FERC last week authorized Dominion Energy’s proposed acquisition of SCANA and its South Carolina Electric & Gas subsidiary, saying the transaction was consistent with the public interest (EC18-60).
Dominion CEO Tom Farrell II
“We are pleased by the FERC’s considered and timely action,” Dominion Energy CEO Thomas Farrell II said in a statement. “We will continue working toward achieving the other required regulatory approvals and completing our transaction by the end of this year.”
The deal has been approved by the Georgia Public Service Commission and federal antitrust regulators. It still requires approval by SCANA shareholders, the North Carolina and South Carolina public service commissions, and the Nuclear Regulatory Commission.
Dominion offered to buy SCANA on Jan. 3 for $7.9 billion in stock and the assumption of $6.7 billion in SCANA debt. (See Dominion to Buy Distressed SCANA for $8B.) SCANA became an acquisition target after its failed attempt to add two reactors to the V.C. Summer nuclear plant. The company and its partner on the project, Santee Cooper, which is owned by the state of South Carolina, spent $9 billion on the expansion before pulling the plug on it last summer.
The decision created a firestorm in South Carolina, where SCE&G and Santee Cooper ratepayers have been shouldering the project’s cost. The state late last month enacted a law directing the Public Service Commission to cut SCE&G’s rates by an amount that would cover nearly all the portion of the rates that go to covering the failed nuclear project’s cost. SCE&G responded with a lawsuit challenging the law’s constitutionality in federal court.
FERC cleared the way for South Carolina Electric & Gas to become part of Dominion. | SCE&G
SCE&G has been sued by its customers over the project, which is being investigated by the FBI, the South Carolina State Law Enforcement Division and the Securities and Exchange Commission, none of which has filed any charges.
SCANA said Friday it has added two independent directors to its board and appointed them to a Special Litigation Committee charged with investigating claims alleged against some of its current and former directors in shareholder lawsuits against it in federal and South Carolina courts.
MISO’s proposal to allow merchant HVDC lines to connect to its system is incomplete, FERC informed the RTO last week in a deficiency letter.
In its filing with the commission, MISO said it based the proposed merchant agreement on its existing generator interconnection agreement and procedures, but FERC on July 12 asked it to explain why it was appropriate to do so — among other questions (ER18-1410). The commission gave MISO 30 days to file a response.
HVDC lines in MISO footprint | MISO
The RTO’s proposal involves treating merchant HVDC as transmission rather than generation, and requires merchant developers to acquire MISO injection rights or a precertification that the system will be able to reliably manage the capacity and energy from proposed lines at the point of connection. (See MISO Plan Provides Tx Treatment for HVDC Lines.)
FERC asked MISO why the timeline and termination provisions for the proposed agreement differ from those in the GIA, given the RTO’s claim that the former is based on the latter.
The proposed HVDC agreement stipulates that if injection rights are not converted to external network resource interconnection service within three years of a line’s commercial operation date, MISO will terminate interconnection service. With the RTO’s GIA — which doesn’t include the concept of injection rights — an interconnection customer can extend its commercial operating date for up to three years without risking queue withdrawal. MISO had said the termination provision matched that of its GIA because in both cases, the “underlying agreement may be terminated if commercial operation is not achieved within three years of the commercial operation date.”
FERC also asked MISO to clarify whether it plans to simultaneously update its merchant HVDC connection agreement when it proposes to make changes to its GIA.
The HVDC agreement also includes a provision stating that transmission owners will be able to review any modifications to a connection facility that affects them, but FERC asked MISO how it would move forward with a HVDC connection request if a party to the connection agreement does not accept a modification.
The commission also asked MISO to describe the processes behind examining injection rights and its proposed merchant HVDC connection service study.
SPP’s Market Monitoring Unit said last week that energy prices averaged about $23/MWh in the spring, despite higher loads.
The MMU’s quarterly State of the Market report also highlighted the recent merger between Westar Energy and Great Plains Energy, the parent company of Kansas City Power and Light, although its completion happened outside the report’s March-May range. (See Westar-Great Plains Merger Wins Final Approval.)
The Monitor said the combined company would have accounted for 19.2% of total system load over the period, making it the largest energy user in SPP’s market footprint. Additional information will likely be included in the summer report, MMU Executive Director Keith Collins said.
The report indicates that spring hourly average load was up 8% from 2017 — and 14% for May alone — as a result of abnormally high temperatures. Average day-ahead prices increased 13% to $23/MWh over last spring, while average real-time prices gained 10% to $22/MWh.
| SPP MMU
Spring’s average monthly gas price at the Panhandle Eastern hub was $2.14/MMBtu, down from $2.70/MMBtu in 2017. Gas prices in spring 2016 were $1.68/MMBtu.
Coal-fired resources continued to account for a smaller share of the RTO’s energy production at 37%. Wind resources accounted for almost 29% of generation, with nameplate wind capacity increasing to 17.7 GW by June, up from 12.8 GW at the end of May 2016.
The Monitor said occurrences of negative price intervals decreased from the winter period and last spring. This spring, prices were negative in just over 5% of real-time intervals, and just under 2% of day-ahead hours.
| SPP MMU
According to the report, overall congestion in the footprint has declined, with real-time intervals with a breached or binding flowgate dropping from 40% last spring to 20% this spring.
The Monitor recently conducted a study of day-ahead market congestion and auction revenue rights bidding behavior following complaints by market participants that were unable to obtain hedges in the ARR process. The study led to three main conclusions, the MMU said: Successful ARR nominations have decreased; the market’s overall need for hedges has increased; and nomination behavior has remained relatively consistent.
The growth in day-ahead congestion correlates with the overall increase in wind production, the Monitor said. It said the 28 GW of additional wind capacity planned in the generation interconnection queue will likely increase the need for hedging.
The MMU recommends “further review and consideration of the auction revenue right process by the RTO and stakeholders” going forward. It will host a webinar July 25 to discuss the spring report.
SPP Preps AECI Seams Project for 2nd Crack at FERC
David Kelley, SPP’s director of seams and market design, told the Seams Steering Committee on Friday that the RTO has performed additional analysis in order to gain FERC approval of a seams project with Missouri-based Associated Electric Cooperative Inc.
Kelley said staff intends to present “new evidence” on regional cost allocation to FERC in July or August. He said SPP will be presenting the avoided costs of regional projects — a metric the commission has already approved — and the reduced regional costs of day-ahead market uplift.
“We’re thinking we’re in really good shape,” said Kelley, who last met with FERC on July 12. “It’s been a little challenging to figure out a way to do regional cost allocation for a single project.”
SPP is trying to reverse FERC’s October rejection of cost allocation for the Morgan project, one of two potential seams projects with AECI. It consists of a new 345/161-kV transformer at AECI’s Morgan Substation near Springfield and the rebuild of a 161-kV line.
The other project, a 345-kV, 50-MVAR reactor at City Utilities of Springfield’s existing Brookline substation, has been included in SPP’s Integrated Transmission Planning Near-Term assessment that will be presented to the Markets and Operations Policy Committee and Board of Directors/Members Committee this month.
The Brookline project’s costs will be allocated under SPP’s normal processes, but Kelley said AECI wants to pick up its share. The two projects have a combined estimated engineering and construction cost of more than $18 million.
The SSC agreed to take a crack at developing a Tariff mechanism to allocate costs for seams projects. With no such mechanism in place, SPP has to take seams projects to FERC on a case-by-case basis.
SPP, MISO Discuss Jan. 17 ‘Big Chill’
The Regional Transfers Operating Committee (RTOC), a six-person committee that includes two representatives from SPP and MISO, met twice in June to discuss what Kelley called “The Big Chill,” the Jan. 17 event when unusually frigid weather forced MISO to initiate a maximum generation alert for its South region.
MISO exceeded its 3,000-MW regional dispatch limit on transfers between its North and South regions over the SPP transmission system for an hour and was forced to make emergency purchases from Southern Co.
Kelley said the RTOC reviewed the use of NERC’s transmission loading relief process during the event and processes for acquiring and delivering emergency energy. He said improved communications will be the key to preventing a recurrence and improving operations and reliability.
“Situations like Jan. 17 don’t just show up without advance warning,” he said. “We and MISO had multiple warnings days before. We feel, and MISO feels, we can do a better job of communicating in advance.”
The RTOC is an operating committee created by a 2016 settlement agreement between SPP, MISO, Southern and the Tennessee Valley Authority. (See SPP, MISO Reach Deal to End Transmission Dispute.) It will meet again in late July.
M2M Generates $397,428 in Payments to SPP in May
Market-to-market (M2M) payments between SPP and MISO dropped to $397,428 in May, the lowest amount since last August. However, it was also the 10th straight month, and the 18th of the last 20, in which the payments have been in SPP’s favor.
| SPP
The RTO has incurred $53.7 million in M2M payments from MISO since the two began the process in March 2015.
Current and temporary flowgates were binding for 254 hours in May, SPP staff told the SSC.
MISO last week outlined the range of stakeholder feedback it has received since revealing its straw proposal for energy storage resources (ESRs) in June.
The RTO’s proposal for complying with FERC Order 841 called for ESRs participating under four modes of commitment: charging, discharging, continuous operations and outage/offline. When in online mode, storage would be treated as must-run resources. (See MISO Offers Straw Storage Proposal to Meet Order 841.)
At a July 12 Market Subcommittee meeting, MISO said that stakeholders have stressed the importance of coordination with distribution system providers and expressed concern that requiring hourly offers might limit storage’s flexibility. Others reminded the RTO that storage resources are not generation and said they should not be bound to a must-offer requirement. Some said storage should be treated like load-modifying resources while others said storage should be restricted to the ancillary services market, despite FERC’s requirement that it be allowed to provide capacity and energy.
Stakeholders asked how hybrid storage-and-renewable formats will fit under the proposal and requested optimized pumping and withdrawal options for pumped storage facilities. MISO dismissed the latter as beyond the scope of Order 841 but said it will meet with market participants to discuss ways to fully incorporate pumped storage into the market.
MISO Director of Market Design Kevin Vannoy said the RTO would return in August with more detail around the proposal and examples of how storage will function under the model. It will focus examples on non-market services, storage modeling, metering, commitment and dispatch rules, Vannoy said. Market clearing prices or LMPs will set emergency pricing for injecting and withdrawing during maximum generation events.
“There might be restoration payments when energy storage resources provide black start restoration from an event,” he added.
MISO also said it will rely on its existing ramp performance measures — excessive and deficient energy flagging and deployment failure penalties — to evaluate storage performance.
Vannoy said he’s gotten at least two requests for private meetings with MISO staff to discuss the straw proposal. While MISO isn’t opposed to setting up one-on-one meetings, he said, staff are busy working on Order 841 compliance and have limited time. He also said it may be best to raise storage issues and suggestions in public meetings.
“We’re not necessarily looking to facilitate private discussions,” Vannoy said, urging stakeholders to bring their storage questions and recommendations to the Resource Adequacy, Market and Reliability subcommittees.
Vannoy said while MISO usually doesn’t solicit extensive stakeholder feedback on FERC compliance directives, Order 841 compliance is a “special case” that warrants more intensive stakeholder involvement, and MISO plans to collect more feedback through summer.
“I don’t think this is a pure vanilla compliance filing. It’s not where FERC says, ‘Do A, B and C,’ and we file A, B and C,” Vannoy said.
MISO will solicit feedback through fall while presenting more refined versions of the plan. It plans to have a draft compliance plan by mid-October. Its Tariff filing is due in December.
Storage Model on Old Platform
MISO plans to implement its new storage participation model before it replaces its current market platform with a more sophisticated modular system. Responding to the straw proposal, stakeholders asked that the RTO not make a storage participation model dependent on the new platform’s capabilities. Instead, they asked that MISO design the market platform with storage needs in mind.
Kevin Larson, MISO market and modeling director, said the RTO will continue to assess principal vendor General Electric’s performance on project deliverables and will evaluate alternate vendors through the end of 2019. MISO last month said GE was overly optimistic in its original timeline for the replacement, which may lead to delays and a small budget overrun. (See MISO Platform Replacement Risks Delay, Budget Overrun.)
“We’re in an evaluation phase with General Electric,” Larson said.
MISO reported in June that, as part of its multiyear market platform replacement, it had improved its day-ahead solve time by more than six minutes, about a 10% improvement. Larson said the additional headroom will allow for “select market enhancements while the new market system is being developed.”
Storage Capacity Accreditation
At the July 11 RASC meeting, MISO presented its proposal on how it will accredit storage capacity, another requirement of Order 841.
Senior Adviser of Capacity Market Administration Rick Kim said MISO is proposing to require that storage resources continuously discharge energy equivalent to their zonal resource credits committed in the Planning Resource Auction.
The continuous discharge would be subject to a minimum run time, either 24 hours or four hours for limited-use resources. Storage resources would also have to submit the generator verification test capacity (GVTC) data required of other planning resources. MISO would ask for a storage resource’s GVTC by Oct. 31, 2019, for the 2020/21 planning year capacity auction. The RTO said it would also want storage resources to provide documents to support the megawatt-hours of capacity they claim. MISO will apply default outage rates to determine unforced capacity calculations for storage resources that have less than a year of operational data.
Storage assets should also secure either firm transmission service or network resource interconnection service before offering as a capacity resource. If the storage resource is interconnected at the distribution level, the resource will be subject to coordination with the distribution provider, transmission owner and MISO.
Kim asked stakeholders for specific ideas on the calculations and tests for capacity accreditation.
MISO and SPP announced Friday they plan to relax barriers that have prevented them from agreeing to develop interregional projects.
The two RTOs will remove their $5 million cost threshold and joint modeling requirement for the projects, staff revealed during a July 13 conference call of the Interregional Planning Stakeholder Advisory Committee.
Removal of the $5 million cost standard will not affect other criteria, such as the 5% or higher benefit threshold for each RTO and the requirement that projects be in service within 10 years of approval, the RTOs said.
Instead of creating a joint model, MISO and SPP will now leverage their existing regional planning models to evaluate interregional projects. Eliminating the joint model requirement will shorten a lengthy study process and allow the RTOs to examine more potential projects, they said. MISO and PJM removed a similar requirement almost two years ago in response to a FERC complaint filed by Northern Indiana Public Service Co. (See FERC Orders Changes to MISO-PJM Interregional Planning.)
MISO Planning Adviser Davey Lopez said removing the joint model will eliminate inconsistencies between the joint model and the RTOs’ respective regional models.
“We’re both doing very robust regional reviews,” SPP Interregional Coordinator Adam Bell added.
Concerns over Cost Allocation
Bell said stakeholders were split over removal of the joint model; while some wanted the triple hurdle eliminated, others were concerned about equitable cost allocation absent a joint model. Had MISO and SPP approved an interregional project, the joint model would have determined each RTO’s share of the cost.
The RTOs said they will calculate adjusted production costs and avoided costs for all interregional projects using their regional calculations of benefits. They have pledged to provide interregional cost allocation examples to address stakeholders’ concerns about inequities and explore the possibility of adding a market-to-market benefit metric.
The Wind Coalition’s Steve Gaw stressed the need for the RTOs to develop an objective cost allocation plan rather than promising negotiations.
“For me, this isn’t sweeping things under the rug. This is sweeping things into a different room,” Gaw said. “If you’ve got two RTOs determining what their benefits are. … I think you have to have something that avoids you arguing over how the benefits are calculated in each of your regions.”
Other stakeholders also asked for a more specifics on cost allocation, and Lopez promised more discussion on the issue during the August IPSAC meeting.
“This is a difficult conversation to have without examples in front of us,” Bell acknowledged. He assured stakeholders the RTOs only arrived at the decision to remove the joint model after substantial discussion about how it would affect project cost allocation.
The two RTOs agreed in February not to pursue a 2018 coordinated system plan, which could have resulted in an interregional project, instead promising to examine their joint planning process and seek ways to improve interregional coordination.
The two have completed two coordinated system plan studies to date, but neither has resulted in a viable interregional project. During their 2016/17 study, the RTOs identified three possible projects, but all were disqualified by the $5 million cost requirement, Lopez said.
“I think the studies have shown us that there are some barriers,” Lopez said.
Bell said MISO and SPP will likely return to the IPSAC next month to seek approval to revise their joint operating agreement, which will be filed by the end of the year.
Bell said the RTOs hope to produce another coordinated system plan study in 2019, although filing timelines could interfere with the goal.
No Dent in MISO 345-kV Threshold
The JOA revisions will not include a provision to lower MISO’s requirement that market efficiency interregional projects be at least 345 kV.
“SPP continues to encourage MISO to pursue lowering its current 345-kV voltage threshold for SPP-MISO interregional projects,” SPP said. However, MISO said it continues to view the voltage threshold as a strictly regional issue, not up for discussion in the IPSAC because there is no voltage threshold criteria in the JOA. Lopez said MISO’s Regional Expansion Criteria and Benefits Working Group will continue to explore the effects of lowering the threshold.
MISO last month said it will revise its regional — not interregional — cost-sharing practices for market efficiency interregional projects with SPP in order to match its process for PJM seams projects, lowering the voltage threshold to 100 kV over some stakeholders’ objections. (See MISO to Lower SPP Interregional Project Thresholds.) MISO lowered its 345-kV threshold for MISO-PJM projects to 100 kV in 2016 under FERC’s orders.
The MISO-SPP plan also excludes a requirement that prospective interregional projects that were evaluated but didn’t pass a cost-benefit ratio be reviewed and voted on by both boards of directors. MISO said requiring such a move was unnecessary: Interregional projects that pass all criteria would still need to be approved by the boards.
FERC on Friday tentatively accepted a cost-of-service agreement between Exelon and ISO-NE for Mystic Generating Station Units 8 and 9, ordering an expedited hearing process on unresolved issues (ER18-1639).
The order drew sharp rebukes from Commissioners Robert Powelson and Richard Glick, both of whom called it “yet another rush to judgment.”
The agreement would allow the gas-fired units in Massachusetts an annual fixed revenue requirement of almost $219 million for capacity commitment period 2022/23 and nearly $187 million for 2023/24. But the commission found the information Exelon provided to support those figures insufficient, setting for hearing the company’s proposed capital expenditures, fuel costs, and operations and maintenance expenses.
Notably, FERC did not hold the hearing in abeyance and appoint a settlement judge, as it often does when it suspends an accepted filing. Instead, it ordered an expedited hearing schedule, citing Exelon’s Jan. 4, 2019, deadline for deciding whether to retire the units and the beginning of Forward Capacity Auction 13 on Feb. 4. The agreement goes into effect June 1, 2022, subject to the outcome of the hearing.
The commission ordered the presiding judge to certify the record by Oct. 12, with initial briefs due Nov. 2 and reply briefs Nov. 16.
ISO-NE’s Tariff does not allow for reliability-must-run agreements, and only allows cost-of-service agreements to respond to local transmission security issues. FERC on July 2 denied the RTO’s request for a Tariff waiver to allow for the Mystic agreement. Exelon said in March that it would retire the 2,274-MW plant when its capacity obligations expire on May 31, 2022 (ER18-1509). (See FERC Denies ISO-NE Mystic Waiver, Orders Tariff Changes.)
Mystic Generating Station, on the Mystic River in Everett, Massachusetts. A wind turbine owned by the local water authority to power a pumping station is on the right.
The commission instead ordered the RTO to revise its rules to allow cost-of-service agreements for facilities needed to address fuel security issues, or show cause as to why it shouldn’t have to (EL18-182). ISO-NE’s response is due Aug. 31.
Powelson and Glick also dissented in that order, and both cited it in their dissents last week.
“The commission is not even waiting for stakeholders’ responses to the show cause order it issued last week before plunging ahead with its plans to bail out Mystic and Distrigas,” Glick said. Exelon included in the agreement the costs of purchasing fuel from and operating the nearby Distrigas LNG import terminal, which it is buying from ENGIE North America.
“By setting the agreement for modified settlement and hearing procedures, the majority is expressing a preference for a short-term cost-of-service mechanism to address fuel security,” Powelson said. “That message may have been implied in the waiver order, but after today’s order there is no question as to the majority’s direction. …
“Over the next few months, interested participants will focus time and energy on the agreement in an attempt to reach consensus on a host of challenging issues. Because the commission has failed to narrow the issues to be addressed in this proceeding, today’s order has opened a proverbial can of worms. Thus, instead of working collaboratively to respond to the commission’s Section 206 inquiry or consider more cost-effective alternatives, stakeholders will be working on the Mystic agreement.”
Distrigas, Cost Allocation
While FERC said it could not determine whether the agreement was just and reasonable, it did comment on several issues raised by protesters in the proceeding.
Several protesters questioned whether including an entire LNG facility in a cost-of-service rate violated the Federal Power Act.
Distrigas Terminal at sunset | Everett Chamber of Commerce
The commission said it would set the matter for hearing, but “in advance of the hearing, we find unpersuasive arguments that the FPA prohibits any recovery of the fuel supply charge for the Distrigas facility.”
“This finding as to jurisdiction does not mean that Mystic is entitled to recover all costs that it claims in connection with the Distrigas facility,” the commission said. “Whether individual components of a cost-of-service rate, including fuel-related costs, are recoverable turns on whether they are just and reasonable, not whether the commission has regulatory authority over all aspects of those rate components.”
Other protesters were concerned that there was no cost allocation mechanism in the agreement. FERC noted that in its show cause order, it directed ISO-NE to include such a mechanism in any Tariff revisions the RTO proposes.
The commission also said that while capital expenditures would be subject to hearing, the Mystic units should be allowed to collect actual prudently incurred costs, subject to true-up.
“We find that given the inherent difficulty in projecting costs in advance of the agreement’s effective date, and the concerns raised as to whether certain expenditures will be necessary to keep the Mystic units operational during the proposed service period, a true-up mechanism is necessary to ensure that the rates established reflect actual costs incurred,” the commission said.
The order directed the participants to present evidence regarding the appropriate design of the true-up mechanism in the agreement, noting that ISO-NE may also address the related clawback provision in EL18-182.
FERC on Friday rejected PJM’s proposal to exempt incumbent transmission owners from signing designated entity agreements (DEAs), saying it gave them an undue advantage over non-incumbents (ER18-1647).
In May, PJM proposed two changes to the competitive proposal window process mandated by Order 1000.
The commission approved PJM’s request to allow transmission developers 60 days to accept a DEA after receiving it as the winner of a project. The agreement includes a development schedule and a requirement to provide a letter of credit equal to 3% of the estimated project cost.
But the commission rejected the RTO’s proposal to exempt incumbent TOs from the requirement to execute a DEA for Regional Expansion Transmission Plan projects that the Operating Agreement requires PJM to designate to an incumbent. Such projects include TO upgrades; projects that would alter the TO’s use of its right of way; and those located solely within a TO’s zone that are not allocated outside.
PJM argued that the terms of the Consolidated Transmission Owners Agreement (CTOA) governing incumbents are comparable to the DEA. It said the security requirement — to protect ratepayers from additional costs if the original developer abandons a project and it must be reassigned — was unnecessary for incumbents because they cannot abandon projects and that requiring it would only increase costs.
| Asplundh Construction
The commission said PJM’s proposal would provide an advantage to incumbent TOs in the RTO’s evaluation of transmission proposals. FERC noted that it had rejected similar exemptions in Order 1000 filings by FERC Accepts Order 1000 Compliance Filing.)
“The less stringent requirements in the Consolidated Transmission Owners Agreement also could spare an incumbent transmission owner from a breach (and the associated remedies) that would otherwise be triggered if it executed the designated entity agreement. Although PJM argues that the proposal to exempt incumbent transmission owners from the requirement to execute a designated entity agreement in certain cases will further administrative efficiency, any such benefits do not overcome undue discrimination concerns,” the commission said.
“Under PJM’s proposal, an incumbent transmission owner proposing a transmission owner designated project in PJM’s competitive proposal window process could reflect the cost savings associated with not having a security requirement in its proposal,” FERC added.
The commission also said the CTOA’s milestone requirements are less stringent than that in the DEA, which includes “several interim milestone obligations and consequently, more potential events for breach.”
FERC said the DEA could prevent a transmission developer from assigning its rights to an affiliated limited liability company or C-corporation as financing vehicles, or from meeting legal requirements for state public utility status. “Such prohibition could inhibit the developer’s ability to seek siting approval from that state, particularly if the state requires that the developer be incorporated as a public utility under state law,” FERC said.
The commission approved PJM’s proposal to change the time period for a transmission developer to accept its designation.
Rather than having 60 days from receiving notification of its designation to accept, PJM proposed that the developer have 60 days after receiving the DEA.
“We agree that this proposal will provide PJM with more time to develop and issue the designated entity agreement, as well as for the transmission developer to respond to the initial designation with a development schedule with milestones and relevant project information,” FERC said.
Energy Imbalance Market officials on Thursday approved a proposal to prevent market participants outside California from skirting the state’s greenhouse gas compliance obligations by “shuffling” low-emissions resources into CAISO while ramping polluting resources to serve load closer to home.
The EIM Governing Body’s decision nearly completes a two-year effort to reach agreement on the issue among a broad swath of stakeholders, including the California Air Resources Board, environmentalists, and power producers and utility regulators in the inland West.
CAISO developed the EIM GHG proposal to help ensure that California accounts for emissions from resources dispatched secondarily to cover for zero-emissions power transferred into CAISO. | Fort Churchill Generating Station, NVEnergy
“This has been a long effort,” Governing Body Chair Valerie Fong said during the group’s July 12 meeting. “It has required active engagement by market participants. It has required active listening and rethinking by ISO staff and management. So, I do think we’re in a better place today than we were a year ago.”
Under CAISO rules, the proposal falls under the Governing Body’s “primary” decisional authority, meaning it will now advance to the consent agenda of the ISO’s Board of Governors before submission for FERC approval.
Secondary Dispatch
The reason for “resource shuffling” is that under the EIM’s rules, California load-serving entities are subject to GHG emissions caps and compliance obligations, while LSEs elsewhere in the West are not.
The EIM Greenhouse Gas Attribution Enhancements proposal was designed to prevent what CAISO refers to as the “secondary dispatch” of higher-emitting resources in the EIM to replace lower-emitting generation transferred into CAISO. Under current EIM practice, the ISO’s least-cost dispatch process typically selects the lowest-emitting resources to serve load in CAISO’s balancing authority area because those resources tend to submit the lowest GHG bid adders into the market.
“Because all resources in an EIM balancing area are generally equally effective in supporting energy transfers to another balancing area, the market minimizes costs by designating the resources with the lowest GHG costs as supporting transfers to the ISO balancing area,” CAISO management explained in a memo to the Governing Body.
The problem: The market currently designates all of a resource’s output with a corresponding GHG adder as supporting a real-time transfer into CAISO, even if that output was already submitted to the EIM as part of a base schedule — indicating the supply was already slated to support load outside ISO.
“The market may designate a resource as supporting a transfer into the ISO even though that resource would have operated at the same output to serve load outside of the ISO without an energy transfer,” CAISO said. “The market will dispatch another resource or resources to ‘backfill’ this dispatch to serve the load outside of the ISO that would have been served by the resource designated as supporting the transfer.”
If the backfilling resource has higher emissions than the one supporting the transfer, this “secondary dispatch” results in the market undercounting the actual GHG emissions attributable to California, the outcome ARB was trying to prevent when it prompted CAISO to develop the proposal. (See CAISO, ARB to Address Imbalance Market Carbon Leakage.)
Headroom
CAISO’s proposal seeks to address ARB’s concerns by limiting a resource’s energy transfers into the ISO to “an amount no greater than the headroom” above the resource’s base schedule.
Under the plan, the EIM would calculate that headroom by subtracting the base schedule from the megawatt quantity for which a resource has submitted an energy bid and corresponding GHG bid adder. CAISO expects the changes will reduce the GHG emissions from secondary dispatch and more appropriately account for emissions produced by units dispatched to serve California.
“Unfortunately, this approach doesn’t fully eliminate the potential for secondary dispatch. It only minimizes it,” Don Tretheway, the ISO’s senior adviser for market design policy, told Governing Body members.
Tretheway also noted that some EIM stakeholders have expressed concerns the new rules could incentivize suppliers to hold the base schedules for their non-emitting resources such as hydro to zero, while simultaneously base scheduling an emitting resource. That would leave the non-emitting resource with all the headroom in the EIM, possibly positioning it to capture a GHG premium if an emitting resource with a GHG adder sets the marginal price for transfers into CAISO — an opportunity for gaming the market.
“But this concern doesn’t recognize that there’s consequences for having suboptimal base schedules. Because we will redispatch, and this leads to additional costs,” Tretheway said. “So, at a minimum, you’re going to have imbalance energy costs as you decrement down that gas resource and increment up the non-emitting resource.”
Tretheway also pointed out that an EIM participant would face additional costs for creating real-time congestion if it didn’t resolve congestion ahead of an operating hour — resulting in uplift costs for the BAA — before submitting its suboptimal base schedule.
‘Simple is Always Better’
CAISO’s final GHG plan won out over a more complicated proposal that would have developed a “two-pass” market mechanism to address secondary dispatch. Under that proposal, a first pass in the market would have determined the optimal schedule across the EIM footprint while restricting net transfers into the ISO. A second pass would allow transfers into the ISO but limit each EIM resource’s GHG bid quantity to the difference between the resource’s upper economic limit and the optimal schedule determined in the first pass. (See EIM Members Seek More Details on GHG Accounting Plan.)
“We were, as [were] other stakeholders, concerned about the two-pass approach that was considered, so the final approach we think is very reasonable,” said Eric Hildebrandt, director of CAISO’s Department of Market Monitoring. “There is the issue of monitoring the base schedules and looking for that potential gaming opportunity. We think that is something the ISO is committed to doing.”
Speaking ahead of the vote, Governing Body member Kristine Schmidt applauded ISO staff for developing a proposal that “has resolved a really strong, outstanding issue … very important to the state of California.”
Body member John Prescott congratulated staff for a solution “that seems to be workable.”
“I can understand it, which means its fairly simple,” Prescott joked. “But simple is always better.”
Prescott said the proposal allows California to meet its environmental goals with “minimal impact to the external EIM participants — that’s very important.” He added that he hoped EIM participants would monitor the proposal after it becomes policy.
“If those out there that are actually implementing this find that it is a problem for them, that it causes unanticipated results, I’d sure like to hear that, so I just put that request out there,” Prescott said.
While Governing Body Vice Chair Carl Linvill added his praise, he reminded his fellow members they will likely have to deal with the issue again after CAISO deploys its day-ahead market to the EIM.
Speaking during his first meeting as a Governing Body member, Montana Public Service Commission Vice Chair Travis Kavulla said he would support the proposal “with a little bit of reluctance.”
“I wouldn’t want the opportunity to pass by without at least questioning a little bit of the premise of what we’re trying to do here,” Kavulla said. “I do think we have to realize that resource shuffling is a natural and economically rational consequence of having a local carbon dioxide price that doesn’t persist across the entire footprint of the market.”
Kavulla said that by assigning a “local” emissions price to backfill generation, CAISO was doing what it has admitted is impermissible, “which is to subject generation outside of California to a California air regulation even when the generation is not being used to serve California load.”
AUSTIN, Texas — Regulators threw a wrench in American Electric Power’s massive Wind Catcher Energy Connection on Thursday, expressing concerns over whether the company will protect ratepayers from the project’s risks.
Public Utility Commission Chair DeAnn Walker made that clear following oral arguments in the contested proceeding involving AEP subsidiary Southwestern Electric Power Co. and several consumer groups (Docket No. 47461).
“I’m going to be upfront with you,” Walker said, addressing AEP CEO Nick Akins, her fellow commissioners and others in the PUC’s hearing room. “At this point, I can’t approve the [project].”
Walker said she would need additional consumer protections from SWEPCO, which would own 70% of the $4.5 billion project. It includes a 2-GW wind farm being built by Invenergy in the Oklahoma Panhandle and a 360-mile, 765-kV line from the facility to Tulsa. Sister company Public Service Company of Oklahoma would own the other 30%.
The two utilities would purchase the wind facility upon its completion, scheduled for the fourth quarter of 2020.
“I have issues and concerns … on the financial impacts to the company,” Walker said, alluding to a recent court decision remanding a SWEPCO rate case back the PUC.
The Texas Court of Appeals for the Third District on July 10 granted a rehearing request by the Texas Office of Public Utility Counsel (OPUC), Texas Industrial Energy Consumers (TIEC), and Cities Advocating Reasonable Deregulation (CARD), reversing a district court’s ruling that the utility’s John W. Turk, Jr. Power Plant should be included in cost recovery (No. 03-17-00490-CV).
Commissioner Arthur D’Andrea said he too would like to see the parties develop additional consumer protections. “But it doesn’t do us any good to protect the consumers, and then have the company fail,” he said.
As is their normal practice following oral arguments, the commissioners will review the arguments and the financial data submitted before issuing a decision. The PUC’s next scheduled open meeting is July 26.
“I’d like some time to look at the transcript,” D’Andrea said.
“I am really struggling with where I am on this,” Walker said. “I was hoping to get more solid on where I am.”
The commission was unmoved by the AEP delegation’s reminder that it faces a time crunch to take advantage of expiring federal production tax credits. Paul Chodak, AEP’s executive vice president of utilities, said the company must give contractors a notice to proceed by Aug. 6 to qualify. He said the company is already moving dirt, securing rights of way and spending “tens of millions of dollars” in legal fees.
“We are on a critical path. Whatever the answer is, we would like it as quickly as possible,” Akins said. “If it’s a bad answer, we can deal with that. If it’s a good answer, we can certainly deal with that too.”
“We’re very aware of the timing implications,” Walker responded.
She encouraged AEP and the other parties to try and “address the customer benefits or protections” before the next open meeting. “Right now, I think there’s more that can be done for the consumers,” Walker said.
“We’re hopeful we can have additional settlement discussions with the intervenors, especially given the PUCT’s encouragement,” said SWEPCO spokesperson Carey Sullivan.
PUC staff, which oppose Wind Catcher, met after the hearing with OPUC, TIEC, CARD and fellow intervenor Golden Spread Electric Cooperative. The group did not commit to further settlement discussions.
SWEPCO operates in East Texas, Louisiana and Arkansas. AEP says Wind Catcher will save SWEPCO’s Texas customers $1.7 billion over 25 years. Company representatives pointed to settlement agreements in Arkansas and Louisiana that insulate customers from the project’s risks, including a cap on construction costs, minimum production levels and qualification for 100% of the federal PTCs. They also noted components of Wind Catcher’s 800 turbines will be built in Texas and Houston-based Quanta Services will build the transmission line.
Representatives of TIEC and CARD argued Wind Catcher would saddle Texas consumers with hundreds of millions of dollars in future rates, saying it would be more expensive and less efficient than the recently approved Xcel Energy wind facility. (See Texas PUC Issues Final Order for SPS Wind Farm.)
“This project is not needed in any traditional sense,” said TIEC’s Rex VanMiddlesworth, pointing to AEP’s argument that Wind Catcher will provide a hedge against higher natural gas prices. “All these parties that have dug into that — staff, the cities and OPUC — have disagreed with that and have presented [countering] evidence. If [SWEPCO’s estimate] was the case, we’d all be saying we want it, like we did for the [Xcel] wind facility.”
“Our concern is not the accuracy of SWEPCO’s forecasts. … Our concern is that the risk of those projections being accurate is on the ratepayer,” said CARD’s Alfred Herrera. “Our concern is that when this project goes into the rate base, the customer will pay.
“SWEPCO is asking you to approve a multibillion project and guarantee its returns,” Herrera said. “That’s the effect of what will happen if this plant comes into the rate base. That’s not how competitive markets work. If this deal is such a good deal, then let the competitive market build it.”
PUC staff oppose an administrative law judge’s preliminary decision approving AEP’s application, saying “the evidence presented does not support a sufficient probability of improvement of service or lowering of costs to ratepayers.”
Staff are recommending that the commission condition its approval on a requirement that SWEPCO guarantee tax credits in the amounts represented by the utility, and some level of net benefits to customers.
PUC Grants Utilities’ SMT Rehearing Request
The PUC granted a motion for rehearing and issued a final order for Smart Meter Texas (SMT), a website that provides customers and authorized market participants access to electric usage data (Docket No. 47472).
The utilities involved in SMT (AEP Texas, CenterPoint Energy Houston Electric, Oncor and Texas-New Mexico Power) filed the request in June “to address limited clarifications.”
The utilities agreed to provide on-demand meter readings as a substitute for home area network (HAN) functionality. Walker filed a memo clarifying that the utilities can’t discontinue support of a customer’s existing HAN device unless the customer requests that the device be disconnected.
SMT allows customers to download and view their energy data or share them with competitive service providers, companies that market energy efficiency, demand response, distributed generation and other services. (See “Commission Streamlines Smart Meter Texas Portal,” Texas PUC Issues Final Order for SPS Wind Farm.)
ALBANY, N.Y. — The New York Public Service Commission on Thursday voted unanimously to authorize state agencies to procure 800 MW of offshore wind energy by next year, the first phase of a plan to develop 2,400 MW by 2030.
Offshore wind is “viable, valuable and ready for prime time,” PSC Chair John B. Rhodes said.
Under the commission’s July 12 order (18-E-0071), the New York State Energy Research and Development Authority will issue a solicitation for 800 MW of offshore wind in the fourth quarter, in consultation with the New York Power Authority and the Long Island Power Authority.
NYSERDA will announce the award in the second quarter of 2019 and, if needed, issue a second solicitation next year to meet the 800-MW goal. The agency will hold a technical conference on the solicitation process from July 23 1-3 p.m. at the Department of Public Service’s office at 90 Church Street in New York City; it will also be available via webinar.
High-Stakes Race
Gov. Andrew Cuomo’s office said that offshore wind will not only help achieve the state’s Clean Energy Standard goal of obtaining 50% of electricity from renewables by 2030 but also will support nearly 5,000 new jobs, nearly 2,000 of them long-term career opportunities in operations and maintenance.
“We’re in a race right now with our fellow states along the Eastern seaboard to get these staging and fabrication facilities for this new industry built in our state, and of course they want it in their states,” Commissioner Gregg C. Sayre said. “I think it would be appropriate for us to get moving quickly and win this one for New York.” (See Competition, Cooperation and Costs the Talk at OSW Conference.)
The U.S. Department of Energy in June awarded a $18.5 million grant to NYSERDA to lead a nationwide research and development consortium for the offshore wind industry, with the state to match the federal funds.
Massachusetts officials hope to develop supply chains for the nascent industry in the Port of New Bedford but will have to avoid interfering with fishing operations there, the No. 1 fishing port in the U.S. (See Overheard at ISO-NE Consumer Liaison Group Meeting.)
According to the environmental impact statement issued by NYSERDA in June, the New York offshore wind projects will affect only 3% of the state’s fishing grounds.
Bidding Details
David G. Drexler, DPS managing attorney, told the commission that NYSERDA will solicit two separate bids from each participating bidder. One would be for a fixed-price offshore wind renewable energy certificate (OREC), while the other would be based on a variable OREC tied to an index.
To contain costs, NYSERDA will reject bids higher than a confidential “upset price,” like the method used in Renewable Energy Standard Tier 1 procurements, Drexler said.
“NYSERDA … would at all times have the authority to reject any and all bids, taking into account not only the benchmark upset price but also recent auctions and market conditions,” Drexler said.
NYSERDA will rank bids based on the following weights price (70%); economic benefits (20%); and project viability (10%). The agency will have discretion in fixing the specific terms of the contract, which will run for 20 to 25 years.
The Phase 1 order for the initial 800 MW makes the generation developer responsible for its own radial transmission to shore, calling it “the most easily implementable and feasible option for jump-starting offshore wind development in New York.”
NYSERDA recommended that backbone transmission and independent ownership be reserved for consideration in Phase 2, to procure the remainder of the 2,400 MW total. It noted that the Bureau of Ocean Energy Management has sold only one wind energy lease directly off New York — Equinor’s site, which is capable of hosting approximately 1,000 MW. The agency said a shared radial system would create unnecessary risks of stranded assets and provide limited cost advantages.
Equinor and Vineyard Wind supported the direct generator lead approach in the early stages of development, arguing in joint comments that “requiring a separate transmission provider would increase project uncertainty and the risk of delay.”
The Green Building Council, the Sustainability Institute and transmission developer Anbaric argued that the first phase should include soliciting bids to develop an “Open Access Offshore Transmission” system, with Anbaric saying it would provide more information about the best options and potentially reduce the costs of the procurement.
Anbaric said that requiring direct generator leads would lead to a piecemeal approach and would not optimize the interconnection, potentially increasing costs for later stages of development. The Green Building Council and the Sustainability Institute concurred with Anbaric’s argument, saying that the generator lead approach would result in a highly inefficient array of separate transmission cables.
Central Hudson Gas & Electric, Consolidated Edison, New York State Electric and Gas, National Grid, Orange and Rockland Utilities, and Rochester Gas & Electric, filing as “Joint Utilities,” also argued that the state should immediately consider developing a transmission backbone and optimizing onshore interconnection locations. They said utility ownership of the transmission portion could produce substantial ratepayer savings. NYPA and New York City also urged that “a coordinated approach to transmission should be initiated immediately,” with NYPA adding it was prepared to assist in the effort.
“Anbaric remains eager to deliver offshore wind to the New York onshore grid quickly and economically,” Anbaric CEO Edward Krapels said in a statement Friday. “We will intensify our development of our New York OceanGrid and look forward to working with generation companies to link the first 800 MW of offshore wind to the New York state grid.”
The PSC also approved new electricity rates for an upstate utility, Massena Electric Department, that will allow high-density load customers, such as cryptocurrency companies, to qualify for service under an individual service agreement.
“As part of our continuing effort to balance the needs of existing customers with the need to attract new companies, we must ensure that business customers pay a fair price for the electricity that they consume,” Rhodes said. “However, given the abundance of low-cost electricity in upstate New York, there is an opportunity to serve the needs of existing customers and to encourage economic development in the region.”
The commission’s order (18-E-0211) said that the individual service agreement tariff includes provisions to protect customers from increased supply costs resulting from the new service.
The program will apply to customers who have a maximum demand of at least 300 kW.
The new rates become effective July 17.
Low-income CDG Initiatives
The commission also adopted three measures to enhance the ability of low-income residents to participate in community distributed generation (CDG) programs: a bill discount pledge program; an income verification service; and a loss reserve fund (15-E-0082).
CDG projects are generating facilities located behind a nonresidential host meter coupled with a group of off-takers who receive bill credits based on the generation of that facility. New York defines low income as at or below 60% of the state median income.
Public funds will be held in reserve to cover losses that CDG project owners or their lenders may incur if low-income subscribers default on or terminate their subscriptions at a higher rate than other customers. DPS staff reported that “a relatively modest amount could provide surety for hundreds or even thousands of subscriptions” but did not define the amount.
Con Ed Smart Solutions Program
The commission approved, with modification, Con Ed’s request for a Smart Solutions Program, which included an enhanced gas energy efficiency program, a new gas demand response program, a new “Gas Innovation” program to encourage renewable alternatives to natural gas heating technologies, and a new market solicitation for non-pipeline solutions.
The order (17-G-0606) established criteria for continued development of the gas innovation program and denied the company’s request “to recover costs associated with parallel pipeline development efforts, thereby maintaining customer protections associated with unsuccessful pipeline development projects.”
The commission said Con Ed’s proposed gas DR program and non-pipeline proposal both “require further information from the company, input from stakeholders, and review from staff, and therefore, these components of the petition will not be considered in this order.”
