NERC opened the new year with two big personnel announcements, introducing a new head of the Electricity Information Sharing and Analysis Center (E-ISAC) and saying farewell to retiring Trustee Dave Goulding.
Manny Cancel, who retired last month as chief information officer for Consolidated Edison, joined NERC on Tuesday as senior vice president and chief executive officer of the E-ISAC.
Manny Cancel | NERC
NERC said Cancel, who worked for Con Ed for nearly four decades, will lead the E-ISAC management team and be the center’s “key external face” before the Electricity Subsector Coordinating Council (ESCC), government and industry. He will oversee development of the revised E-ISAC Long-Term Strategic Plan.
Cancel has been active in the Member Executive Committee (MEC), an advisory group for the E-ISAC formed out of the ESCC.
“Having an executive of Manny’s stature and experience lead [the E-ISAC] is a rare and welcome opportunity,” NERC CEO Jim Robb said in a statement. “Over the last two years, the E-ISAC has built a strong foundation. … I know Manny will help us take it to the next level.”
Cancel, who has an undergraduate degree in management information systems from Baruch College and an MBA from Cornell University, serves on the advisory board of Per Scholas, a nonprofit that offers tuition-free technology training and professional development for individuals from “overlooked communities.”
Improving the capabilities of the E-ISAC is a key priority for NERC, which announced a five-year expansion plan in 2017. The center added nine full-time equivalent employees in 2019 and plans to add seven in 2020 and 14 through 2022. Its 2020 budget is almost $31.3 million, a 13.3% increase from 2019 and up from about $18.6 million in 2017.
NERC spokeswoman Kimberly Mielcarek said the revised E-ISAC strategic plan is “in the early phases” and is expected to be completed this year. “Manny and the ISAC team will work with the MEC on a timeline,” she said via email.
Cancel fills the spot that has been vacant since SVP Marcus Sachs, who formerly oversaw the E-ISAC, left NERC in December 2017. (See NERC Parts Ways with Chief Security Officer.)
Bill Lawrence took over day-to-day management of the E-ISAC with Sachs’ departure. Lawrence was promoted to vice president, chief security officer and director of the E-ISAC in August 2018.
Lawrence has apparently been away from NERC since at last October, when he was mysteriously absent at GridSecCon, E-ISAC’s annual conference. (See Robb Sees Calmer 2020 After ‘Turbulent’ Year.)
Lawrence is expected to return this month, Mielcarek said. “All I know is he took personal time off,” she said.
Search for Canadian Trustee
Meanwhile, NERC said it had begun a search for a Canadian trustee following the announcement that Goulding had retired from the Board of Trustees effective Jan. 1 after serving nearly a decade.
Goulding served as chair of the Northeast Power Coordinating Council for almost three years after retiring as CEO of Ontario’s Independent Electricity System Operator in 2006.
He graduated from the University of Bradford in England and worked in transmission and generation construction, operations, and maintenance with the U.K.’s Central Electricity Generating Board before its privatization in the 1990s.
At NERC, Goulding chaired the Enterprise-wide Risk Committee, and served on the Finance and Audit Committee and the Nominating Committee.
“Dave brought deep operational and management experience to all facets of the board’s work. He has been instrumental in revamping our Enterprise-wide Risk Committee, providing pivotal oversight of NERC’s corporate risk management program,” board Chair Roy Thilly said in a statement.
Goulding, who was traveling and unavailable for comment, said in a statement: “I will always be a proponent of the need for the unique approach NERC brings to assuring reliability of the grid.”
CARMEL, Ind. — MISO says it may reduce the capacity accreditation of some of its load-modifying resources in an effort to improve resource availability in its footprint.
Speaking at a Resource Adequacy Subcommittee meeting Wednesday, MISO planning adviser Davey Lopez said the RTO is considering basing an LMR’s accreditation on the smaller of either an average of its actual availability over a three-year period or its tested availability. LMRs that can respond more often and with shorter lead times will receive a larger capacity credit, he said.
Lopez noted that LMRs are currently “receiving capacity credit that’s disconnected from what we see in” the MISO Communications System (MCS). He said an LMR with a four-hour lead time that can respond to 20 calls during a planning year currently receives the same capacity credit as an LMR with an eight-hour lead time that can only respond the requisite five times per year. MISO is proposing that better-performing LMRs receive a higher capacity credit while slower LMRs with spottier service receive a percentage based on a still undetermined calculation in a loss-of-load expectation (LOLE) study.
“That’s the gap we’re trying to close here,” Lopez said, reminding stakeholders that the proposal is still a draft.
MISO stakeholders should expect an April filing with FERC to adjust LMR accreditation in some manner, Lopez said.
The changes are proposed as LMRs take an increasing slice of the RTO’s capacity supply. MISO has gone from clearing about 9 GW of LMRs in its Planning Resource Auction in 2017 to almost 12 GW in 2019. Lopez said that since the last PRA in April, LMRs’ daily availability on average is about 4 GW short of what was cleared, according to MCS self-reporting of availability.
Stakeholders: MCS Still Wanting
Multiple stakeholders asked why MISO would rely on MCS data when the stakeholder community has called navigation of the nonpublic MCS site clunky and confusing. They called for the RTO to reinvigorate a shelved effort to improve the MCS for its users. (See MISO to Fix Communications System Shortcomings.)
“This is now the second time you’ve come before us about LMRs. There was a filing last year on LMRs; now there’s going to be a filing this year. If LMRs are such a concern, then this MCS tool needs to get fixed, and the senior management needs to get on board with getting it fixed,” Customized Energy Solutions’ Ted Kuhn said, prompting nods of agreement from several stakeholders. “I continue to find that using MCS data is problematic.”
“I guess my response is that the MCS is our system of record,” Lopez said, adding that it’s undeniable that LMRs aren’t showing up as promised. “We want to give our operators the best information possible during emergencies. And right now, what’s clearing in the PRA is nowhere near what’s showing up in the MCS. … The accreditation should reflect that.” Lopez said LMR availability has become especially important given that MISO now experiences the possibility of an emergency in every month, not just the summer ones.
MISO LMRs’ self-reported availability versus amounts cleared in the capacity auction | MISO
Lopez said recent analysis shows LMRs’ uneven availability contributes to about a 2-GW increase in the planning reserve margin (PRM) requirement. Removing LMRs from the equation reduces the requirement from 136 GW to 134 GW for the 2020/21 planning year.
Kuhn suggested MISO create a separate class of better-performing LMRs for capacity auction purposes. “An LMR-plus, or something,” he said.
Independent Market Monitor David Patton has recently criticized MISO’s planning studies for still assuming that emergency resources are available to respond even when their long lead times preclude them from doing so. Patton said the problem remains that the RTO must first declare an emergency before calling up LMRs for dispatch.
MISO early last year promised to issue LMRs individualized scheduling instructions before an emergency occurs based on their unique notification times. It has also promised to confirm or withdraw advanced scheduling instructions at least two hours prior to an expected emergency event.
The LMR proposal is part of MISO’s resource availability and need project, a multistage endeavor divided into resource adequacy and market improvements.
While MISO’s Market Subcommittee focuses on possible market changes, including emergency pricing edits and providing market information in advance of the day-ahead market, the RASC is dissecting a possible seasonal PRA and new LOLE modeling and capacity resource accreditation. (See MISO Weighs Seasonal Capacity, Accreditation Plan.)
Lopez said the possibility of a seasonal auction is still on the table, though it will be discussed at later RASC meetings.
LOLE Refinements
MISO also used Wednesday’s meeting to unveil a proposal to model more real-world conditions in its annual LOLE study, encompassing more generation outage risk and intermittent resource behavior.
Lopez said MISO wants to use “more appropriate” wind generation and intermittent resource output levels that are based on unforced capacity values in non-summer months.
MISO is also proposing to combine 30 load shapes to create a more realistic outage pattern for a typical weather year and use the actual availability of its demand response resources to predict the likelihood that they’ll respond.
“If we plug these changes into the 2020 PRM model, it’s approximately a 1% increase to the PRM,” Lopez said.
The electrification of residential and commercial structures is receiving increased attention at the start of 2020.
The City Council of Bellingham, Wash., is weighing a proposal banning gas heat from all buildings, including existing structures. If it adopts the measure, the city of 90,000 would go a step further than Berkeley, Calif., which last year became the first city to ban natural gas in new construction.
California lawmakers announced a “green new deal” proposal Monday that calls for the state to accelerate its goals to reduce greenhouse gas emissions. Though still sketchy, the plan eventually could include building electrification mandates similar to those in proposals at the national, state and local levels in 2019. Los Angeles, for instance, adopted a plan last year that required city-owned buildings to become all-electric.
The city of Bellingham, Wash., is considering banning natural gas heating in all buildings.
The Rocky Mountain Institute, a nonprofit that advocates for clean energy, released a report Monday showing that two states — California and New York — are responsible for 18% of building emissions nationally. The report cited U.S. Energy Information Administration data.
Both California and New York have pledged to become carbon neutral by 2050, but reaching such ambitious goals is proving problematic. In stakeholder meetings and conferences over the past year, industry experts have expressed confidence that they can reduce carbon emissions by 80% in the next decade but eliminating the remaining 20% remains elusive.
Electrifying buildings is seen by many as a key to achieving at least a portion of those reductions, along with the electrification of the transportation sector and phasing out natural gas plants in favor of renewable resources.
Replacing traditional gas appliances such as water heaters with electric units is a key goal of electrification. | Edison International
“Across the U.S. economy, gas has now surpassed coal in its overall contribution to climate change,” the RMI report said. “With coal’s decline, electric-power sector emissions have fallen by a quarter in the past decade, but emissions from fuels burned in buildings has not budged.”
The bulk of those emissions, about 450 million tons of carbon dioxide annually, come from gas burned in buildings for heating and cooking, the report said.
“There is precedent for rapid change in this sector: In the 1940s, coal was the dominant heating fuel in U.S. homes, but by the 1970s, its share had fallen to below 5% of households, and it was virtually eliminated by the 1980s,” it said.
“Although gas was the primary replacement, electricity has gradually eroded gas’s share over the past several decades. The most recent data shows that 25% of U.S. households and 29% of commercial buildings are all-electric, up from 21% each over roughly a decade ago.”
Utilities, Environmentalists Aligned
Electrification of buildings is controversial for home and business owners, who don’t want to give up their gas cooktops or to make expensive upgrades. (Some cities, including Seattle, have begun offering financial incentives to switch to electric heat pumps.)
But it’s popular with utilities that see electrification as a major source of demand and revenue going forward. The Electric Power Research Institute estimated in mid-2018 that electrification of transportation and buildings could boost U.S. electric load growth by as much as 52% by 2050. (See State Regulators Hear Challenges, Promise of Electrification.)
Edison International, which owns Southern California Edison, released a report in April touting the benefits of building electrification.
“We confirm that the electrification of buildings represents an important opportunity to reduce greenhouse gas emissions from buildings both in the near term and long term, and can lead to consumer capital cost savings, bills savings and lifecycle savings in many circumstances,” the utility said.
The utilities’ views are in line with environmentalists, who laud the efforts of Berkeley and like-minded cities that want to do away with gas heating and cooking appliances.
“Climate-aware consumers and policymakers know too much is at stake to keep constructing new buildings that depend on an antiquated and polluting energy source, locking them into decades of higher costs and pollution,” Pierre Delforge and Merrian Borgeson, senior scientists with the Natural Resources Defense Council, wrote in a blog post Sunday.
“New buildings are the obvious place to start,” they said. “All-electric homes cost less and are faster to build than those heated with gas.”
VALLEY FORGE, Pa. — PJM officials said Wednesday that they won’t run a capacity auction until FERC approves the RTO’s compliance filing implementing the expansion of its minimum offer price rule (MOPR), making it unlikely the delayed 2019 auction will occur this year.
PJM must make a compliance filing by March 18 in response to FERC’s 2-1 ruling expanding the MOPR to all new state-subsidized resources.
“We do not plan to run a [Base Residual Auction] until we have an approval of that compliance filing. There’s so much at stake. … It is extremely risky for us to do that, and it’s a little bit too much risk for us to take on,” Adam Keech, vice president of market services, told the Market Implementation Committee during the first stakeholder meeting on MOPR since FERC’s Dec. 19 order. (See FERC Extends PJM MOPR to State Subsidies.)
PJM’s Pat Bruno indicated later that an auction before year-end was unlikely although it was “technically possible.”
Noting that FERC rejected most of PJM’s proposals, Keech also said the RTO is likely to file a request for rehearing or clarification of the order for its “procedural value.” Rehearing requests are due Jan. 21.
“We want to make sure we’re not marginalized in ongoing proceedings,” General Counsel Christopher O’Hara explained, highlighting the possibility that the order will be the subject of an federal appellate court proceeding.
“It’s going to be near impossible for the commission to accept the compliance filing without also granting at least clarification in part, and perhaps some of those clarifications cross over into rehearing,” O’Hara added. “I’m not talking major issues; I’m talking about some smaller issues.”
Wednesday’s meeting also marked the first public appearance by PJM’s new CEO, Manu Asthana, who began work last week. Asthana, who spoke briefly at the beginning of the MOPR discussion, said he and other board members want to incorporate stakeholder feedback in the compliance filing.
“We want to listen to … your perspective on the order: what it means for your business and what you want us to do about it,” he said.
Stakeholders: Resume BRA ‘ASAP’
The five-and-a-half-hour MOPR discussion also featured presentations by more than a dozen stakeholders who gave varying interpretations on the impact of the order and how PJM should respond.
Calpine — which filed the complaint that led to the commission’s June 2018 order finding the existing MOPR not just and reasonable — called for swift scheduling of the 2019 BRA. (See FERC Orders PJM Capacity Market Revamp.)
“There is nothing to debate. FERC issued its order, an order we have been waiting for over a year, and it’s time to proceed,” Calpine said. “Eighteen months have passed, and it is now PJM’s responsibility to hold the auction as soon as possible.”
FERC’s Dec. 19 order rejected most of PJM’s proposals on some key aspects of the MOPR expansion. | PJM
The PJM Power Providers group agreed, saying the BRA should be resumed “ASAP.” The American Petroleum Institute, which represents both natural gas producers and large energy users, called for “a timely restart” of the BRA “and a clear signal of future regular auctions.”
But American Municipal Power, which owns and operates generation, transmission and distribution for municipal utilities in nine states in PJM and MISO, said the RTO should seek an extension of the 90-day compliance filing deadline.
AMP said the additional time would allow PJM to use a “transparent” process to craft a response that could minimize further litigation and uncertainty.
Exelon said PJM should set the 2022/23 BRA about 12 months after the compliance order to allow state regulators and legislators time to make rule changes required if they decide to exit the capacity market and develop fixed resource requirements (FRR) as an alternative method of resource adequacy.
Exelon’s Jason Barker said PJM that must “offer a meaningful opportunity for states to consider and pursue alternatives” to the RTO’s capacity procurement.
“FERC has provided the states with a binomial choice for shaping the capacity mix to achieve their environmental goals: participate in the PJM capacity market — which does not value environmental attributes — or direct their utilities to establish an FRR.”
Jeff Dennis, general counsel for Advanced Energy Economy, whose members include renewable generators and companies providing demand response and energy efficiency aggregation, said it’s likely PJM will need to postpone the 2020 auction as it did the 2019 BRA. A former FERC official, Dennis told an AEE webinar on the MOPR ruling Wednesday: “We are likely many, many months away from a capacity auction.”
Condensing or shifting pre-auction activities must consider sequencing dependencies, PJM says. | PJM
Disagreement over RGGI
The speakers gave differing views on whether the commission’s definition of state subsidy would impact the resources of states participating in the Regional Greenhouse Gas Initiative.
Keech said PJM may seek FERC clarification on how RGGI and New Jersey’s Basic Generation Service (BGS) Electricity Supply Auction are impacted by the MOPR expansion.
In his dissent on the December order, Commissioner Richard Glick said the commission’s subsidy definition was likely to snare the BGS auction, in which electric distribution companies seek offers from resources to serve their load. That would require PJM and its Independent Market Monitor to “look behind the results of every BGS auction to determine which resources are receiving a benefit from this state process,” Glick said. “Even state processes that are open, fair, transparent and fuel-neutral may be treated as state subsidies, irrespective of the underlying state goals.”
“We’re not quite clear how those [programs] fit inside the … definition of a state subsidy,” Keech said. “Without more detail, it would seem like it would fall under state subsidy.”
Exelon said PJM’s compliance filing “should clarify that RGGI does not confer an actionable subsidy to any resources.”
Vistra Energy agreed, saying that although FERC’s subsidy definition is very broad, “we think it’s possible to implement it reasonably without implicating market-driven price outcomes” such as the RGGI carbon auctions.
The Advanced Energy Management Alliance said PJM should not consider DR as state-subsidized, saying “FERC precedent is to not include state peak shaving programs as subsidy.”
AMP made a similar pitch for the public power business model, citing what it called the “fallacy that tax-exempt financing constitutes a subsidy.” It called for a new stakeholder process to revise the RTO’s unit-specific exemption rules, saying PJM and the Monitor lack first-hand experience with the public power business model, “leading to incorrect comparisons of financing related costs for merchant projects and those available to not-for-profit public power organizations.”
The American Wind Energy Association and Solar Energy Industries Association said the unit-specific exemption process “must be flexible so all resource types … reflect their actual project costs, operations and projected revenues” and not be based solely on criteria used for setting the net cost of new entry for gas-fired generation.
Impact on Renewables, RECs
There also was discussion on FERC’s ruling to not differentiate voluntary renewable energy credits (RECs) from state-mandated RECs and disagreements over the impact the ruling will have on future renewable resources.
FERC said that although it saw no need to apply the MOPR to “voluntary, arm’s length bilateral transactions … it is not possible, at this time, to distinguish resources receiving privately funded voluntary RECs from state-funded or state-mandated RECs because resources typically do not know at the time of the auction qualification process how the REC will be eventually used.”
Vistra said voluntary RECs should not be considered subsidies. The company said it backs its renewable energy retail products with more RECs than needed to comply with state mandates. “MOPRing these purchases will mean that it is more expensive to offer these ‘green’ products to our customers, there will be fewer low carbon resources to source from than robust market dynamics alone would support, and there is an efficiency loss.”
Lightsource BP, a utility-scale solar developer with more than 1 GW of projects in the PJM interconnection queue, said voluntary RECs should not be considered state subsidies because they are a separate market from mandated RECs and trade at a fraction of solar compliance RECs.
It said vintage 2020 voluntary RECs are currently trading at 50 cents to $1/MWh, while solar RECs in New Jersey are worth about $227.50/MWh, $80/MWh in Maryland and $40/MWh in Pennsylvania. “As such, estimated project revenues from voluntary REC sales pale in comparison to estimated project revenues from state compliance RECs and should not be considered material,” Lightsource said, adding that PJM should mandate that capacity sellers use REC tracking systems to provide transparency to address FERC’s concerns.
“Forecasted PJM capacity market revenues are an integral component of PJM solar financeability, and a majority of the 1 GW in our PJM portfolio is at risk for being priced out of the capacity market auction,” Lightsource said.
But LS Power said the order would not impact its investments in intermittent resources because they don’t rely on the capacity market for significant revenues. It noted that wind and solar resources comprise only 1.2% of PJM’s capacity requirement. It said a 10-MW solar plant in New Jersey would see 80% of its revenues from RECs ($3 million), with energy market revenues contributing another $500,000 and capacity revenues adding only $250,000 (6.7%), assuming the market clears at $150/MW-day.
“Capacity is not the driving revenue stream for investment the way it is for other units needed for reliability that are dispatchable and flexible,” LS Power’s Marji Philips said. “PJM’s responsibility is making sure that plants that do rely on the competitive market that PJM also relies on for reliability have the appropriate price signals.”
Eliminate Capacity Market?
The Natural Resources Defense Council’s Sustainable FERC Project said the MOPR ruling “threatens to make PJM irrelevant” to states’ efforts to reduce carbon emissions.
It noted that 10 of PJM’s 13 states and D.C. have renewable portfolio standards, with D.C., Maryland and New Jersey having set or proposed 100% clean power goals, while three have laws supporting nuclear power.
“PJM should request rehearing and, if denied, seek appellate review of the MOPR order,” it said.
It also said PJM’s planning parameters should be changed to reflect the reliability value of uncleared capacity and that the RTO should ultimately retire the capacity market and develop an alternative resource adequacy structure.
PJM said it would post answers to stakeholders’ questions and hold a second stakeholder discussion on the ruling on Jan. 28. Questions can be submitted to RPM_Hotline@pjm.com.
ISO-NE on Wednesday askedFERC to approve a limited Tariff waiver that would allow market participants to adjust or withdraw their retirement or permanent delist bids for Forward Capacity Auction 15, which are due March 13.
In seeking the flexibility for its participants, the RTO noted the potential for its Energy Security Improvements (ESI) market design to change after the submission deadline.
FCA 15 covers the capacity commitment period beginning June 1, 2024, when the grid operator now intends to implement ESI.
The 680-MW Pilgrim nuclear plant in Plymouth, Mass. | NRC
ISO-NE said that if FERC grants the waiver, retirement bids will remain due March 13 and that the waiver would apply in the event the RTO makes a non-clerical change to the ESI market rules, in which case a participant could either update or withdraw its delist bid.
“It is very possible” that the RTO will not have completed the market design and Tariff revisions for ESI by the existing capacity retirement deadline, it said in its request.
The Markets Committee will likely take an initial vote on ESI before March 13, but the design may evolve further before a final vote by the full NEPOOL Participants Committee is taken on or around April 2, 2020, the RTO said.
“Should this occur, the delist bids might not accurately reflect the impacts of the ESI market rules, in the form in which the rules are filed with the commission on April 15, 2020,” it said.
State regulators from the SPP and MISO footprints continue to discuss opportunities to contribute to the RTOs’ transmission planning analysis, Adam McKinnie, chief regulatory economist for the Missouri Public Service Commission, told the Seams Steering Committee on Tuesday.
McKinnie, who also serves as a contact between regulatory staff and the SPP Regional State Committee and Organization of MISO States’ Liaison Committee, said commissioners are interested in whether larger projects could resolve reliability issues along the seams.
“They’re trying to figure out if there’s a role for states to play in encouraging wider solutions, rather than each RTO solving its own reliability problems,” McKinnie said.
SPP and MISO have taken three stabs at interregional projects but have failed to agree on a single solution.
The Liaison Committee, composed of regulators from both footprints, commissioned SPP’s Market Monitoring Unit and MISO’s Independent Market Monitor to analyze seams issues. The MMU produced a MISO, SPP Regulators Nibble Away at Seams Issues.)
The regulators have sought stakeholder feedback to a series of questions on the two studies. McKinnie assured the SSC that the responses are read. “That’s why we tried to provide ‘kitchen-sinky’ questions,” he said.
The Liaison Committee will hold a conference call Jan. 13 to discuss responses to the monitors’ reports. It will also meet Feb. 9 during the National Association of Regulatory Utility Commissioners’ Winter Policy Summit in D.C.
M2M Settlements Reach $68.1M in SPP’s Favor
SPP earned more than $870,000 in market-to-market (M2M) payments from MISO during November, cracking $68 million in favorable settlements since the process began in 2015.
Permanent flowgates were binding for 315 hours and more than $878,000 in SPP’s favor. Temporary flowgates were binding for 813 hours and more than $7,848 in MISO’s favor.
November market-to-market summary | SPP
Staff’s Will Ragsdale said two permanent flowgates along the Kansas-Missouri border — “our old friend,” the 161-kV Neosho-Riverton, and the 161-kV Moberly-Overton — accounted for more than $809,000 in M2M settlements to SPP. The Neosho-Riverton flowgate has racked up more than $30 million in settlements, four times the second-most constrained flowgate.
SPP has realized $68.1 million in M2M settlements since the two RTOs began the process of using the RTO with the most economic dispatch to address market flows. Staff are reviewing flowgates in western North Dakota to determine allocated property rights, or firm-flow entitlements, on M2M constraints and also comparing allocated M2M settlements with LMPs in market settlement areas.
Committee Reviews 2019, Preps for 2020
Committee members spent much of the meeting discussing the group’s organizational effectiveness, based on SPP’s annual stakeholder survey results. A suggestion to hold quarterly meetings because of a lack of voting items went nowhere.
Members also reviewed their 2019 accomplishments — including oversight of the MISO-SPP coordinated system plan improvements and study — and major pending issues. The latter includes joint studies with MISO and Associated Electric Cooperative Inc.; identifying the administrative processes that lead to inefficiencies between the SPP and MISO markets; and continued pursuit of coordinated projects to address historical M2M congestion between the RTOs.
Staff are working to set up SPP’s annual issues-review meeting with MISO, tentatively scheduled for March 10.
Dominion Energy might have finally met a “bill” it does not like.
Virginia delegates on Tuesday announced a bipartisan bill that would end the electric market monopoly in the state, allowing consumers to choose their electric provider and requiring distribution utilities to divest their generation. The legislation takes aim at Dominion, which serves two-thirds of the state’s consumers, and which the state Corporation Commission says has overcharged customers by $1.3 billion since base rates were frozen in 2015.
The bill was announced at a press conference by Del. Mark Keam (D–Vienna) and Del. Lee Ware (R–Powhatan) and endorsed by groups including the conservative R Street Institute and anti-poverty group Virginia Poverty Law Center. It’s the latest sign that Dominion will face tougher scrutiny from state lawmakers than it has in the past.
In December, Ware joined another Democrat in introducing a bill to reverse the General Assembly’s decision to freeze base rates for seven years, a change Dominion claimed it needed to ensure it could fund carbon emission reductions under the Obama administration’s Clean Power Plan. The CPP was cancelled by the Trump administration, which has proposed much less stringent regulations. (See EPA Finalizes CPP Replacement.)
Del. Mark Keam | Virginia Energy Reform Coalition
“Over the past couple of decades, innovation and technological advancements have allowed consumers around the nation to choose when, where and how they obtain affordable and reliable energy. But in Virginia, we are stuck with a century-old business-as-usual model that benefits monopolies while suppressing competition and consumer choice. It’s time to reform the rules of the road,” said Keam. “We are done and are tired of ‘business-as-usual.’”
Under the current system, monopolies such as Dominion and Appalachian Power own and operate all segments of the state’s vertically integrated system, including generation, distribution and retail services. The bill announced Tuesday, which is set to be discussed in the 2020 General Assembly, would:
Establish a competitive market for electricity retailers to allow customers to shop on price or on environmental attributes (e.g., renewable energy);
Establish a nonprofit independent entity that has no financial stake in market outcomes to coordinate operation of the distribution system;
Remove existing interconnection and financing barriers to customer-owned energy resources; and
Add additional consumer protections and education to ensure smart energy choices.
Dominion and American Electric Power, parent of Appalachian Power, did not immediately respond to requests for comment.
“This legislation, which I trust will gain broad bi-partisan support, will chart a course toward engendering much-needed competition in the retail sales of vital electricity services,” said Ware. “This is a time of new opportunity.”
Keam and Ware claim Virginians have the seventh-highest electricity bills in the country. The utility has had its rates frozen since 2015 when the then Republican-led General Assembly removed state regulators’ ability to review base rates and set profit levels.
“It wasn’t until the rate freeze of 2015 that I came to the realization that this is really bad and really wrong. But only a handful of us said, ‘Why are we doing it this way?’ And the answers weren’t adequate,” Keam said. “So, from that point on until last year when we had that big fight over grid modernization, I think that’s awoke a lot of peoples’ understanding that we don’t have to take this.”
Dominion has long been one of the biggest political contributors in the state, having donated about $1.8 million in 2018-19 and $7.1 million since 2010, according to Virginia Public Access Project. In the past, most of the donations went to Republicans. In the most recent cycle, however, the utility donated slightly more ($949,000 to $870,000) to Democratic candidates.
Dominion Energy headquarters in Richmond, Virginia | Timmons Group
But most Democratic legislative candidates agreed last year to reject funds from Dominion and made their opposition to the utility part of their campaigns. Nearly 50 of the 61 candidates that rejected Dominion money won their elections in November. With that, the Democrats took the majority in both the House and the Senate. The state’s governor also is a Democrat.
The bill proposed Tuesday is being backed by the Virginia Energy Reform Coalition, a group formed last year that includes both environmental organizations (Appalachian Voices, Clean Virginia and Piedmont Environmental Council) and right-leaning free market organizations (R Street Institute, Reason Foundation and Virginia Institute for Public Policy).
Devin Hartman, the director of energy and environmental policy at the R Street Institute, said the time is now for Virginia to embrace innovation.
“Virginia is shackled to a monopoly utility model that stifles innovation, increases costs and puts government in the difficult role of replacing competition,” he said. “It’s time for Virginia to liberate market forces, empower consumers and shift the role of government to facilitate competition. Competitive markets are the path to an innovative and consumer-friendly clean energy future. It’s time for Virginia to make the right choice.”
Pioneer Transmission can recover about $10 million in precommercial operation costs used to develop a high-voltage transmission line in Indiana, FERC decided last week.
The joint venture of Duke Energy and American Electric Power incurred the costs March 2009 through Dec. 31, 2019, while planning and constructing the $347 million, 765-kV Greentown-to-Reynolds transmission line between Kokomo and Reynolds, Ind. FERC approved Pioneer’s October filing to include the asset in its formula rate on Dec. 31 (ER20-159).
However, the commission also told the transmission company it must update its capital structure from the hypothetical 50% debt and 50% equity to the 2018 year-end actual of approximately 51.1% debt and 48.9% equity.
The 70-mile Greentown-to-Reynolds project is the first segment of the $1 billion, 290-mile Greentown-to-Rockport line that has been in the works for more than a decade. The completed line is expected to traverse MISO into PJM. Pioneer began construction on the segment in 2013 and finished work in June 2018; the segment is one of the 17 multi-value projects MISO approved in 2011.
The Greentown-to-Reynolds line | Duke Energy
In a related order issued the same day, FERC also denied Pioneer’s request to rehear its first request to amortize and recover the precommercial operation costs of the Greentown-to-Reynolds line (ER18-2119).
Pioneer first filed to recover precommercial operation costs in July 2018, but the commission rejected the filing without prejudice a year later, finding that the company included a 150-basis-point return on equity adder for new transmission in its carrying charges. FERC had previously said in 2009 that Pioneer could not receive the adder unless the project was approved by both MISO and PJM. Pioneer has not yet obtained PJM approval for the project. (See FERC Lowers ROE for Segmented Pioneer Tx Project.)
Pioneer said FERC should revisit the decision because the commission did not act within the 60-day period prescribed by the Federal Power Act, thus making the filing legal on Sept. 30, 2018.
But FERC said Pioneer’s regulatory asset filing was not properly filed electronically and therefore was not subject to a statutory action date.
“If we were to vacate the commission’s rejection of Pioneer’s filing in this docket as Pioneer requests, it would be permitted to accrue an unauthorized 150-basis-point ROE adder to its regulatory asset carrying charge and thus profit through its own failure to comply with the commission’s filing regulations,” FERC explained, pointing out that Pioneer was able to submit its October filing correctly.
“Evolutionary, not revolutionary,” Southwest Power Pool executives like to say about their RTO. It’s written into SPP’s corporate culture, the idea being that it takes time “to do the right thing, for the right reason, in the right way every time.”
The RTO’s emphasis on continuity will be tested in 2020, however. By midyear, SPP will be without five of the key figures who have helped expand the grid operator’s footprint into 17 states and implement a day-ahead market. Former Board of Directors Chair Jim Eckelberger and Directors Harry Skilton and Phyllis Bernard left the board at year-end after having served together since 2003. COO Carl Monroe will follow them out the door after January.
Come April, CEO Nick Brown, who joined the RTO 35 years ago as employee No. 7, will retire. SPP, having identified both internal and external candidates, says it is on track to announce his replacement during January’s board meeting in Santa Fe, N.M. (See SPP’s Brown to Retire as CEO in 2020.)
Larry Altenbaumer replaced Eckelberger in January 2019, seeking to place his own stamp on the RTO by shortening board meetings and focusing them on strategic discussions with members and the Regional State Committee. In addition to taking over the chairmanship of the Strategic Planning Committee, he also headed the Affordability and Value Task Force, which identified “meaningful opportunities to enhance other aspects of performance.” (See SPP Value Group Finds No ‘Silver Bullets’.)
Dennis Florom, manager of energy and environmental operations for Lincoln Electric System, said that as SPP grows in size and membership, “it gets more difficult to keep things member-driven,” referencing the RTO’s preference to serve as advisers to members.
“This is what sets SPP apart, and SPP prides itself on that. The new CEO will need to work with the board to make sure that SPP maintains its identity and that members continue to set the direction as forks in the road present themselves,” Florom said.
SPP’s expansion into the Rockies and beyond has already reached the crossroads.
In early December, the RTO became the reliability coordinator for 15 Western Interconnection utilities, representing about 12% of the region’s load. (See Westward Ho: SPP Now a Western RC Provider.) However, shortly thereafter, SPP’s ambitions to run an energy market in the Western Interconnection took a hit with news that Colorado’s largest utility (Xcel Energy) and three others chose CAISO’s Western Energy Imbalance Market over its own competing market offerings. (See EIM Lands Xcel, 3 Other Colo. Utilities.)
The RTO is still plugging ahead with its Western Energy Imbalance Service, which is scheduled to go live in early 2021. Two additional utilities, Municipal Energy Agency of Nebraska and Wyoming Municipal Power Agency, have announced they will join the five that signed contracts in September to fund WEIS’s development: Basin Electric Power Cooperative; Tri-State Generation and Transmission Association, and three Western Area Power Administration entities, Colorado River Storage Project; Rocky Mountain Region and Upper Great Plains. (See SPP Board OKs $9.5M to Build Western EIS Market.)
“Discussions continue with other interested parties, but no additional contracts have been signed at this point,” SPP spokesman Derek Wingfield said.
CAISO’s EIM, which currently has nine members, is expected to grow to 23 by the end of 2022.
Competing for Load
In the meantime, there’s plenty for the grid operator and its members to chew on. The explosive growth of renewable energy shows no signs of easing. Wind farms and, more recently, solar installations and energy storage, continue to add more energy than SPP — with a reserve margin of around 25% — knows what to do with.
SPP set a new wind peak record of 17,861 MW on Dec. 11, breaking a mark set two months earlier by 266 MW. In the early-morning hours of Oct. 9, the RTO produced 73.67% of its energy from wind, hydro and other non-fossil resources, fulfilling predictions a year before that it would reach the 70% threshold.
Florom said that a peek at the generation interconnection queue “shows a level of renewables that SPP load can’t handle.” The RTO had more than 22 GW of installed wind capacity as of October, with more than that in the queue.
Florom suggested storage and new transmission could “present opportunities for addressing more renewables.”
“Tariff changes and working with other entities outside of SPP to export these renewables are ways that SPP can address this challenge in ways that might benefit everyone,” Florom said.
But exporting energy could require additional transmission construction, which comes with a cost. Altenbaumer is keenly aware that members are still digesting the $10 billion in transmission construction and upgrades over the previous decade.
“The big concern [stakeholders] have is what happens with the next wave of transmission projects and making sure they pass a very tight metric to provide value,” he said in November.
Some of the answers may lie in the implementation of the Holistic Integrated Tariff Team’s recommendations. (See SPP Board Approves HITT’s Recommendations.) State regulatory staff are working on some of the key recommendations, including creating larger transmission pricing zones and sub-zones; evaluating the byway facility cost allocation review process; and evaluating cost allocation and rates for storage devices classified as transmission assets.
Other stakeholder groups are working on an uncertainty market product, improvements to the day-ahead market — including a multiday, longer-term market product — and establishing uniform local planning criteria within the Tariff’s Schedule 9 pricing zones.
SPP’s staff take a deeper view into the future. During a Strategic Planning Committee meeting in November, Senior Engineering Vice President Lanny Nickell said the RTO and its stakeholders should be “thinking about” competition between RTOs and keeping its own load while competing for other loads.
“How do we compete, as a region, for loads that love the renewable resources and [their] low prices?” he asked. “They’re looking for opportunities to add warehouses and data centers. How do we compete for those?”
“Given concerns with costs, we can’t afford to lose much load as we calculate administrative costs and move forward in a world that is changing rapidly,” said Bruce Rew, senior vice president of operations. “We can’t afford to lose megawatt one.”
Change is coming. Whether it’s evolutionary or revolutionary, a new cast of characters at the top will be the ones to address it.
PJM last week sent members directions on how to file claims against the $5 million fund established in the GreenHat Energy settlement just days after FERC accepted the terms of the agreement.
In October, PJM filed its plan with the commission to pay two trading firms $12.5 million to settle claims of economic harm that resulted from the RTO’s decision to not liquidate GreenHat’s entire 890 million MWh portfolio of financial transmission rights during the 2018/19 planning period (ER18-2068).
After the company defaulted in June 2018, PJM reran only the July FTR auction — a decision the RTO says kept costs to members down and avoided a cascade of market violations that would increase uncertainty for years to come. (See PJM to Pay $12.5 million to Settle GreenHat Dispute.)
GreenHat’s significant growth in exposure and MTA loss | PJM
As part of the settlement, members agreed to fund a separate account that would pay out additional claims if PJM’s analysis verified those market participants also suffered economic harm. If PJM discovers instead that a claimant benefited from prior actions, it will owe a fee equal to 50% of the amount of the benefit. The RTO said in October that it doesn’t expect additional claims, based on the limited protest filings it received during the proceeding.
In its email to members Thursday, PJM directed potential claimants to submit an email to FTRPayeeFund@pjm.com with “Payee Fund Claim” in the subject with the name of the market participant in the body of the email on or before Feb. 1. Claimants should not include a dollar amount for which the market participant was harmed.
PJM said it will notify claimants by Feb. 10 of the harm or benefit for the market participant and what amount will be credited or charged, respectively, to its monthly billing statement following the notification.
