CARMEL, Ind. — MISO is weighing how it can improve its interregional process and joint operating agreement with SPP to make it easier to develop cross-seams projects that have so far remained elusive.
“The assumption is the coordinated system plan is not setting us up for success,” Eric Thoms, MISO manager of interregional planning and coordination, told stakeholders at a Feb. 14 Planning Advisory Committee meeting.
Planning staff for both RTOs have agreed to meet this spring to devise ways to improve their joint study process.
Thoms said MISO is considering lowering hurdles for interregional projects, including removing the $5 million cost threshold and eliminating the joint model study requirement, which he said is unnecessary when the RTOs’ separate regional evaluations can adequately examine prospective interregional projects.
He also said the RTOs might identify more joint benefit metrics that could better illustrate the value of potential transmission projects and clarify to stakeholders the process for approving interregional projects.
However, some stakeholders said the RTOs must first address their disparate transmission usage charges before working toward interregional project approval.
“I’m glad to see MISO is trying for constituency between seams, but MISO and SPP have incompatible [unreserved usage charges],” said Minnesota Public Utilities Commission staff member Hwikwon Ham. Until the RTOs have comparable transmission usage charges, interregional projects will be difficult to approve, Ham said.
Xcel Energy’s Drew Siebenaler agreed the RTOs must discuss transmission service charges and resolve the issue of MISO consistently bearing more costs for potential projects that stand to benefit both sides of the seam.
Adam McKinnie, chief economist with the Missouri Public Service Commission, asked that the charges not be the lone hang-up in approving a possible near-term interregional project. Thoms promised to return to the PAC in April to further discuss the topic.
The next Interregional Planning Stakeholder Advisory Committee meeting will be held Feb. 27. Officials from both RTOs plan to present a more detailed coordination plan during the meeting.
CARMEL, Ind. — MISO will expedite review of a proposal to interconnect Foxconn’s massive electronics plant planned for southeastern Wisconsin months ahead of the RTO’s usual year-end approval schedule, stakeholders learned Wednesday.
The $140 million interconnection project to plug Foxconn’s $10 billion plant into We Energies’ network will move ahead “as needed to meet the December 2019 in-service date,” Lynn Hecker, MISO manager of expansion planning, said at a Feb. 14 Planning Advisory Committee meeting.
Foxconn manufacturing plant in the Czech Republic | Syner
American Transmission Co. submitted the request for accelerated approval late last year, insisting that its proposed project cannot wait until usual approvals at the end of the year as part of MISO’s 2018 Transmission Expansion Plan. ATC has proposed constructing a 14-mile, 345-kV transmission line; a new 345/138-kV substation; and new underground 138-kV lines to connect the substation to a smaller Foxconn-owned substation near the plant. (See MISO Seeks Stakeholder Input on Foxconn Decision.) MISO’s decision was based on ATC’s forecasted load of 230 MW, although Foxconn says there’s potential for campus expansion at the site, possibly adding another 200 MW of load.
Stakeholders had little to say about the project, although some asked the RTO to make more widely circulated announcements when it wraps up expedited review studies and when it plans to announce expedited decisions.
New York’s Integrating Public Policy Task Force (IPPTF) on Monday debated a proposal seeking to align the state’s effort to price carbon with the Regional Greenhouse Gas Initiative. It also discussed an alternative to NYISO’s capacity market.
Representatives from the Long Island Power Authority (LIPA) and National Grid made presentations as part of the ongoing process to develop a straw proposal for pricing carbon into the state’s wholesale electricity market, a joint effort by NYISO and the state’s Department of Public Service (17-01821) that aims to deliver a workable plan by year’s end.
The IPPTF’s work plan includes five issue tracks: 1) straw proposal development; 2) wholesale energy market mechanics and interaction with other wholesale market processes; 3) policy mechanics, such as setting the carbon charge; 4) interaction with other state policies; and 5) customer impacts. (See NYC, Goals Dominate Talk on Carbon Pricing.) The effort is still in the first track, slated to conclude March 19.
Regional Circuit Breaker
During his presentation, LIPA Director of Power Markets Policy David Clarke asked that “NYISO and DPS think about the carbon abatement cost curve throughout the RGGI region, what it might look like, what it might cost to buy and retire allowances along the curve and how far we might go to narrow differences by doing so, especially considering the roles of the cost-containment reserve.” The RGGI reserve contains allowances only released if allowance prices exceed predefined levels.
New York could reduce its carbon emissions at a lower cost by drawing on the broader region and a wider geographic set of abatement alternatives, Clarke said.
Projected RGGI allowance prices in constant 2015 and nominal dollars | ICF
“RGGI has a 10-million-ton reserve, priced in 2025 a little over $17 a ton. Essentially, it’s a circuit breaker,” Clarke said. “So RGGI states have agreed to this circuit breaker, a price increase they can live with if the market’s carbon price went too high.”
LIPA considers the state’s Clean Energy Standard (CES) goals — principally, an 80% emissions reduction by 2050 — as a starting point for pricing carbon and wants NYISO to consider an approach that increases the state’s carbon prices to the RGGI cost-containment reserve price. The power agency noted that the draft 2017 Policy Scenario Overview, prepared by ICF International for RGGI in June 2017, pointed to a “wide range” of projected 2025 allowance prices, “the lowest of which accompany high renewable build-out scenarios, but most are well below $17/ton for 2025.”
CES Impact on RGGI Prices | The Brattle Group
Clarke noted that, in The Brattle Group’s report on the social cost of pricing carbon in New York, the “starting point was a $40 adder above the assumed $17 price, so they were looking at $57-58/ton as the carbon adder.”
“The Brattle proposal is to take the carbon price and raise it into the marketplace and get some marketplace reductions, and it raises it quite a lot,” said Mark Reeder of the Alliance for Clean Energy New York. “And [LIPA] seems to be proposing as an alternative to that — [that] New York retires RGGI allowances and raises the price in the market for carbon that New York sees. But it’s not just New York; it’s everybody else [that sees a higher price], and it’s an alternative way of getting the market to see a higher price of carbon.”
Clarke agreed that was “a more or less” accurate summary of LIPA’s thinking.
“We observe that the RGGI prices are likely to trade well below the cost-containment reserve level if nothing changes,” Clarke said. “And from a loads perspective, buying and retiring allowances below this price can be significantly less expensive than the average cost loads would pay under an approach that sets a carbon adder at the social cost of carbon.”
Under current regulations, any entity, including a state or load-serving entity, can set up an account to buy allowances. RGGI regulations also provide for retiring allowances from voluntary reductions, so there are a couple mechanisms to buy or retire allowances up to the cost-containment reserve price, Clarke said.
Alternative Market Design
Ben Carron, National Grid’s senior analyst for regulatory strategy and integrated analytics, presented the company’s Dynamic Forward Clean Energy Market (DFCEM) concept, an alternative to the capacity and renewable energy credits markets in New York. Under the idea, the state would use an auction to procure the clean energy attribute from a resource, but not the energy itself. The model is designed to incentivize development of new clean energy resources and retain existing ones in order to reduce emissions.
Carron noted that “the concept is being discussed in the [Integrating Markets and Public Policy] process in New England,” but he emphasized that he was speaking on behalf of National Grid and not the other consortium members that created it. (See NECA Panelists Talk Carbon Pricing, Northern Pass.)
“We share similar concerns to those presented last week by the city of New York, which is that this needs to be considered on an economy-wide scale,” Carron said.
Locational Incentives for Clean Energy | The Brattle Group
While the task force is only addressing how to harmonize wholesale energy markets with public policies in the energy sector, Carron said a wider approach could avoid creating perverse incentives and ensure that stakeholders understand how it is going to interact with other components of the state’s energy plan.
“Doing some upfront work to establish the cost of carbon abatement in each sector would be a useful exercise for policymaking in all sectors and would inform the potential for leakage across sectors in this effort,” Carron said.
Reeder said the DFCEM appeared similar to New York State Energy Research and Development Authority auction processes for obtaining renewable resources, in which one Tier 1 REC represents the energy production of 1 MWh.
“Ostensibly, that achieves a similar outcome if I think about the CES objective [of] around 50% renewables by date X,” Reeder said. “So how would this interplay with what NYSERDA does right now? Is it a complement? Is it a supplement? Would it essentially obviate the need for NYSERDA to do what they do now?”
“I think that it might obviate the need,” Carron said. “We should create a wholesale market solution that accomplishes as much of what we’re setting out to do with public policy as possible.”
Track 2 Issues and Scheduling
The task force also reviewed a plan for Track 2 of its work, which will deal with wholesale energy market mechanics — including “carbon leakage” and how to measure emissions — and interaction with other wholesale market processes.
The plan lays out Track 2 meetings from April to July before the suggested Aug. 1 deadline for draft recommendations. The joint staff will present frameworks for Track 2 issues of each meeting and also left some meeting dates open to resolve thorny issues — such as leakage — that may require additional discussion.
| IPPTF
Representing New York City, Couch White attorney Kevin Lang expressed concern about transmission being slated for discussion on July 30, just two days before the deadline for draft recommendations.
“Waiting until the end of July to talk about transmission is way too late,” Lang said.
IPPTF co-chair Nicole Bouchez, NYISO market design specialist, said the task force would consider earlier discussions on the subject but that it did not foresee the draft recommendations covering every issue.
In addition to transmission, Track 2 will also deal with leakage and resource shuffling; emission rates for generators; carbon shadow price; carbon charge implementation; emission rates for distributed energy resources and demand response; fuel blends; how much transparency is available; the mechanics of allocating carbon revenues; credit implications; capacity market implications; and bilateral arrangements.
The task force next meets Feb. 19 at NYISO headquarters.
Some energy resource developers in California say CAISO needs to change its interconnection rules to prevent financially unviable projects from lingering in the queue and affecting more sound projects.
CAISO’s annual Interconnection Process Enhancements (IPE) process is becoming increasingly complex as the state’s generation mix changes, with renewables and storage comprising the vast majority of projects currently in the queue. The ISO outlined its 2018 IPE in an issue paper last month. (See CAISO Launches Interconnection Initiative.)
The majority of generation projects in the CAISO interconnection queue are renewables.
As part of the initiative, CAISO asked for comment on whether it should alter its Transmission Plan Deliverability (TPD) allocation, which establishes the amount of additional transmission capacity needed for projects to achieve deliverability and determines generators’ cost responsibility for network upgrades costs. Projects allocated sufficient TPD receive reimbursement for their upgrades. CAISO uses a point system to allocate TPD based on project status, including the status of project financing, power purchase agreements, regulatory approvals, land acquisition, and other factors.
CAISO’s current process provides interconnection customers with two annual opportunities for earning TPD allocations following Phase II interconnection studies and after one year of parking in the queue. Under revisions filed with FERC, which the ISO says are likely to be approved, a third annual opportunity for a TPD allocation will be made available to interconnection customers following a second year of parking. Projects that don’t qualify for a TPD allocation following the three opportunities must convert to energy-only status — making them ineligible for resource adequacy payments — or withdraw from the queue.
In its comments to CAISO, Southern California Edison (SCE) said it opposes allowing projects to remain in the queue indefinitely and to have endless opportunities to apply for deliverability status.
“Such projects remaining in the queue open-endedly without making progress towards their commercial operation negatively affect other active projects,” the company said.
SCE said projects not allocated TPD by the end of the second parking period should be required to execute the agreement and proceed as energy-only or be suspended, allowing for a three-year period during which they retain priority for TPD allocation. Two parking periods and a three-year suspension should be adequate, the utility said.
Differing Opinions on TPD Allocation Changes
Utility-scale developer First Solar said that forcing projects into “energy-only” status and large forfeiture amounts that become due if a project withdraws might incite developers to choose energy-only status rather than depart the queue. The company said the issue is compounded by a lack of transparency of available deliverability at interconnection points on the CAISO grid.
“Deliverability is critical for marketing a project, as energy-only projects currently are less appealing due to their lack of resource adequacy attribute and are therefore less competitive in procurement,” First Solar said. “We ask the CAISO to address several issues that prevent interconnection customers from being allocated or retaining deliverability, as well as issues that have impacts on others in the queue.”
CAISO resource developers have competing views of how interconnection policies should be overhauled.
But the state’s Office of Ratepayer Advocates (ORA) said it did not support changes to the current TPD allocation process that allows three opportunities for TPD allocation, rather than allowing projects to remain in the queue indefinitely.
“Changes in the queue procedures should only be considered for resources that meet project area needs, support state resource targets or CAISO-controlled grid needs, such as resources that can respond to grid demands throughout the day and/or provide additional services in addition to energy,” ORA said.
The California Wind Energy Association said that with the third allocation option on file at FERC, “there is no need to tinker with the TPD allocation process. We suggest that this IPE element be tabled.”
Independent transmission company ITC said it supports inclusion of the possible TPD changes in the scope of the 2018 IPE stakeholder initiative as part of its “broader support” for studying the impacts of allowing projects with potentially limited commercial viability to remain in the queue and seek TPD allocation.
ITC also recommended the initiative further examine “how identified impacts of an interconnection request on neighboring systems are coordinated and mitigated” to “consider additional clarifications to Affected System practices.”
The company pointed to FERC’s recent order on a complaint by the Environmental Defense Fund regarding MISO, PJM, and SPP Affected System studies. Earlier this month, the commission ordered a technical conference after finding the RTOs’ tariffs and joint operating agreement do not fully explain the guidelines and timelines that the RTOs use to coordinate with other affected systems during the interconnection process. (See FERC Orders Review of PJM, MISO, SPP Generator Studies.)
As of Jan. 1, the ISO’s interconnection queue contained about 43,000 MW of proposed generation, including about 28,000 MW of renewables, 12,000 MW of storage, and 2,800 MW of other resources, documents show.
Constitution Pipeline on Monday asked FERC to reconsider a January order upholding a denial of the company’s water permit application by New York environmental regulators, saying the commission “erred” in its interpretation of the federal Clean Water Act.
At issue is a proposed 124-mile natural gas pipeline originating in Pennsylvania that would deliver 650,000 dekatherms of gas per day into upstate New York.
First sections of Constitution Pipeline arrive in New York | Constitution Pipeline
Constitution last October petitioned the commission to rule that the New York State Department of Environmental Conservation (NYSDEC) had waived its authority under Section 401 of the Clean Water Act by failing to issue or deny a water quality certification within the one-year “reasonable period of time” stipulated by the act, despite the company’s cycle of withdrawing and resubmitting the application.
But the commission disagreed, ruling last month “that once an application is withdrawn, no matter how formulaic or perfunctory the process of withdrawal and resubmission is, the refiling of an application restarts the one-year waiver period under section 401(a)(1).”
Nonetheless, the commission said it continued to be concerned “that states and project sponsors that engage in repeated withdrawal and refiling of applications for water quality certifications are acting, in many cases, contrary to the public interest and to the spirit of the Clean Water Act by failing to provide reasonably expeditious state decisions.” (See FERC Upholds New York Denial of Constitution Pipeline.)
Constitution’s Feb. 12 petition calls on the commission “to curb this abuse of [the] legal process” in which DEC “has succeeded in delaying and frustrating the certification review process by claiming that Constitution’s serial submissions entitle the agency to successive year-long review periods.”
“The Commission erred in its interpretation of the “reasonable period of time” in this case because the mechanical application of the final submission date of April 27, 2015, wrongfully allowed NYSDEC to exceed the maximum allowable period of time under the Clean Water Act,” Constitution said.
The pipeline developer contends that the commission is fostering a regulatory scheme detrimental to the public interest and that its Jan. 11 order enables NYSDEC “to abdicate its responsibilities.” The company noted that, except for the Clean Water Act approvals, the project is federally approved and its right-of-way has been optioned or acquired.
“The piping and equipment for this project have now been held in storage for over three years, and the pipeline remains fully contracted with long-term commitments from established natural gas producers currently operating in Pennsylvania,” said the petition, which also requested expedited action by the commission to prevent further delay.
Constitution said its pipeline is a “critical natural gas infrastructure needed to meet the natural gas demands of the Northeast United States – the current winter supply and pricing environment in New England making this point most clear and obvious.” (See FERC, RTOs: Grid Performed Better in Jan. Cold Snap vs. 2014.)
In a proceeding related to the Millennium Pipeline, FERC last September ruled against the NYSDEC on a similar issue of timeliness, finding the agency had waived its authority to issue or deny a water quality certification for the project by failing to act within the one-year time frame required by the Clean Water Act (CP16-17). (See Environmentalists Denounce FERC Millennium Pipeline Ruling.)
SPP’s Market Monitoring Unit (MMU) last week conducted its first quarterly market report webinar, importing a practice MMU Executive Director Keith Collins used while at CAISO.
“It is not only a great forum for us to present on our quarterly report, but it also allows for great interactive discussion between market participants and market monitoring staff,” said Collins, who joined the MMU last year.
Staff reviewed the report’s highlights, focusing, as the report did, on the SPP market’s growing frequency of negative price intervals. The MMU said the market’s practice of self-committing resources in the day-ahead market may be exacerbating the situation.
“We’re not saying negative prices are bad, but they are an indication of what happens on the system as a consequence of thousands of megawatts not participating in the day-ahead market,” Collins told participants. “When they show up in the real-time market, it can create this disconnect.”
Negative Prices | SPP MMU Fall 2017 Quarterly Report
Collins said the MMU will repeat the practice following each quarterly and annual market report. The calls are open to members, market participants and regulatory staff, among other stakeholders.
“Our goal is to improve the markets through education and understanding of market outcomes,” he said.
December MISO-SPP M2M Results in $4.2M in Charges
SPP recorded its third consecutive month of multimillion-dollar market-to-market (M2M) payments from MISO in December, staff told the Seams Steering Committee on Feb. 7. The month’s $4.2 million in charges pushed the amount of M2M payments to SPP past $36.8 million.
M2M Update December 2017 | SPP
Permanent and temporary flowgates were binding for 531 hours in December. SPP’s Riverton-Neosho-Blackberry flowgate on the Kansas-Missouri border was once again responsible for the bulk of the charges.
The two RTOs began the process in March 2015. SPP last month said it has reimbursed MISO more than $2.25 million after resettlements of several M2M flowgates, and that it will continue to perform “limited” resettlements because of a memorandum of understanding between the two. (See “SPP Pays MISO $2.25M After M2M Resettlements,” SPP Markets and Operations Policy Committee Briefs: Jan. 16-17, 2018.)
Staff also briefed the committee on the Feb. 27 MISO-SPP Interregional Planning Stakeholder Advisory Committee meeting. The RTOs’ staff and stakeholders will discuss improvements to the Coordinated System Plan, which has identified four potential seams projects in two previous iterations. None of the four survived regional reviews.
SPP is also trying to meet with Associated Electric Cooperative Inc. before March 9. Staff have drafted a scope that identified needs from its 2018 Integrated Transmission Planning Near-term Assessment that are “electrically significant to the SPP-AECI seam.”
Board Approves Non-Jurisdictional Tariff Change
The Board of Directors approved a Tariff revision that incorporates a refund obligation for SPP’s nonpublic transmission-owning utility members during a special conference call Monday afternoon.
The measure addresses a FERC directive that SPP require non-jurisdictional transmission owners to refund revenues received associated with their service, and that it enforce the membership agreement in court (EL18-19). The RTO has a Feb. 28 filing deadline in the docket. (See FERC Backs off Nonpublic Utility Refunds in MISO, SPP.)
The 20-person Members Committee was divided on its advisory vote to the board, with five members — Empire District Electric, Oklahoma Gas & Electric, Public Service Company of Oklahoma, Southwestern Public Service and Westar Energy — casting opposing votes.
The proposal, which was recommended by the Corporate Governance Committee, includes a provision that should there be a conflict between a FERC refund order and state statute, the refund amount would be deemed uncollectable. Members questioned why non-jurisdictional members should be treated differently than investor-owned utilities and whether their customers might pick up the tab for those entities unable to provide refunds.
“If our customers are overpaid and there’s a refund order, our customers are left with a short amount,” said OG&E’s Greg McAuley.
Kansas City Power & Light’s Denise Buffington, who represents IOUs on the CGC, said she supported the measure because of her understanding that the Nebraska Constitution prevents its entities from delegating authority to someone else.
“I’m OK with this if SPP can show how everyone else will be kept harmless,” she said. “I will be closely scrutinizing the SPP filing. If it doesn’t show harm to other members, we will be filing comments in the docket.”
FERC ruled Friday that the developer of a proposed 1,500-MW Indiana wind farm must go to the end of the interconnection queue to move its point of interconnection (POI) 2.9 miles.
The commission’s Feb. 9 order rejected Harvest Wind’s request for a waiver allowing it to change the POI without triggering the “material modification” language under PJM’s Tariff. FERC sided with PJM in requiring a new queue application and facilities study (ER18-615).
Colorado-based Renewable Energy Systems Americas acquired the Harvest Wind project after the previous developer agreed in late 2016 to move to a second POI after AEP Indiana Michigan Transmission said the original was not a suitable spot for the wind farm’s 765-kV switchyard.
RES Americas said it learned in fall 2017 that the new location, POI 2, had some of the same problems as the original location, including wetlands and endangered species concerns. In addition, noise from the switchyard’s transformers would be too loud because of nearby houses, the company said in its Jan. 5 waiver request.
The developer said its proposed interconnection, POI 3, is “electrically identical” to the current location because it is just 2.9 miles away on the same 765-kV transmission line.
PJM opposed the request, arguing that the waiver would delay other projects in the queue because of the size of the wind project and the need for transmission restudies.
The commission agreed with PJM, finding that “Harvest Wind has not sufficiently demonstrated that it acted in good faith. Harvest Wind states that it became aware in September 2016 that both POI 1 and POI 2 presented some complicating factors due to site topology, but at that time it did not believe these factors were insurmountable. … Moreover, Harvest Wind fails to explain why it did not discover these additional complications for almost a year after initially being put on notice that complications existed at POI 1 and POI 2, demonstrating a lack of due diligence on Harvest Wind’s part.
“Harvest Wind has not sufficiently demonstrated that granting the waiver request will not have undesirable consequences or harm third parties,” the commission continued. “We agree with PJM that changing the point of interconnection at this late stage would introduce uncertainty that could well impact other lower-queued interconnection customers and that such restudy of the point of interconnection would require reassessment of protection, requiring the expenditure of time and resources, thus burdening and harming other parties.”
RES Americas said in its waiver request that it might be forced to abandon the project if the waiver were not approved.
An RES Americas spokesman said the company was “planning to proceed with the project” but did not say why a delay might force it to abandon it.
FERC approved PJM Tariff and Operating Agreement revisions incorporating two pro forma pseudo-tie agreements and a pro forma reimbursement agreement effective Nov. 9, 2017.
The commission’s Feb. 5 order rejected protests by MISO’s Independent Market Monitor, NYISO, American Municipal Power, Illinois Municipal Electric Agency and North Carolina Electric Membership Corp. (ER17-2291). (See Critics Protest PJM Dynamic Transfers Plan.)
| MISO, PJM
In its protest, NYISO said PJM’s rules will likely cause “adverse reliability impacts” and “exacerbate interregional seams.” But PJM pointed out that there are no resources currently pseudo-tied into PJM from NYISO.
The MISO Monitor David Patton contended FERC should not consider PJM’s proposal separately from other pending pseudo-tie proceedings. The plan creates “substantial economic and reliability harm to the customers in [the MISO and PJM] area,” he said.
The commission was unpersuaded, saying: “The terms of the proposed revisions and pseudo-tie agreements are not unjust and unreasonable merely because the commission has not yet acted in the other proceedings.” FERC also rejected the Monitor’s request for a technical conference.
“We agree with PJM that the pseudo-tie agreements and corresponding Tariff and Operating Agreement revisions promote uniformity among the pseudo-tie and dynamic schedule requirements and increase the transparency and efficiency of the implementation process,” the commission said.
California regulators on Thursday approved an order putting new requirements on community choice aggregators (CCAs), saying the decision did not come easily.
At the same time, CCAs and their supporters are arguing for more transparency and control over resource adequacy (RA) procurement.
“I just have overwhelming anxiety about the purpose of resource adequacy,” California Public Utilities Commission President Michael Picker said, addressing a crowded hearing room at commission headquarters in San Francisco after a public comment period. “It seems as if people have forgotten the energy crisis of 2001 and 2002.”
The State Legislature authorized the creation of CCAs in 2002 in response to the energy crisis, allowing local governments to directly contract for energy services to serve their residents. CCAs did not begin appearing until 2010 but have since grown rapidly.
Until now, CCAs have avoided the requirement to carry RA reserves, even as they’ve taken on a greater share of California load. Instead, customers of investor-owned utilities have been left with stranded costs because of the timing of load forecast submissions and RA allocations, in some cases procuring RA for customers about to be served by CCAs. Cost-shifting can run into the tens of millions of dollars annually, the CPUC said.
Picker struck an assertive tone on the RA issue, saying that grid reliability is at stake as procurement of electricity disaggregates through CCAs, which he’s unsure could meet critical grid needs.
“It really makes me nervous and it makes me wonder if people are really prepared to embrace this opportunity to serve as [load-serving entities],” Picker said, adding that the CPUC made reasonable efforts to accommodate the concerns of CCA supporters.
The CPUC made changes to its initial RA proposal in response to written comments, including extending the deadline for CCAs to submit their RA implementation plans until March 1 in order to allow several of them to begin serving their new customers in 2019. The CPUC also created two waiver options, one in which CCAs and IOUs can agree on the CCA’s RA requirements and cost responsibility, and another stipulating that if agreement was not reached, the CCA agrees to be bound by a future CPUC determination in the RA proceeding regarding its RA cost responsibility.
Many of the more than 40 registered speakers attending the CPUC hearing were there to speak against the CCA ruling. West Hollywood City Councilmember Lindsey Horvath told the CPUC that CCA customer energy costs must be determined in a fair and open process.
“How can we properly determine our fair share without access to contracts we’re being asked to account for?” Horvath asked. “We are glad to see the direction the commission is moving with in the current form of its resolution, but we’re not there yet.”
The CPUC introduced the proposal in December with a comment period near the holidays, leaving CCA representatives saying the expedited order did not give them time to provide input. (See California Proposes Resource Adequacy Obligations for CCAs.) Other proponents said it would delay CCA creation and slow achievement of climate goals. CCAs have grown rapidly and are popular as a way for localities to take control of energy consumption, with many marketed as green energy options.
But Picker said that if the decision delays the implementation of CCAs, “we are just going to have to live with that.” The consequences of having grid failure “can wipe the slate clean,” he said, again invoking the reliability crisis of the early 2000s.
Commissioners appeared sympathetic to CCA supporters, but Martha Guzman Aceves said that issues with the RA program have led to more procurement of natural gas generation.
“This is a problem to reaching our climate goals,” she said. “This is actually an environmental justice issue for me.” She added that, “Sometimes we don’t use the best process, I totally acknowledge that. But we need to deal with this problem now.”
“There has got to be good dialogue, there has to be trust,” Commissioner Carla Peterman said. “The last thing I want is to exacerbate tension between the CCAs, the utilities and the commission.”
In its order, the CPUC said: “Numerous commenters assert that the resolution violates their due process rights. We disagree. The changes in the CCA timeline made by this resolution are an exercise of authority the commission has had since 2002.”
Decision Adopts IRP Process
Another decision approved by the CPUC on Thursday sets RA requirements for all California LSEs. It institutes a two-year integrated resource planning process including electrical cooperatives, IOUs, CCAs and electric service providers.
The decision also recommends the state’s Air Resources Board adopt a greenhouse gas emissions target for the electric sector of 42 million metric tons by 2030, a 50% reduction from 2015 levels.
CPUC Delays Gas Moratorium Vote
In other items on the CPUC decision list, the commission tabled a proposal to require Southern California Gas to enact a moratorium on new commercial and industrial natural gas connections in Los Angeles County because of supply issues.
The CPUC said that while conservation measures by customers in response to the Aliso Canyon storage facility have helped, “significant new reliability challenges on the SoCalGas system exist due to a series of major unplanned outages and maintenance issues. The Los Angeles region faces greater uncertainty than a year ago with respect to the ability of SoCalGas to meet customer demand this winter.”
FORT LAUDERDALE, Fla. — The chairman of NERC’s Board of Trustees said last week the organization hopes to have a new CEO in place by the summer.
Roy Thilly told the Member Representatives Committee (MRC) during its Feb. 7 quarterly meeting that the selection process is “well underway,” with a goal for this spring.
“This is an important decision the full board needs to be involved in,” he said.
Russell Reynolds Associates has been conducting the executive search. Thilly said the board will select a group of about eight potential candidates, with a small group of trustees whittling that list down to two or three final candidates. The board will interview each of the finalists.
“Essentially, we want to be enthusiastic about the final candidate and have no hesitation that we have the right person for this job,” Thilly said. “If we don’t, then it’s important that we step back and take the time to do so.”
NERC has been without a CEO since Gerry Cauley resigned in November following his arrest for domestic abuse. General Counsel Charlie Berardesco stepped into the CEO role on an interim basis. (See Cauley Resigns; NERC Launches Search for Replacement.)
Thilly complimented NERC’s management team and staff for “really stepping up,” along with the Regional Entity CEOs.
“We feel like we’re in a good place right now,” he said. “The feedback I’ve gotten is that Charlie has stepped into the job in a seamless way and pulled the organization together.”
NERC also needs to hire a new chief security officer to replace Marcus Sachs, who resigned shortly after Cauley. (See NERC Parts Ways with Chief Security Officer.) Thilly said candidates have been “assembled,” but the agency won’t move forward until the new CEO is in place.
“It’s essential the new CEO participate in that hiring process and be very comfortable with the selection,” he said.
FERC’s McIntyre Says Resiliency Still of Interest in DC
FERC Chairman Kevin McIntyre told NERC trustees and stakeholders that the federal government still remains focused on grid resiliency, despite the commission’s rejection of the Department of Energy’s Notice of Proposed Rulemaking meant to address the issue. FERC launched a new resiliency initiative Jan. 8 after declining to take up the department’s proposal.
“Interest in that subject is not waning on [Capitol Hill], and it is not waning in the administration,” McIntyre said. “When real-world engagements occur with resiliency, like it’s old-fashioned cousin, reliability, we should use that as a teachable moment, and take lessons forward into the game plan and be better prepared for future events.”
McIntyre said the commission looks forward to working with NERC, and that it must remain “vigilant” in ensuring the grid’s resiliency, “a phrase you’ve no doubt heard.”
McIntyre and Berardesco were among several industry witnesses who recently testified before the Senate Energy and Natural Resources Committee about the January “cold-weather bomb.” (See FERC, RTOs: Grid Performed Better in Jan. Cold Snap vs. 2014.)
“Hanging in the air was the broader overall topic of grid resiliency,” McIntyre said. “I was very glad to be in a position to report that, based on various analyses, the bulk power system operated very reliably. My general impression was that my report, and those of the other witnesses, was well-received and appreciated in how well the grid performed.”
Resiliency is a priority at FERC, McIntyre said, and he expressed his gratitude to NERC for its work on the issue. He referenced the MRC’s Reliability Issues Steering Committee, which, at the trustees’ request, is developing a framework for resiliency.
The committee told stakeholders that most resilience definitions have two common elements: that it is “time-dependent” and differs from business-as-usual operations, and that it cannot be measured in a single-unit metric. It said the National Infrastructure Advisory Council’s framework for establishing critical infrastructure goals is a “credible source for further understanding and defining resilience.”
Bruce Walker, assistant secretary of the Energy Department’s Office of Electricity Delivery and Energy Reliability, said the department’s goal is to develop partnerships within the industry and provide resources to move issues forward.
“We have the opportunity to see the results of real work being done by FERC and NERC, and to shape policy through our coordination with both of these agencies,” said Walker, whose nomination was approved in October. “The [DOE] has stepped back to take a look at what our mission really is. It is … our mission-critical focus across the energy sector.”
Walker, formerly a deputy executive for Putnam County, N.Y., ran a boutique consulting firm focused on risk management at investor-owned utilities and served in leadership positions at National Grid and Consolidated Edison. He said his first goal is to develop a North American energy model “that integrates all different forms of energy so that we can run, like we do on our transmission system, a load flow.”
He said the bulk power system’s interdependencies will identify “those assets than can be enhanced, replaced or installed” to improve the system’s “affordability” as “we start moving forward” with the administration’s proposed $1.5 trillion infrastructure bill.
Other goals will focus on cyber and physical security, rapidly moving forward storage technologies, making use of sensing technologies and developing hardening strategies that add “some resiliency in a viable way.”
Jim Robb, CEO for the Western Electricity Coordinating Council, said recent developments within the Western Interconnection have put “substantial financial pressure” on Peak Reliability, the region’s delegated reliability coordinator (RC).
Within the past few months, Peak has announced it would team up with PJM Connext to attract participants to a new Western energy market. (See Peak, PJM Pitch ‘Marketplace for the West’.)
“Obviously, significant changes are going on that create a lot of uncertainty about how the ultimate reliability landscape will play out,” Robb said. He thanked FERC staff for working with WECC staff “as we move to a multiple RC model.”
NERC, WECC, British Columbia Agree to MOU
The board unanimously approved a memorandum of understanding between the British Columbia Utilities Commission (BCUC), WECC and NERC.
Modeled on recent MOUs with other Canadian jurisdictions, the agreement recognizes the parties’ roles under existing laws and authorities, maintains the status quo on funding arrangements, and provides for sharing of confidential and compliance-related information. WECC will periodically provide information on the Canadian province’s noncompliance for NERC’s review.
WECC General Counsel Steve Goodwill said a fully executed MOU should be in place in March, pending board approval from NERC and WECC.
NERC began formal correspondence with British Columbian authorities in 2006, while WECC has provided compliance monitoring for BCUC since 2009 through an administration agreement.
Goodwill said WECC is also negotiating similar terms with Mexico that recognize the changes in that country’s regulatory structure.
“Like the MOU with British Columbia, it will openly recognize for the first time the ability to share critical information on compliance enforcement in Mexico with NERC,” Goodwill said. “This is an all-around good story. The ability to share data among ourselves is critical.”
The MRC approved two new members and re-elected two incumbents to the board. Suzanne Keenan was elected to a two-year term expiring in 2020 and Rob Manning to a three-year term expiring in 2021, while George Hawkins and Jan Schori were re-elected to three-year terms also expiring in 2021.
Keenan served as CIO and senior vice president of process improvement for Wawa from 2008 to 2017. Her industry experience includes field services, re-engineering and performance, regulatory performance, and emergency preparedness experience with PECO Energy.
Hawkins, CEO of the D.C. Water and Sewer Authority, was first elected to the board in 2015. He serves on the Standards Oversight & Technology and Corporate Governance & Human Resources committees.
Manning was involved in transmission and distribution infrastructure research for the Electric Power Research Institute but will give up those duties with his election. He also spent six years with the Tennessee Valley Authority.
Schori, former CEO of the Sacramento Municipal Utility District for more than 14 years, was elected to the board in February 2009. She chairs the Finance and Audit Committee and serves on the Compliance and Enterprise-wide Risk committees.
