MISO’s Board of Directors has three seats up for grabs in December, though the new board is only guaranteed one new face.
The RTO’s Nominating Committee advanced current Directors Theresa Wise and Robert Lurie for member consideration, along with newcomer Jody Davids. Formerly chief information officer for PepsiCo, Davids has also served as CIO for Agrium, Best Buy and Cardinal Health. She currently sits on the board for Premier, a Charlotte, N.C.-based health care improvement company.
Jody Davids | Premier
Wise and Lurie are both rounding out their first terms and applied for reappointment. Lurie served the one-year remainder of former Director Thomas Rainwater’s term, which expires at the end of December.
Longtime Director Baljit Dail will not make a reappearance at MISO’s U-shaped board table next year. Dail spent 12 years on the board — three more than technically allowed — through a special waiver that allowed him an extra term so the board could retain a person with technology expertise.
MISO’s 139 voting-eligible members can begin casting ballots for candidates beginning 8 a.m. Thursday. The electronic polls will close at 5 p.m. Oct. 30. Board elections require a minimum 25% participation rate to achieve quorum.
Members can vote for or against any of the candidates, or abstain. Candidates must earn a majority of votes cast to be installed. MISO will announce election results in mid-November.
The board voted unanimously during its Sept. 17 meeting to retain Phyllis Currie as its chairman in 2021.
FERC ruled last week that generating facilities that are not online and producing energy must pay for their station power at retail rates subject to state jurisdiction and directed PJM to consider changing its Tariff accordingly (EL20-30).
The commission said an offline generator that requires power to operate its lighting, air conditioning and other facilities “is consuming electricity as an end user and thus, consistent with the boundaries of the commission’s jurisdiction under the [Federal Power Act], the provision of station power is a retail sale subject to state jurisdiction.”
The commission’s ruling came in response to a complaint filed by Lawrenceburg, Ind., and the Indiana Municipal Power Agency against the RTO, American Electric Power Service and Lawrenceburg Power seeking to void the power self-supply monthly netting provisions of the RTO’s Tariff.
The city’s Lawrenceburg Municipal Utilities has an exclusive franchise for supplying electricity within city limits and says Lawrenceburg Power’s 1,160-MW combined cycle plant in the city must take station power service from the city because Indiana law does not allow it a choice of retail supplier. The plant is interconnected with AEP transmission facilities under PJM’s operational control.
FERC approved the netting rules in 2001, saying station power can be supplied to a generating plant in three ways: on-site self-supply (from behind-the-meter generation); remote self-supply (from another generator owned by the same company); or third-party supply.
| Lawrenceburg Municipal Utilities
While the commission disclaimed jurisdiction over the supply of station power, it rejected the petitioners’ request for a declaratory order finding the station power monthly netting provision in section 1.7.10(d)(i) of the PJM Tariff null and void.
Instead, FERC instituted a new proceeding, requiring PJM to propose changes to its Tariff consistent with the order or show cause why changes are not necessary (EL20-56). The RTO has 60 days to respond.
FERC said PJM’s proposed revisions should clarify that the monthly netting provision in section 1.7.10(d)(i) “does not determine whether a retail sale of station power has occurred in that month.” It also said Tariff provisions should clarify that PJM has no responsibility for the determination of any state-jurisdictional retail rates.
“Because the PJM Tariff’s self-supply monthly netting provision can be read to — and indeed has been relied on by certain PJM generators to assert the right to — determine whether a retail sale of station power has occurred and avoid the retail purchase of station power, which is inconsistent with the commission’s jurisdiction, we find that PJM’s Tariff may be unjust, unreasonable, unduly discriminatory or preferential,” FERC said.
Lawrenceburg Power told FERC that Lawrenceburg Municipal Utilities has attempted to charge the generator a minimum of $845,000 annually “even if Lawrenceburg Power does not consume any station power in the entire year” and that it prefers self-supplying its station power under the PJM Tariff.
“Arguments about the justness and reasonableness of the retail rates, and about what entity within the state of Indiana has authority to provide retail service, are more appropriately raised before the relevant state regulatory body,” FERC said. “The commission does not have the authority to determine when, and on what terms, a retail sale of station power is made.”
The ruling is likely to have impacts on other merchant generators.
Among the intervenors in the case were Buckeye Power, which said it and one of its member cooperatives, Washington Electric Cooperative (WEC), are involved in a dispute with Waterford Power, a merchant generator located within WEC’s service territory, regarding WEC’s right to supply Waterford’s station power.
The standard drafting team (SDT) working on revising NERC reliability standards CIP-004-7 (Cybersecurity — Personnel and training) and CIP-011-3 (Cybersecurity — Information protection) will review the latest round of comments on the proposed changes in hopes of submitting them for approval this year. (See NERC Opens Comments on Standards Plan.)
NERC posted the standards for comment on Aug. 9, along with planned reliability guidelines on winter weather readiness and supply chain procurement. (See “Project 2019-02 Nears Completion,” Reliability Guidelines, Standards Posted for Comment.) Respondents were asked whether they agree that:
the revisions to CIP-004-7 properly clarify the requirements for managing provisioned access to bulk electric system cyber system information (BCSI) when using third-party solutions such as cloud storage services;
CIP-004-7 explains clearly that entities are only required to manage physical access to physical BCSI and electronic access to electronic BCSI;
CIP-011-3 explains the protections expected when using third-party solutions; and
the 18-month implementation plan proposed by the SDT is reasonable.
The results of the industry ballot that accompanied the comment period are not available yet, but SDT members have indicated they expect stakeholders to ultimately approve the revisions. However, the comments indicate there are some kinks to work out before industry gets fully on board with them.
Concern over Ambiguous Access Terms
Regarding the first question, a number of commenters complained about the insertion of the term “provisioned access” in CIP-004-7 without a definition. Anthony Jablonski of ReliabilityFirst asked that the term be either defined in the standard or removed entirely lest it “lead to misunderstanding [and] inconsistent audit results.”
“If you take ‘provisioned access’ to mean only intentionally created individual accounts, then administrative access to BCSI will not be governed by any standard,” Jablonski warned.
In a comment endorsed by several other stakeholders, Mark Gray of the Edison Electric Institute noted that a requirement to “authorize provisioning of access to BCSI based on need” is ambiguous and could be read to mean that entities are required to authorize access by anyone who asks, or have no discretion over which information can be accessed. He suggested that the phrase “process to” be added to the requirement, to clarify that each entity is responsible for defining its process for granting access.
| Shutterstock
Ambiguity was also a problem for respondents to the second question, with an anonymous commenter representing the Tennessee Valley Authority objecting that the “proposed language is too ambiguous and obligates entities to protect BCSI in any form, even [those] beyond [their] control.” For example, utilities could be held responsible for access to information being held by FERC or NERC. The commenter recommended that the language be “rescoped” to focus on managing access to information repositories, rather than the data themselves.
Mark Ciufo, writing for Hydro One Networks, also criticized the requirement for lack of clarity, observing that the standard “only [requires] managing physical access to BCSI,” while not explicitly stating that electronic access should be managed as well. Bruce Reimer of Manitoba Hydro agreed, pointing out that the standard’s requirements around the provisioning of physical access also seem inconsistent.
“If all unencrypted BCSI [is] stored on a server, does the server need to have authorized physical access? Obviously, the answer is ‘yes,’” Reimer said. “However, if using the provisioned access language, the BCSI server physical access control would be ignored. The provisioned access to BCSI is not clear.”
General Agreement on Cloud Services
Responses to the question about CIP-011-3 generally agreed that the most recent revisions “add clarity for protections expected when utilizing third-party solutions such as cloud services for storage purposes,” in the words of Jonathan Robbins of Seminole Electric Cooperative. However, many commenters felt the language could still be made more specific; for example, Jablonski and Russel Mountjoy of Midwest Reliability Organization called for the SDT to ensure that terms such as “data governance” and “data sovereignty” are fully defined in the text.
The 18-month implementation time frame likewise received widespread support, though some commenters supported a longer span: Richard Jackson of the U.S. Bureau of Reclamation called for a 24-month deadline, while TVA requested an extension to 36 months. By contrast, Jablonski said the revised standard would create “no significant new compliance requirements” and that, therefore, a six-month window would be more appropriate.
NRG issued a notification indicating that the plant will shut down on Dec. 20 but will be available for annual seasonal operations between June 1 and Sept. 30. ERCOT market participants have until Oct. 12 to file comments on any possible reliability effects from the suspension.
Operations at the plant have been suspended since May 1. NRG cited the global economic downturn and the low price of oil.
NRG intends to mothball its Petra Nova carbon-capture project. | NRG Energy
The plant, which has a summer capacity of 71 MW, was retrofitted at a cost of $1 billion to capture carbon from one of the nearby W.A. Parish Generating Station’s coal-fired units. Post-combustion carbon-capture technology reduces Petra Nova’s carbon emissions by 90%. The captured carbon is funneled through an 80-mile pipeline to a nearby oil field.
Petra Nova became operational in December 2016, on budget and on schedule. NRG said the plant delivered more than 1 billion tons of captured CO2 within its first 10 months. Power Engineering honored the project in 2017 as its Coal-Fired Project of the Year. Industry analysts don’t expect the plant to return to operation until oil prices stay consistently above $50 or $60/barrel.
Despite the project’s carbon-capture pedigree, NRG has remained a target of environmentalists. Chrissy Mann, the Sierra Club’s Beyond Coal Campaign representative, said that even when the Petra Nova project was operational, the Parish facility was the No. 1 source of particulate matter and No. 2 source of sulfur dioxide in the state of Texas.
“As NRG seemingly ends its carbon-capture project, NRG needs to take steps to address its dangerous air and water pollution,” Mann said. “It definitely makes economic sense that NRG is moving away from this continued investment in coal.”
With SPP stakeholders unable to reach consensus on how to modify the RTO’s congestion-hedging practices, the Strategic Planning Committee has taken matters into its own hands and will see if it can come up with a solution.
At issue is the Holistic Integrated Tariff Team’s recommendation last year to add counterflow optimization (CFO), limited to excess auction revenues, to SPP’s market mechanism that hedges load against congestion charges. (See SPP Board Approves HITT’s Recommendations.)
The Market Working Group took up the charge, reviewing 11 different proposals, including the status quo. Seven of those received support from either the RTO, the MWG or the Market Monitoring Unit, but not enough to reach consensus. The remaining four proposals were not supported by anyone.
“We’ve been informed by the MWG that, while [it] worked diligently to address this issue, [it] has concluded [it] can’t bring specific issues back to the table with broad-based support,” SPP Board of Directors Chair Larry Altenbaumer said during a Sept. 16 meeting of the Strategic Planning Committee, which he also chairs.
“My sense is we may be at a point where rather than trying to put this forward for an immediate answer,” he said, “we have a chance to step back and take an overall assessment before stepping forward.”
To do so, Altenbaumer will be relying on Director Graham Edwards, who served on the HITT; Dogwood Energy’s Rob Janssen, who was the team’s vice chair; and NextEra Energy Resources’ Holly Carias, who chairs the Markets and Operations Policy Committee. Altenbaumer told the SPC that he has asked the three to further study automated counterflow. They will be assisted by SPP staff and receive input from the MMU.
Altenbaumer said the group’s only charge is to maintain the HITT’s recommendation. They are to present their findings to the board and MOPC in January.
“If the sense is we come back and say the status quo is unbalanced, that’s an OK answer. If they say it’s good for now, that’s an OK answer,” Altenbaumer said. “This situation is not unique to SPP. At least one other RTO is working through this process at the same time. Whatever can be gained in conversations with them can be a benefit to us as well.”
SPP’s current congestion-hedging practice is to allow market participants to nominate counterflow on a voluntary basis. Because it is a charge, participants are less likely to nominate, staff said.
The grid operator has been working since 2016 with participants, who are split over the system’s effectiveness, on changes to the market design. SPP supports automated counterflow to solve the current practice’s inequity, while the MMU said it is supportive of the status quo only over a solution that uses CFO.
The Monitor broke down the various proposals into two boxes: those using CFO and those not. In the former category, American Electric Power put forth a pre-auction, direct assignment of counterflows with opt-in/opt-out flexibility, while Oklahoma Gas & Electric suggested earmarking CFO dollars from the previous year, with the CFO method to be determined later.
SPP’s MMU says automated counterflow may not benefit load-serving entities. | SPP Market Monitoring Unit
In the non-CFO bucket, Nebraska Public Power District proposed partially modifying the excess auction revenue distribution method. The MMU opted for a more-than-partial modification of the revenue.
“Without addressing the underlying issues, the MMU believes the solutions being discussed today are really treating the symptoms,” the Monitor’s John Luallen said. “They have little to do with congestion patterns. They all represent a redistribution of congestion-hedging revenues between participants.”
Luallen said all congestion-hedging products derive their value from the day-ahead market’s congestion rent, which is unchanged by automated counterflow. He warned that the HITT’s proposed framework creates risk because load-serving entities, as a whole, will receive less revenue than they would without the counterflow.
Two factors determine whether automated counterflow creates value for LSEs, Luallen said: the change in the congestion rent received, net of cost, and the change in the auction revenue received.
Altenbaumer agreed with Luallen, saying both proposal categories “may be trying to address the symptoms rather than the underlying issues.”
“My desire is to come up with a solution that creates greater overall value or a situation or outcome that produces better efficiency in our markets or creates greater overall fairness in our market,” Altenbaumer said.
The elimination of coal-fired electric generation means that New York’s battle against climate change must now focus on natural gas, Columbia Law School’s Michael Gerrard told the Independent Power Producers of New York (IPPNY) in the keynote address at the organization’s 35th annual Fall Conference last week.
Michael Gerrard of Columbia Law School delivered the keynote address at the 35th annual IPPNY Fall Conference on Sept. 15. | IPPNY
“Far and away the largest source of greenhouse emissions in New York state is natural gas, and more of it comes from electricity production than anywhere else,” said Gerrard, a member of the Climate Leadership Council (CLC) and the founder of Columbia’s Sabin Center for Climate Change. “This is a blinking red light.”
The state’s last coal-fired generator, the Somerset plant on Lake Ontario, ended production in March. But while New York has banned fracking within its borders, more than half of its generating capacity is at natural gas-fired power plants, and a recent study concluded that its GHG emissions in 2015 were virtually unchanged from 1990 levels when considering upstream impacts and the role of methane from drilling sites producing the state’s fuel. Methane is about 80 times as potent at trapping heat as CO2 in its first 20 years. (See NY Study Highlights Rising Methane Emissions.)
“The climate reality is that global temperatures will continue to go up until we achieve net-zero [GHG] emissions,” said Gerrard, who spoke in place of his friend and colleague, CLC founder and CEO Ted Halstead, who had died in a hiking accident in Spain the previous week.
Economywide Carbon Tax?
The CLC’s 2017 climate change proposal called for an economywide fee on CO2 emissions starting at $40/ton and increasing by 5% every year, with all the revenue distributed to people in quarterly dividends.
But Congress hasn’t made a serious attempt to address GHG emissions since the failure of the Waxman-Markey cap-and-trade bill in 2009, leaving New York and other states to ratchet up their own efforts to address climate change.
The Climate Leadership and Community Protection Act (CLCPA) signed by New York Gov. Andrew Cuomo in July 2019 set ambitious clean energy goals — 100% zero-emission electricity by 2040 and an 85% cut in emissions by 2050 from 1990 levels — but did not include all the measures that will be needed to reach them.
A bill introduced in the state legislature last year that would impose a $35/ton carbon tax, rising after 11 years to $180, has not made it out of committee after previous failed attempts dating back to the legislature’s 2015-16 session (S3608).
“I’m not holding my breath that we’ll have either a nationwide or a New York state economywide carbon tax,” Gerrard said. He said the most promising initiative in the state may be the joint task force on carbon pricing created by NYISO and the state’s Public Service Commission in 2017, which resulted in a proposal published last December that would have the commission set the social cost of carbon to be used in any state policy.
Electrifying Everything
Gerrard said that while there is no unanimity on this issue, he thinks that FERC has the authority to consider climate change when acting on matters like the NYISO carbon pricing proposal.
“FERC makes its decision based on its view of the public interest, a phrase that appears about 50 times in the Federal Power Act. In the words of current FERC Commissioner Richard Glick, ‘climate change must factor directly into the commission’s permitting responsibilities, which generally require the commission to determine whether the relevant facilities are consistent with the public interest.’ Simply put, it is hard to imagine a consideration more relevant to the public interest than the existential threat posed by climate change,” Gerrard said.
Extreme heat kills more people than does extreme cold, he said, showing a National Weather Service heat index map that indicated extreme danger at 40% humidity and 110 degrees Fahrenheit, the highest temperature on the map.
“They don’t go higher than that, but we’ve seen actual temperatures in the last month that go literally off the charts,” Gerrard said. “The appropriately named Death Valley, Calif., experienced 130 degrees just a couple weeks ago, which may have been the warmest temperature ever recorded on the planet.”
Preventing the atmosphere from warming more than 1.5 degrees Celsius above pre-industrial levels, as recommended by the U.N. Intergovernmental Panel on Climate Change, will require electricity decarbonization, energy efficiency, carbon capture and electrification of transportation and everything else run by fossil fuels, Gerrard said.
Matt Schwall, IPPNY director of market policy and regulatory affairs, asked what the regulatory chances are of FERC approving a New York carbon pricing plan.
“I think it only happens if we have a change in administrations, and a change therefore in the composition of FERC,” Gerrard said. “I think it only happens with strong support from New York state. … If there is all of this support, and it’s clear we’re not going to have federal carbon pricing, there’s a good chance that FERC would approve it.”
Such a ruling could withstand an appellate challenge, he said, “because there is lots of precedent within FERC for considering [GHG] in a variety of contexts.”
Still, he added, surviving the challenge “depends in part on what panel is randomly drawn at the D.C. Circuit [Court of Appeals] to hear it.”
FERC last week denied LG&E and KU’s request for rehearing of its order rejecting the company’s proposed transition for exiting from market power mitigation measures, though it did alter the terms of its exit (ER19-2396, ER19-2397).
The commission imposed rate de-pancaking provisions to resolve horizontal market power concerns after Louisville Gas & Electric and Kentucky Utilities merged into a single company in 1998 and left MISO in 2006. In March 2019, the commission agreed the provisions could be removed because loads located in the LG&E/KU market would have access to enough competitive suppliers.
FERC conditioned the removal on a transition mechanism to protect Kentucky municipal customers that had relied on MISO transmission service. In its original September 2019 rejection, it identified several of these customers, including the city of Falmouth, located in the north of the state near its border with Ohio. (See FERC Orders Expanded Mitigation for LGE-KU.)
LG&E/KU, however, argued that Falmouth had joined East Kentucky Power Cooperative, a PJM member, in 2018 and thus should not be included in the transition mechanism. FERC acknowledged that it had erred and ruled that the city “should not be a transition customer.”
The commission otherwise rejected all of LG&E/KU’s numerous arguments, including that it ignored evidence that charges under certain MISO schedules are not pancaked charges, and that it erred by rejecting the company’s proposal to eliminate de-pancaking for exports to MISO.
“We find that LG&E/KU’s arguments overly simplify the context of this proceeding,” FERC wrote in its ruling.
In a separate but related ruling on rehearing, the commission also clarified its use of the “initial term” framework regarding the transition mechanism to Kentucky Municipal Power Agency’s (KMPA) ownership in the Prairie State Energy Campus project and the “take or pay” power sales agreements between it and its members (EC98-2-002, ER18-2162-001).
FERC had ruled that the transition mechanism would be “limited to the initial term of the power purchase agreements entered into by customers in the LG&E/KU market in reliance on the de-pancaking mitigation prior to the issuance of the March order.” But it said the agreements between KMPA and its members have no readily apparent “term” in the “same sense as the power purchase agreements discussed by the commission in the September rehearing order.”
It determined that the Prairie State agreements will be subject to the transition mechanism for a period of 10 years.
“We find a 10-year framework to be appropriate for the transition mechanism for power purchase or sales agreements with no initial term because, otherwise, the de-pancaking mitigation would continue in perpetuity in contrast to the March order, which directed that the de-pancaking mitigation can terminate,” the commission said. “We find that 10 years from the date of the issuance of the March order is a reasonable period of time to allow KMPA to plan for alternative supply choices before its power supply agreement is no longer subject to the transition mechanism.”
Avista violated its own tariff by requiring the Bonneville Power Administration to acquire firm point-to-point transmission service to deliver operating reserves from a resource located outside Avista’s balancing area to a BPA customer situated within, FERC said last week (EL20-36).
Under FERC’s pro forma Open Access Transmission Tariff, load-serving transmission customers must obtain operating reserves along with transmission service. Reserves can either be purchased from the transmission provider or a third party, or be self-supplied.
BPA purchases network transmission service from Avista to serve customer load located within the utility’s BA, an arrangement that historically included the purchase of operating reserves. In 2018, the federal power marketing administration notified Avista that it would begin to self-supply those reserves from its own generation outside the BA.
“This was the first instance in which an Avista transmission customer had opted to self-supply operating reserves,” FERC noted in its order Thursday.
Avista then informed BPA that it would need to acquire additional firm point-to-point transmission service to deliver the self-supplied reserves in the utility’s territory. The utility also noted it had revised its business practice manual to reflect the requirement.
BPA responded with a complaint to FERC, contending that the new self-supply business practice violates the Federal Power Act because:
it is unduly discriminatory and preferential by imposing additional costs on BPA’s self-supplied operating reserves that are not applied to Avista’s reserves;
it is unjust and unreasonable to require transmission customers to pay an additional charge to self-supply reserves; and
Avista had not filed the business practice manual change with FERC under FPA Section 205.
BPA contended that it was delivering the same reserve product designated to meet the same contingencies, the only difference being the location of the supply. It also argued that there is no NERC reliability factor that justifies treating reserves from off-system resources differently from those originating from internal resources.
“Furthermore, Bonneville asserts that when Avista receives off-system operating reserves from the Northwest Power Pool Reserve Sharing Group, Avista does not procure additional firm point-to-point transmission service,” FERC noted.
Avista countered that, in order to be comparable to its supply of operating reserves and fully serve load, BPA’s reserves must be delivered to the AVA.SYS delivery point on the utility’s system, the point from which it deploys all operating reserves within its system.
Avista argued that it would not be sufficient for BPA to deliver those reserves to the AVA.BPAT delivery point, which represents the boundary between the entities’ systems, because it is considered neither a source nor sink.
Furthermore, Avista contended that BPA could not use its firm network transmission service to deliver the operating reserves from AVA.BPAT to AVA.SYS because the utility’s tariff stipulates that network transmission service is used to deliver capacity and energy from the customer’s designated network resources to its network loads, while the BPA generation being set aside as operating reserves would not be supplying network load.
BPA responded that the commission did not have to resolve the issue of where the operating reserves are delivered but should address Avista’s disparate treatment of each’s reserves. BPA said it would be willing to deliver its self-supplied reserves to any point as long as Avista’s resources are subject to the same requirements.
‘Inappropriate’ Restriction
In its order, FERC noted the proceeding contained no dispute about whether self-supplied operating reserves deployed from designated network resources within Avista’s BA can use a transmission customer’s existing network service and not be required to obtain additional service.
“Indeed, Avista acknowledges that it does not reserve and use additional transmission service for its own operating reserves,” the commission wrote.
The question, FERC clarified, is whether Avista may require that reserves outside its territory must obtain additional firm service.
“We find that the transmission used by operating reserves deployed from designated network resources — regardless of whether those resources are located within Avista’s balancing area or outside it — is part of the network transmission service for which the network transmission customer has paid,” FERC found.
The commission noted that a previous opinion determined that “operating reserves ‘are reservation services that do not require additional transmission.’”
“We are not persuaded by Avista’s arguments that the location of the operating reserves, or the fact that Bonneville lacks designated network resources within Avista’s balancing area, justifies the assessment of additional transmission charges for operating reserves that are provided in conjunction with taking transmission service,” the commission said.
FERC additionally ruled that Avista was violating its own tariff by not allowing network transmission service customers to use their service to deploy reserves from outside the BA.
“Specifically, section 28.3 of Avista’s tariff states that Avista ‘will provide firm transmission service over its transmission system to the network customer for the delivery of capacity and energy from its designated network resources to service its network loads on a basis that is comparable to the transmission provider’s use of the transmission system to reliably serve its native load customers,’” the commission said.
“Avista’s requirement to reserve and use additional firm point-to-point transmission service to transmit operating reserves deployed from designated network resources located outside of Avista’s balancing area inappropriately restricts the network transmission customer’s use of its network transmission service,” FERC continued.
But the commission would make not issue a determination over whether BPA’s operating reserves deployed from resources are eligible to use the existing transmission service.
“The record is unclear about whether the Bonneville resources from which it will deploy operating reserves meet the requirements to be designated as network resources under the Avista tariff, and nothing in this order finds that the resources that Bonneville wants to rely on for the operating reserves at issue are designated network resources under Avista’s tariff,” the commission concluded.
FERC last week opened an investigation under Federal Power Act Section 206 into the justness and reasonableness of Basin Electric Power Cooperative’s 2020 rate schedule and the wholesale power contracts between the cooperative and 19 of its members (ER20-2441, ER20-2442, EL20-68).
The commission found Basin’s rate schedule and power contracts raised factual issues that should be addressed through hearing and settlement judge procedures.
FERC said it accepted Basin’s 2020 filings because it considered them to be initial rates, effective Sept. 15. The commission disagreed with intervenors’ arguments that a lack of withdrawal and termination procedures rendered the wholesale contracts unjust and unreasonable, saying each contract includes provisions requiring notice of termination for the contract term’s end.
Commissioner James Danly dissented in the order, saying he didn’t agree with the commission’s decision to set for hearing whether the Mobile-Sierra presumption should attach to the wholesale contracts. Under Mobile-Sierra, FERC must presume that the electricity rate set in a freely negotiated wholesale contract meets the FPA’s “just and reasonable” requirement. The presumption may be overcome only if the commission concludes that the contract seriously harms the public interest.
“My disagreement … stems from my general disagreement as to the analysis applied by the commission in considering whether and when the Mobile-Sierra presumption should apply,” Danly wrote. He noted that Basin’s counterparties “almost uniformly agree[d] that ‘without a doubt’” the wholesale contracts were freely negotiated. Only Tri-State Generation and Transmission Association asserted its contract was “not accomplished on an even playing field,” he said.
“Given the near universal support for the [contracts] other than Tri-State’s generalized complaint about bargaining positions, there is no credible claim of infirmity in the [contracts’] formation … that would lead us to conclude that they do not represent the fully voluntary agreement of the parties,” Danly said. “This issue should not be set for hearing.”
FERC Combines Tri-State Membership Fee Dockets
FERC on Sept. 11 accepted Tri-State’s methodology for members’ one-time payments to become partial-requirements members, but it also established hearing and settlement procedures over the co-op’s buy-down payment (BDP) calculation, subject to refund.
The commission combined the proceeding with another docket involving Tri-State that it set for hearing in June concerning the cooperative’s proposed contract-termination payment (CTP) methodology for computing member exit fees (ER20-2417, ER20-1559). (See FERC Sets Tri-State’s Exit-fee Rules for Hearing.)
FERC found there were several common issues regarding Tri-State’s use of the two methodologies and agreed with United Power, a Tri-State member, to consolidate the proceedings.
Tri-State’s BDP methodology is designed to give its utility members additional flexibility for the self supply of power and more local renewable energy development.
FERC has set Tri-State’s membership fee calculations for hearing and settlement procedures. | Tri-State Generation and Transmission Association
In February, Tri-State’s board agreed to hold an open season to allocate 300 MW of systemwide member self-supply capacity for future member partial requirements contracts, equal to 10% of Tri-State’s total demand. Under previous rules, members were limited to self supplying only 5% of their power, with an additional 2% through community solar.
The cooperative said the BDP methodology establishes a framework for holding partial requirements customers responsible for the costs incurred in permitting them to switch to partial requirements service without imposing a financial burden on the remaining full-requirements members.
Tri-State said the proposed methodology uses the same underlying mark-to-market method as the CTP methodology. The mark-to-market method is a planning approach, Tri-State said, with the departing utility member’s required BDP based on a forecasted difference between the cooperative’s long-term financial forecast (LTFF) business-as-usual case and load-loss case.
FERC said its preliminary analysis indicated the proposed methodology had not been shown to be just and reasonable.
Several Tri-State members protested in the docket, raising concerns that certain material terms and conditions are referenced in the cooperative’s transmittal letter but are not included in the rate schedule. FERC found that terms and conditions of Tri-State’s proposal to impose a full transmission service requirement on partial requirements members needs to be filed with the commission under FPA Section 205 and included in its rate schedule.
A CAISO resource adequacy workshop Thursday was part of an initiative that started nearly two years ago, but it could not have been more timely following the heat waves and energy emergencies of mid-August and Labor Day weekend.
During those periods, the ISO had to compete for strained energy resources across the West, scrambling last-minute and paying sky-high prices for imports to cover peak demand. California was criticized by some for relying too heavily on imports that grew scarce as other states tried to meet heavy demand amid record temperatures.
“Our challenge, in this RA imports policy, is how do we strike that right balance between ensuring that our imports, which we rely on heavily, are reliable and dependable, and yet we understand we are competing for this supply broadly across the West?” said John Goodin, the ISO’s senior manager for infrastructure and regulatory policy. “How do we not make it so onerous that others reject the California market as too rigorous and go sell somewhere else?”
The CAISO market needs to be “liquid and able to trade and transact imports,” he said.
The authors of the initiative’s issue paper wrote that CAISO’s must-offer obligations, RA substitution rules and resource availability incentive mechanisms together “create a very complicated system of processes that differ vastly from other ISOs/RTOs.” Part of the initiative involves addressing those “overly complicated” processes.
Goodin spoke Thursday about the need for the ISO to ensure that it has dedicated generation and transmission capacity for RA imports.
“You not only have to lock up the source, but you have to lock up the transmission as well,” he said.
The ISO’s “perennial concerns” are that “speculative” supply and double-counted resources are clouding its RA import estimates, Goodin said. CAISO wants out-of-state suppliers to dedicate specific generation resources, including pooled resources, to serving California load so that CAISO is not relying on supply that doesn’t materialize, he said.
The ISO prefers resources come from a seller’s capacity reserves and that non-delivery be subject to fines.
“That’s the key point,” Goodin said. “It’s backed by capacity reserves, and it pays damages if it’s not delivered. Those are the two requirements we’re very interested in.”
Firm Transmission
More recently, the ISO has been worried about not having the means to bring in energy from out of state.
The “hotter topic is the delivery assurance,” the transmission side of RA imports, Goodin said.
During the “heat storms” of August and September, vital transmission lines linking Southern California to the Pacific Northwest were pushed to their limits and sometimes beyond, he said in his presentation to the RA Enhancements Working Group. Slides showed the strained situation at the California-Oregon Intertie (COI).
The COI and Pacific DC Intertie were at or near maximum capacity during the mid-August Western heat wave. | CAISO
Goodin argued the situation underscored the need for firm transmission service that’s guaranteed, especially in times of crisis.
“RA import capacity must be dependable and deliverable on high-priority transmission service,” one of his slides said.
Some stakeholders — such as the Bonneville Power Administration, Calpine and LS Power — back the proposal for firm point-to-point, source-to sink transmission.
However, the plan is unpopular with other stakeholders who contend it isn’t necessary and could even prove harmful.
Opponents include California’s community choice aggregators, represented by the California Community Choice Association, and the state’s three large investor-owned utilities: Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric.
The publicly owned Sacramento Municipal Utility District also opposes firm transmission, arguing there’s no supporting data demonstrating the need for it. Though at or near maximum capacity, the COI’s 500-kV lines retained some transfer capacity during the crises in August and September, opponents contended.
Financial services firm Morgan Stanley argued that firm point-to-point transmission will do more harm than good.
“The CAISO should reject the arguments promoting source-to-sink firm requirements,” Ali Yazdi, a head energy trader with Morgan Stanley Capital Group in Canada, said in his written comments on the ISO’s fifth revised straw proposal, now under discussion. “These stringent rules will only serve to squeeze out competition, reduce diversity of supply and, in fact, harm reliability.”
The plan could lead to long-term hoarding of transmission rights by entities that stand to gain the most, Yazdi said. He reiterated his comments during Thursday’s workshop.
Morgan Stanley and others favor an alternative proposal by CAISO that requires firm transmission delivery only on the last line of interest, the last leg to the CAISO balancing authority area. Goodin said the alternative remains a viable option.
Thursday’s meeting was one of two held last week by the RA working group; the first dealt mainly with unforced capacity evaluations. Comments on the sessions are due Oct. 1, and a draft final proposal is due Nov. 3. The CAISO Board of Governors is expected to take up the plan in the first quarter of 2021.
