,” Nelson said.
Stu Bresler, senior vice president of market services for PJM, said the RTO differs from NYISO in that it must balance the interests of 14 jurisdictions, including D.C., instead of just one state. He said the diversity of opinions and policy direction among the states in the PJM region is a constant challenge.
But Bresler also said having each jurisdiction’s unique perspective is a valuable tool, giving PJM better insight into potential solutions to problems. The Organization of PJM States Inc. allows for an exchange of ideas as to how the markets should evolve and how operations can be done more effectively.
“That diversity of thought provides for a much richer discussion in our region and has really helped us and assisted us in evolving our operations planning and markets over the years that has been beneficial for ratepayers and consumers,” Bresler said.
Looking for Solutions
Logan said NYISO has taken a “damn the torpedoes” leadership style when it comes to decarbonization. He asked where Nelson sees the ISO’s resource mix heading under the new BSM regulations.
Nelson said NYISO is going see a rapid transformation as more solar, offshore wind and storage come online. The ISO is considering how markets need to change to accommodate the changes. She noted its Grid in Transition initiative, which focuses in part on ensuring that ancillary service products are aligned with reliability needs, particularly around New York City. (See NYISO Moves Forward on EAS Projects.)
“It’s a multifaceted strategy across our market platforms because we are expecting so much change on the system,” Nelson said.
Turning to Bresler, Logan said it appeared that PJM has taken a “wait it out” approach toward the MOPR, as some of its states debate using a fixed resource requirement (FRR). He asked how carbon pricing fits into the RTO’s markets. (See Commenters Weigh in on PJM MOPR Compliance Filing.)
Bresler said it’s PJM’s hope that states would not elect the FRR option and instead see how things “play out” in the upcoming capacity auctions. He said the “prevailing wisdom” is the MOPR won’t have a huge impact on the first few capacity auctions because of exemptions granted by FERC to existing renewable resources.
In the long term, Bresler said, PJM has questions about the sustainability and durability of the “broad MOPR rule” and wants the states to work with the RTO to achieve environmental goals by leveraging the competitive nature of the markets. (See NJ Regulators Weighing Input on Capacity Market Exit.) He said a carbon price is a potential solution to reach reduction goals, among other concepts.
“Perhaps there’s a way to incorporate other goals as well but maintain as much as we can this competitive approach across a large region, which has shown to be tremendously beneficial,” Bresler said.
NextEra Energy Transmission (NEET) announced Tuesday that it will pay $660 million to acquire independent transmission company GridLiance, which owns 700 miles of high-voltage lines in Illinois, Kansas, Kentucky, Missouri, Nevada and Oklahoma.
The deal, which includes the assumption of debt, will be financed in part by parent NextEra Energy’s $2 billion sale of equity to BofA Securities and Barclays, announced last week.
Launched in 2014, GridLiance markets its expertise in planning, engineering, construction and operations to small transmission owners, including electric cooperatives and public power. Backed by Blackstone Energy Partners, an affiliate of The Blackstone Group, it also offers its “partners” a source of capital investment for transmission projects.
In addition to the transmission it owns, Gridliance also has long-term partnership agreements in Missouri, Oklahoma, Nevada, Texas and Kansas.
NextEra said the deal will require approval from FERC and utility commissions in Kansas, Missouri and Oklahoma. It is expected to close in 2021.
“GridLiance partners with electric cooperatives and public power utilities to enhance transmission system reliability and is well positioned to benefit from the substantial expected renewables growth over the coming years,” NextEra CEO Jim Robo said in a statement. “This acquisition furthers our goal of creating America’s leading competitive transmission company and is consistent with our strategy of adding high-quality regulated assets to our portfolio.”
“We are very excited to be joining NextEra Energy Transmission at a pivotal time in the company’s development,” GridLiance CEO Calvin Crowder said. “Our unique capabilities, proven track record and tremendous growth prospects, coupled with NextEra’s experience as a leading transmission owner, make this a great fit for both companies. We are also grateful for the support of Blackstone in founding GridLiance and for working closely with management over several years to build the company.”
Fighting ROFR
NEET currently has operating assets in California, New Hampshire and Texas, including Lone Star Transmission in Central Texas (330 miles of double-circuit 345-kV line and six substations).
One of NEET’s affiliates was awarded the rights to the Empire State Line in Western New York (20 miles of 345-kV line and two substations), which will increase renewable energy flows from the Niagara hydroelectric facility and imports from Ontario by 3,700 MW. Another affiliate is building the East-West Tie in Ontario (280 miles of double-circuit 230-kV line), which it says is the first competitive transmission project awarded to a nonincumbent in the province.
The Wall Street Journalreported on Tuesday that Duke Energy recently rebuffed a takeover attempt by NextEra. NextEra is still interested in Duke, the Journal said, noting that such a deal would be the largest utility acquisition ever. NextEra is the largest public utility in the U.S. with a market capitalization of $139 billion; Duke has a market value of about $61 billion.
NextEra shares closed Tuesday at $283.12/share, down $1.02 (0.36%). Blackstone shares rose by 5 cents to $52.71/share (0.095%).
GridLiance was the second asset sale by Blackstone Energy this month. On Sept. 24, it announced it would sell its 42% stake in Cheniere Energy Partners to Brookfield Infrastructure Partners and funds managed by Blackstone Infrastructure Partners for $7 billion. In 2012, Blackstone Energy and its affiliates invested $1.5 billion in Cheniere to build the first two liquefaction trains at the Sabine Pass LNG facility in Louisiana, the first LNG export facility in the continental U.S.
NERC on Monday completed the second of two compliance filings directed by FERC earlier this year, detailing changes to its Rules of Procedure (ROP) intended to “reflect current business practices and provide further transparency to industry stakeholders” (RR19-7).
FERC ordered the ROP changes in January in response to NERC’s five-year performance assessment, expressing dissatisfaction with the transparency of the Electricity Information Sharing and Analysis Center (E-ISAC) considering it accounts for 28% of the ERO’s total 2020 budget. The commission requested that NERC clarify the E-ISAC’s relationship with the Electricity Subsector Coordinating Council (ESCC), correct inconsistencies in terminology used in the ROP and update other operational practices related to the ERO’s infrastructure security program. (See NERC Wins Another 5 Years as ERO.)
The compliance filing was originally due July 21, but NERC requested an extension in order to allow for the full 45-day stakeholder comment period, which FERC approved in March, followed by another delay because of the COVID-19 pandemic. (See NERC Board of Trustees/MRC Briefs: Aug. 20, 2020.)
The commission had ordered an additional compliance filing, submitted in June, discussing NERC’s oversight of its regional entities and the development process for reliability guidelines, as well as the role of the E-ISAC. (See NERC Clarifies Audits, E-ISAC in Filing.)
Registration and Certification Revisions
NERC’s planned changes include:
revisions to the Registration and Certification Program in Section 500 (Organization registration and certification) and Appendices 2, 5A, 5B and 5C;
updates to the infrastructure security program in Section 1003, including the E-ISAC; and
modifications to the sanction guidelines in Appendix 4B.
The first set of changes, which primarily involve adding “more granularity” to registration-related provisions, is being published for the first time. These include sections involving joint registration organizations (JROs), to provide clarity to the requirements for JRO construction and operation; and coordinated functional registration (CFR) agreements, with greater specificity around the information required to make a CFR acceptable to NERC and the roles and responsibilities of parties to the agreement.
In addition, NERC proposes to “add more specificity to the minimum criteria for certification” by detailing that entities’ “tools, personnel, facilities and [processes] used to perform … tasks required by the applicable reliability standards will be evaluated.”
The organization also plans to remove a requirement in Appendix 5A that the Compliance and Certification Committee approve any revisions to registration and certification procedures before they are submitted to the board, while adding a new section to the same appendix specifying how entities maintain their certifications. Redundant language in Appendix 5B will be removed as well, and Appendix 5C will be changed to create better alignment with updated sections of the ROP.
E-ISAC, Sanctions, APB Clarified
Revisions to Section 1003 include the insertion of a paragraph describing the role of the E-ISAC and its place alongside the Department of Energy and ESCC in the U.S. national security framework and language emphasizing that NERC considers security an equal priority to reliability and resilience. References to the critical spare transformer program, the National Infrastructure Protection Plan and other organizations were deleted, as NERC is not involved in these activities anymore.
Changes to NERC’s sanction guidelines aim to emphasize the importance of fairness when determining penalty amounts, with reference to factors such as risk and severity level, as well as the role that nonmonetary sanctions may play in determining the final penalty amount. Additional language was inserted at FERC’s request requiring NERC and the REs to ensure that the size of the offender and its ability to pay are taken into account when setting penalties to ensure that violators do not see sanctions as “an economic choice or cost of doing business.”
In its January order, FERC also directed NERC to “clarify its processes regarding the development and issuance of All Points Bulletins,” part of the E-ISAC’s Critical Broadcast Program (CBP). NERC addressed this request in the last section of its Monday filing, describing the threshold for activating the CBP, procedures for approving activation, the target audience of the program, and methods and timing of communicating critical security information. In addition, the organization discussed the CBP’s relation with other information-sharing mechanisms, such as the NERC Alert process.
FERC on Monday placed an Iowa wind farm’s method for calculating reactive power rates into question, although it declined to initiate a blanket probe into similar NextEra Energy rate filings.
The commission said NextEra Energy Resources’ Crystal Lake II wind farm in north-central Iowa may be improperly including operations and maintenance costs and transmission-related expenses in its reactive power rate schedule. It set the facility’s rates for hearing and settlement proceedings (ER20-2543).
Crystal Lake II said it now requires slightly more than $1 million per year in reactive power revenue. The facility is designed to provide reactive power, and its turbines have been churning since 2012.
Nearby Interstate Power and Light (IPL), an Alliant subsidiary, raised objections to Crystal Lake II’s rate schedule, arguing that it is unacceptable for asynchronous generators to use the reactive power rate methodology FERC established in 1999 for synchronous generators. IPL said the filing was “one of a series of filings by subsidiaries of NextEra to establish charges for reactive service.” The utility asked the commission to consolidate and investigate all similar filings by NextEra subsidiaries.
FERC said a preliminary analysis of Crystal Lake II’s proposed rates showed they could be unjust and unreasonable. The commission said a consolidation of other NextEra filings was beyond the scope of the proceeding but said that IPL “may raise its concerns regarding how the proposed revenue requirement has been calculated in the hearing and settlement judge procedures.”
Crystal Lake wind farm | NextEra Energy
For its reactive power charges, Crystal Lake II included the costs of low-voltage collection system feeders and low-voltage transformers, which aggregate the output of individual wind turbines. The collection system costs include some substation costs.
IPL argued that collection system costs aren’t necessary for synchronous generators’ production of reactive power and therefore aren’t contemplated by FERC’s 1999 methodology. The utility also said the equipment costs can’t be completely dedicated to reactive power production.
“The allocation of accessory electric equipment costs to the production of reactive power has not been shown to be just and reasonable and appears excessive,” IPL said.
The company also charged that Crystal Lake II was expecting to be compensated for transmission-related system losses, though FERC’s methodology only allows traditional generation’s heating losses to be recovered. “Wind-powered generators do not experience significant heat-related losses in the production of reactive power,” it said.
The utility said FERC should “consider balancing the requirement to provide reactive power with the need for reactive power in a particular locale or region.” It said that FERC “should not simply assume that, because a generator is able and willing to provide reactive power, that this reactive power is needed for reliable and efficient operation of the electric system.”
NERC’s Standards Committee is accepting nominations through Oct. 15 to replace nine members who will depart at the end of the year, as well as to fill three spots that are currently vacant.
The Standards Committee comprises the chair and vice chair, along with two representatives from each of 10 industry segments, with memberships staggered so that half of the representatives are replaced each year. This year’s departing members are:
Segment 1, transmission owners: Sean Bodkin, Dominion Energy;
Segment 2, RTOs and ISOs: Charles Yeung, SPP;
Segment 3, load-serving entities: Linn Oelker, LG&E and KU;
Segment 4, transmission-dependent utilities: Barry Lawson, National Rural Electric Cooperative Association;
Segment 5, electric generators: William Winters, Consolidated Edison;
Segment 7, large electricity end users: Venona Greaff, Occidental Chemical;
Segment 8, small electricity users: David Kiguel, independent; and
Segment 10, regional reliability organizations and regional entities: Steven Rueckert, WECC.
In addition, the committee is looking to fill vacancies for the term that ends December 2021 in segments 4 and 7, so nominations will be accepted for these spots as well. In the election, the candidates in those segments with the most votes will be given their choice of terms, with the other term going to the runners-up.
Nominations are also being accepted for Segment 9 (Federal, state and provincial regulatory or other government entities). Currently the segment is only represented by Ajinkya Rohankar of Public Service Commission of Wisconsin, whose term ends in December 2021.
The committee is required to have at least two members from Canada — currently Kiguel and Robert Blohm of Keen Resources, who will leave at the end of 2021. If the regular election does not result in the seating of another Canadian representative, then the Canadian candidate who receives the most votes in their segment will be named as an additional member.
Nominees may be submitted by anyone, with the election to be conducted “shortly after the nomination period is closed.” Industry segments that intend to use a special procedure to elect their representatives must inform the committee by Oct. 15.
Special Election to Fill RSTC Seat
The Reliability and Security Technical Committee is also holding a special election to fill a vacancy in Sector 8 (Large end-use electricity customers). The nominating period ran from Aug. 28 to Sept. 18, with Travis Fisher, president and CEO of the Electricity Consumers Resource Council (ELCON), and Thomas Siegrist, a consulting engineer with Stone Mattheis Xenopoulos & Brew, making the final ballot. Voting began on Sept. 21 and will end at midnight Oct. 5.
Like the Standards Committee’s, members on the RSTC serve staggered two-year terms. Occidental’s Greaff (2020-2022) and former ELCON CEO John P. Hughes (2020-2023) were elected to represent Sector 8 in January; NERC has not identified which is leaving. (See Nominations Close for At-Large RSTC Members.) The winner of the special election will serve out the departing member’s remaining term.
Stronger federal leadership and changes to wholesale electricity market rules are needed to supplement New England’s decarbonization efforts, Massachusetts Secretary of Energy and Environmental Affairs Kathleen Theoharides and Katie Dykes, commissioner of Connecticut’s Department of Energy and Environmental Protection, told Raab Associates’ New England Electricity Restructuring Roundtable.
Theoharides and Dykes were the keynote speakers at the virtual event Friday, which drew an audience of more than 450 people.
There has been “no hint of politics in the way we approach this work,” Theoharides said about Massachusetts, whose Republican Gov. Charlie Baker committed the state to a target of net-zero emissions by 2050.
Theoharides said one approach to meeting that goal is the Transportation and Climate Initiative (TCI), a collaboration of 12 Northeast and Mid-Atlantic states and D.C.
TCI would set a limit on carbon dioxide emissions from diesel and gasoline vehicles and allow states to invest proceeds from the sale of carbon allowances to support the goals of the program, such as electric vehicle chargers and electric buses.
The initiative estimates a cap that cut emissions 25% from 2022 levels by 2032 would produce $10 billion in public health benefits (2017$) while covering almost three times the Regional Greenhouse Gas Initiative cap, which includes the New England states, New York and more recently New Jersey and Virginia. Transportation represents 43% of emissions in the TCI region, and total transportation-related carbon emissions are nearly twice as large California’s, Theoharides said.
Clockwise from top left: Katie Dykes, Connecticut DEEP; Jonathan Raab, Raab Associates; and Kathleen Theoharides, Massachusetts EEA. | Raab Associates
TCI expects to finalize a memorandum of understanding setting its targets this fall, when each jurisdiction will decide whether to sign the MOU and participate.
“It is a capital investment program,” Theoharides said. “It is a point of regulation far upstream from the consumer at the wholesale or fuel-supplier level. Credits would be auctioned off in each state, and the proceeds would go back into the states, much as they do in RGGI, to invest in clean transportation solutions that give people the option to choose transportation that reduces air pollution and that provides mobility for more residents.”
Amid the COVID-19 pandemic, TCI has the potential to reduce the public health impact of environmental pollution significantly, Theoharides added.
“The pandemic has highlighted the connections between air pollution and respiratory diseases, and TCI is a way to ensure sustained investment in transportation that gives people better, more affordable choices for getting to work, school and health care services while cutting the pollution that makes people sick and makes them more vulnerable to disease,” Theoharides said.
Connecticut has pledged to cut carbon emissions by 80% from 2001 levels by 2050 and 100% in the electricity sector by 2040. Dykes said it is “long past the moment for significant changes in the wholesale electricity markets to ensure that Connecticut can either secure the resources that we need to meet our clean energy goals in-market, or that we can get credit for what we have had to procure outside of the market in order to meet our goals.”
Dykes said a “unified approach” is needed to meet the decarbonization mandates.
“We are not even in an acceptable place in terms of having a proactive transmission planning process that ensures adequate competition in our RTO,” Dykes said about ISO-NE. “For the transmission investments, when you look at the dollars spent per mile deployed, New England is at the bottom of the heap in terms of providing … value for our ratepayers. Transmission service costs are more than twice the average of other RTOs and ISOs.”
Dykes thinks that improving the transparency and accountability of ISO-NE and institutions like the New England Power Pool that are “core to the design and implementation of our wholesale markets” is a “necessary and essential step” to achieve affordable decarbonization that uses competition and minimizes risk to ratepayers. She said the current structure reflects that states do not have adequate input and accountability in the design and structure of the RTO’s governance.
Moderator Jonathan Raab said both Massachusetts and Connecticut have plans and policies in place to meet “really bold decarbonization mandates.” He then asked Theoharides and Dykes if New England states can be “fully decarbonized without strong complementary federal action on numerous fronts” and what the federal government could or should do to facilitate the region’s decarbonization efforts.
Dykes said the impact of climate change on the economy and public health is “accelerating faster than we had anticipated.” She said there is a severe disconnect between states and the federal government, which, Dykes said, is “walking away or even making our climate progress more difficult.”
“We have companies in a private market that can accelerate and deploy climate solutions so quickly and cost-effectively,” Dykes said. “I think the tragedy of all this disconnect at the federal level is that it’s preventing the incredible strengths and advantages of our country from being applied at the scale that we need to solve this climate crisis.”
Theoharides added: “It matters that we have a target as a nation we’re shooting for; it’s not just a handful of states which have mandatory emissions targets; we need a federal target, and we need every state to be pulling its weight to get us there. That leadership needs to come from the top.”
Decarbonization Takes the Whole Village
The conference’s second session featured a four-person panel with representation from local and state governments plus a global nonprofit and think tank. The presentations touched on some of the same topics that Theoharides and Dykes broached earlier and delved into job creation and the social justice aspects of decarbonization.
Hal Harvey, CEO of Energy Innovation, said it is not true “that one has to sacrifice economic vitality in order to have a clean environment.” The financial upside of clean energy is good jobs, lower costs and less local pollution, he said. There were 3.3 million clean energy jobs in the U.S. at the start of 2020, representing more than 40% of the energy workforce, Harvey said.
“The fastest two growing careers in America are solar installer and wind installer,” Harvey said. “The opportunities do not require college degrees. … Roughly half of Americans do not have a college degree; we need an energy strategy that gives them great jobs.”
Hannah Pingree, director of policy innovation and future for Maine Gov. Janet Mills, said the first-term Democrat had made climate progress one of her top agenda items, especially in job creation.
“Maine is embarking right now on an offshore wind project, trying to launch the first floating turbine in the next couple of years, so obviously that’s one of the many exciting things we think could bring jobs and economic prosperity,” Pingree said.
Clockwise from top left: Eugenia Gibbons, Health Care Without Harm; Chris Cook, city of Boston; moderator Jonathan Raab; Hal Harvey, Energy Innovation; and Hannah Pingree, Maine Governor’s Office of Policy Innovation and the Future | Raab Associates
While climate change can drive job creation, Chris Cook, chief of environment, energy and open space for the city of Boston, said it also affects socially vulnerable populations. One of the city’s major initiatives this year is creating Community Choice Electricity, which was recently approved by the Massachusetts Department of Public Utilities. The program will allow the city to buy electricity for residents and businesses through its combined buying power to provide affordable and renewable electricity to those who participate in the program.
“If we provide a clean economy [and] a decarbonization pathway that doesn’t expand equity opportunities for our most socially vulnerable residents, then we will have failed,” Cook said. “It’s not about what we do. It’s about who we do it for. They are our neighbors; they are our friends. They are the people that we are charged with at the city level to take care of, and they need to be actively part of the solution.”
Eugenia Gibbons, Boston director of climate policy for Health Care Without Harm, a global nonprofit that works to reduce the health care sector’s environmental footprint, said climate solutions like decarbonization must benefit historically marginalized communities.
“Essentially we are coming from a place of understanding that climate justice will only be achieved if policies that are enacted bring about concrete improvements in the health and lives of communities that continue to bear the burden of environmental and climate pollution,” Gibbons said. “Equity absolutely has to be a factor in designing, implementing and evaluating policy and program solutions. Otherwise, the disparity will just be perpetuated and exacerbated.”
In the absence of federal leadership, “we absolutely have to demonstrate at the state and local level what is possible and what we are capable of achieving [and] ensure that we are not leaving anybody behind when we move forward with this pathway to decarbonization,” Gibbons added.
When Raab asked the panel for closing thoughts, Harvey said 2020 is an inflection point.
“If we use this decade well, we can land at a reasonable climate future, but this is the decade that matters. This is where we have to stop all new fossil installations, period, and much more rapidly change the direction that we are on,” he said. “I can say now it’s cheaper to save the Earth than to ruin it, because it is. We better get busy, because if we don’t do it this decade, it isn’t going to happen.”
More than 60% of New Yorkers said they approve of NYISO’s carbon pricing plan after learning of the advantages of such a price in the state’s wholesale electricity markets, according to a poll released by the ISO on Monday.
A joint task force between NYISO and the state’s Public Service Commission issued a proposal last December that would use the social cost of carbon (SCC) as a baseline for such a price.
The poll conducted by Siena College Research Institute (SCRI) showed how an informed opinion increased support for carbon pricing.
When respondents were initially asked about NYISO’s proposal, 47% said they were in favor, 36% opposed and 17% expressed no opinion. But after respondents were informed of the plan’s benefits — including replacement of polluting power plants with cleaner generators and the economic boost from adopting clean technologies — support grew to 62% and opposition fell to 27%, while 11% had no opinion.
“At least a plurality of every demographic found each of these potential outcomes making it more likely to support” carbon pricing, SCRI Director Don Levy said.
The SCRI poll shows broad support for New York getting 70% of its electricity from renewable sources by 2030 and increasing to 100% zero-emitting sources by 2040. | SCRI
NYISO released the poll two days before a technical conference on carbon pricing at FERC.
“We view this poll result as a validation of New York’s efforts to develop an innovative solution to the state’s renewable energy goals,” CEO Rich Dewey said in a press conference.
The fact that FERC invited him to testify at the technical conference along with Rana Mukerji, the ISO’s senior vice president for market structures, shows that carbon pricing is “increasingly recognized” as a vehicle to transition the power industry toward renewable energy, Dewey said.
Asked what he hoped to accomplish at the technical conference, Dewey said, “These investments are going to be made in renewable resources. He wants FERC “to understand and accept that a state policy element, appropriately designed and controlled, fully transparent and open, does have an effective place in helping markets position themselves to achieve those goals as efficiently and as effectively as possible.”
The commission earlier in September rejected the ISO’s proposal to make it easier for public policy resources to clear its capacity market, specifically helping those resources in New York City and capacity zones G-J to avoid buyer-side mitigation if enough existing capacity exits the market, or if demand increases enough to boost capacity requirements. (See FERC Rejects NYISO Bid to Aid Public Policy Resources.)
CAISO last week won FERC approval for its second effort to implement market rule changes to allow generators to recover the costs of higher natural gas prices (ER20-2360).
The changes emerged from CAISO’s Commitment Costs and Default Energy Bid Enhancements (CCDEBE) initiative. FERC rejected an earlier filing by the ISO in 2019, saying its generous multiplier for gas resources was neither fact-based nor warranted.
CAISO’s revised plan, which eliminated the multiplier, measured up, FERC said.
“We find that CAISO’s CCDEBE proposal will allow resources that face high gas costs resulting from inter-day variation in natural gas prices to reflect those costs in their reference levels,” FERC said. “By reflecting the actual costs of these resources in reference levels, CAISO’s proposal will facilitate a more efficient dispatch of its system.”
The ruling was one of two that FERC issued Sept. 21 involving CAISO’s efforts to comply with Order 831.
Issued by FERC in 2016, Order 831 requires ISOs and RTOs to raise the hard caps on supply bids from $1,000 to $2,000. Offers over $1,000 require suppliers to justify their costs. It’s meant to allow supply resources, especially gas generators, to earn prices sufficient to recover their operating costs during periods of high demand, thereby helping to ensure reliability.
To comply with the order, CAISO proposed revising its Tariff with a two-tier bid cap structure. The plan includes a soft cap of $1,000/MWh — which would apply to all energy bids except for virtual bids and those for non-resource-specific system resources — and a hard cap of $2,000/MWh, which would apply to all energy bids.
CAISO’s Department of Market Monitoring objected, arguing that the ISO’s proposed provision regarding verification and recovery of minimum load cost bids was unclear and unsupported.
FERC dismissed the objection and said the revisions complied with the requirements of Order 831, subject to a further compliance filing to update certain eTariff records (ER19-2757).
“We find that, as required by Order No. 831, CAISO’s Tariff revisions proposed herein and reflected in the 2020 CCDEBE proposal set forth the process for CAISO to verify that a resource’s bid above $1,000/MWh reasonably reflects that resource’s actual or expected costs,” FERC wrote.
‘Natural Gas Price Volatility’
In the cost-recovery ruling, FERC said it had rejected CAISO’s 2019 CCDEBE proposal because the ISO failed to show that it was just and reasonable to apply a 125% multiplier to commitment cost bid caps derived using supplier-submitted costs.
“Specifically, the commission stated that ‘whereas a multiplier applied to an index captures deviations from an average cost, and therefore may account for resource-specific cost deviations from the index, a multiplier applied to supplier-submitted costs would provide additional headroom on top of verifiable actual costs’ and that CAISO had not provided sufficient evidence to support this upward adjustment,” FERC wrote.
PG&E’s natural-gas fired Colusa Generating Station | PG&E
In its revised proposal, CAISO altered its methodology, including eliminating the multiplier from its plan. Instead, it submitted changes that let suppliers request adjustments to their ISO-calculated commitment costs — their start-up and minimum load costs — and to their energy-price reference levels to more accurately reflect their costs.
“CAISO asserts that the proposed revisions will provide a just and reasonable method for verifying a supplier’s request to increase a resource’s reference levels when its actual or expected costs will be greater than CAISO-calculated costs based on verifiable contemporaneously available information,” FERC wrote.
“CAISO explains that these procedures will enable it to use fuel or fuel-equivalent prices in calculating reference levels that reflect suppliers’ actual or expected fuel or fuel-equivalent costs,” it said. “CAISO contends that this, in turn, will provide CAISO with more efficient resource schedules and dispatches and will ensure that suppliers are adequately compensated.”
FERC agreed with CAISO’s assessment.
“CAISO’s proposal to adjust the reasonableness threshold in response to inter-day fuel price increases in a fuel region, and in response to persistent conditions faced by a resource, will … ensure that its markets accurately reflect natural gas price volatility, which in turn will result in dispatching resources more efficiently,” FERC said.
“Additionally, we find that CAISO’s proposal to exclude existing commitment cost and default energy bid multipliers from the calculation of a resource’s adjusted reference level is just and reasonable and addresses the concerns that led to rejection of the 2019 CCDEBE proposal,” it said. “Under CAISO’s proposal in this filing, reference level adjustments will be based on a resource’s actual or expected costs and will not provide additional headroom above a resource’s verifiable actual or expected costs.”
Maine’s sunshine will soon provide more than just lighting for viewing the fall foliage.
The Maine Public Utilities Commission last week announced a procurement of renewable energy, and solar developers were the clear winners, claiming 14 of the 17 projects selected. It is the PUC’s largest procurement of renewable energy since restructuring more than 20 years ago.
The selected projects were evaluated through a competitive bidding process based on expected value to Maine’s consumers and economy. Solar will account for 482 of the 546 MW of the approved projects, with wind (20 MW), hydroelectric (4.5 MW) and biomass (39 MW) making up the remainder.
The biggest projects are Swift Current Energy’s 100-MW solar farm in Hancock County, which signed a term sheet with Versant Power, and Granite Apollo’s Canton (65 MW) and Roxbury (55 MW) projects, which signed agreements with Central Maine Power.
Maine currently has about 93 MW of solar power, according to the Solar Energy Industries Association, ranking it 43rd among states.
PUC Chairman Philip Bartlett told RTO Insider that this process “reflects just how much renewable energy potential there is in Maine and the benefits to Maine’s economy from moving forward aggressively.”
Thomas College solar roof in Waterville, Maine | Coastal Enterprises
Winning bidders estimated the projects would reduce greenhouse gas emissions by approximately 500,000 tons per year. They have also committed to providing more than 450 full-time jobs during the construction phase and more than 30 full-time-equivalent positions in each operational year.
“It’s really important that as we are transitioning to a clean economy that we recognize the important economic benefits to Maine people and the jobs that can be created,” Bartlett said. “I think it’s certainly beneficial that there’ll be a lot of jobs during the construction phase as well. That will help at a time when the economy is struggling, so hopefully, the combination of those things will have a meaningful long-term impact.”
The projects promise more than $145 million in initial capital spending. In addition, the ReEnergy Livermore Falls biomass project will generate payments to Maine-based contractors for the harvest of wood fuel averaging $11 million to $12 million annually during the 20-year contract term.
“I think that’s an indication of how strong a market signal this was, and we’re excited about this procurement, which is the first to not just look at the price that comes with these projects, which in this case was very competitive, but also look at the economic benefits,” Dan Burgess, director of Gov. Janet Mills’ Energy Office, told RTO Insider. “It’s pretty innovative to have those built-in directly into the contracts and the term sheets; I think it’s a guaranteed positive impact for an economy.”
The first-year energy prices for the 15 new projects awarded term sheets ranged from $29.75 to $40/MWh, with a weighted average price just under $35/MWh.
These projects are the first since Mills signed legislation last year to increase the state’s renewable portfolio standard to 80% by 2030 and set a goal of 100% renewable energy by 2050.
Another round of procurement bids for renewable resources is due in mid-January, and developers that were not initially selected can enter again. The two procurements must equal 14% of the state’s 2018 retail electricity sales. The awards announced last week represent 9.4% of 2018 sales.
The Energy Bar Association’s Canadian Chapter held its first annual meeting online Thursday, with discussions on cybersecurity and holding virtual adjudication hearings amid the COVID-19 pandemic.
The chapter, formed a year ago, was originally going to hold the meeting in D.C. in April, at the same time as the EBA Annual Meeting, but it was forced to reschedule it in an online format because of the pandemic. (See EBA Holds Annual Meeting Online Successfully.)
Here’s some of what we heard.
Challenges of Cybersecurity on the Distribution Side
David Morton, chair of the British Columbia Utilities Commission, opened the conference with an anecdote about visiting the U.S. Department of Energy for a briefing on cybersecurity earlier this year (before the pandemic hit).
There were two briefings that day: one for those with top secret security clearance and those without. Morton attended the latter, “but I’m not sure it would have made any difference,” he said.
“I couldn’t even tell anybody about it anyway. … I had to sign and swear I wouldn’t share [the information he received] with anybody when I brought it back to my commission,” Morton said. “So, what am I supposed to do with that information? How can I even apply it to any of the work that I do?”
Clockwise from top left: Mary Anne Aldred, Ontario Energy Board; BCUC Chair David Morton; EBA Canadian Chapter President Gordon Kaiser; and Louis Legault, Régie de l’énergie du Québec. | EBA
Morton also pointed out that NERC’s mandatory reliability standards only cover the generation and transmission side of the electric industry, leaving the distribution side vulnerable. “If you took out the distribution system in Greater Vancouver, that’s just as bad as taking out the transmission system, at least to the 2.5 million residents in Vancouver,” he said.
“I do think it would be appropriate to raise the bar somewhat on standards,” said Alex Foord, chief information officer for Ontario’s Independent Electricity System Operator. “The larger entities … are going to come along and do the right thing. The challenge is when you get into smaller [utilities] … they don’t have the expertise, the sophistication and the time to do it. But candidly, that’s no excuse for the lack of action; they owe it to their consumers to do better.”
Cintron Shares Experiences with Virtual Hearings
FERC Chief Administrative Law Judge Carmen Cintron gave attendees a candid behind-the-scenes look into how she transitioned the commission’s Office of Administrative Law Judges from in-person to virtual hearings after the pandemic hit.
The pandemic “caught me, to use an American expression, with my pants down. We had modeled for the whole United States being under a nuclear attack; we had modeled for hurricanes; we had modeled for everything, except a pandemic,” she said.
FERC Chief ALJ Carmen Cintron | EBA
The office was immediately able to transition to virtual settlement conferences, which aren’t as complicated as hearings, Cintron said. Its settlement success rate has actually risen to 92%, from its usual 89%. “We attribute this to the fact that the business entities, the decision-makers, can actually participate without having to travel” to D.C.
Meanwhile, Cintron postponed imminent hearings until the office’s IT department set up Cisco’s Webex platform and the ALJs trained in using it and practiced by simulating hearings. The first virtual hearing began May 6 and lasted 16 days. One of the parties filed a motion to halt the proceeding, arguing that its virtual nature was a violation of due process, but it was denied by Cintron.
Though she said the process has been an overall success — with even the party that filed the due process motion responding favorably after their hearing was over — Cintron said it has not been without challenges, mostly owing to technical problems. It was immediately clear from her opening remarks that she is not a fan of Webex, and later in the discussion, she said she wants to migrate to Microsoft Teams. The different parties’ varying degrees of computer proficiency and internet bandwidth were early frustrations. ALJs also needed to obtain up to three separate computer monitors in order to conduct hearings in their homes.
Cintron said she anticipates the online-only format to continue into next year. Even once the crisis ends, she expects hearings to be a mixture of in-person and virtual.