FERC on Friday accepted revisions to PJM’s long-term financial transmission rights auctions to correct current processes that might overstate available system capacity and harm auction revenue rights holders (ER18-1968).
The current process allows long-term FTR market participants to obtain the rights to congestion on transmission paths before the owners of the underlying ARRs.
Following each annual FTR auction, PJM conducts a long-term FTR auction for the three planning years immediately following the planning year during which the long-term FTR auction is conducted. Offered for sale is the residual system capability after the annual ARR allocations and the annual FTR auction. In determining the residual capability, PJM assumes that all allocated ARRs are self-scheduled into FTRs, which are modeled as fixed injections and withdrawals in the long-term FTR auction.
Cleared auction volume (MW) as a percent of total FTR cleared volume by calendar month | Monitoring Analytics
Under the new rules, PJM will revise how it compiles the paths available in the auction by conducting an additional, offline annual allocation of ARRs prior to the opening of each round of the long-term FTR auction. The procedure will use the same topology as the annual ARR allocation except that all transmission outages will be returned to service and PJM will perform its simultaneous feasibility test to determine the set of ARRs to be preserved for the long-term FTR auction. (See “Stakeholders Approve Manual, Operational Changes,” PJM MRC/MC Briefs: June 21, 2018.)
FERC also granted PJM’s request to eliminate the three-year long-term FTR product. The auction currently offers FTRs separately for each of the subsequent three planning years, as well as for all three years combined. Historically, bidding for the three-year product is low and eliminating it will increase the efficiency of PJM’s FTR software, the RTO said.
The commission also granted PJM’s Sept. 3 effective date in order to implement the changes in the next round of its long-term FTR auction commencing Sept. 4.
RTO Insider filed a complaint Friday asking FERC to overturn the New England Power Pool’s ban on press coverage of its meetings or terminate the group’s role and direct ISO-NE to adopt an open stakeholder process similar to those used by other RTOs.
The Section 206 complaint (EL18-196) comes two weeks after NEPOOL submitted a proposal to FERC seeking to codify an unwritten policy of banning news reporters and the public from attending the group’s stakeholder meetings . (See NEPOOL Files Press Ban with FERC.) New England is the only one of the seven U.S. regions served by RTOs or ISOs where the press and public are prohibited from attending stakeholder meetings.
NEPOOL’s proposed amendments to the NEPOOL Agreement would add a definition of “press” and bar anyone working as a journalist from becoming a NEPOOL member or alternate for a participant. The group drafted the revisions after RTO Insider reporter Michael Kuser, who lives in Vermont, applied for membership in NEPOOL’s Participants Committee as an end-user customer in March.
Chilling Discussion?
In its filing, NEPOOL contended that allowing press to become a participant “would adversely impact the power pool’s ability to continue to foster candid discussions and negotiations in its stakeholder meetings.” Absent those discussions among its members, ISO-NE and state officials, NEPOOL “would be limited in its ability to narrow or resolve complex issues within the NEPOOL stakeholder process,” the group said.
It cited concerns that press attendance at meetings “could encourage public posturing, pre-scripted statements and reduced willingness or ability by members to freely explore ideas or solutions.”
FERC Commissioner Neil Chatterjee spoke at NEPOOL’s December Participants Committee meeting at the Colonnade Hotel in Boston. | NEPOOL
NEPOOL’s case for maintaining privacy pivots on the argument that it does not function in the same manner as other RTOs. Its filing notes that “unlike other regional transmission organizations in which stakeholders are assembled by and at the direction of the particular RTO, NEPOOL is and always has been an independent, separately organized stakeholder body.”
To support its claims, the power pool’s filing included the testimony of Robert Stein, principal consultant at Signal Hill consulting group, who said he has participated in the NEPOOL stakeholder process since beginning his career in the power industry in 1971.
Stein testified that the power pool’s meetings have always been “nonpublic,” and expressed concern that the press’ presence would change the “tenor and tone” of NEPOOL meetings “in a very unhelpful way.”
“Over the years I have both observed and participated in discussions at meetings where positions were taken and changed in our non-public setting,” he said. “This would be much less likely if members are concerned that those positions, as they may evolve during the NEPOOL process, could appear in press reports and need to be defended publicly. There are many examples, such as in diplomacy and labor negotiations, where the ability to negotiate outside the public spotlight is important if not essential.”
‘No Apparent Basis’
RTO Insider responded that Stein “has no apparent basis for this speculation” given his testimony that NEPOOL meetings have always been nonpublic and that he has worked his entire career in New England.
RTO Insider estimated it has covered 900 stakeholder meetings in the other six RTOs/ISOs since 2013 and said its reporters can recall fewer than 10 instances of a stakeholder representative reading from a prepared speech.
RTO Insider’s Aug. 31 complaint contended that nonpublic meetings violate the public interest and the missions stated in ISO-NE’s and NEPOOL’s governing documents.
It also contested NEPOOL’s assertion that it is a private organization, saying that FERC precedent “hardwires the NEPOOL stakeholder process into the regulatory process by requiring its use.” It noted that ISO-NE’s Participants Agreement with NEPOOL requires the RTO “to present proposals for changes to market rules, operating procedures, manuals, reliability standards, general tariff provisions, or non-[transmission owner] [open access transmission tariff] provisions for governance participant consideration and NEPOOL participant vote.”
NEPOOL conducted 253 votes on 56 meeting days in 2017. All the meetings were closed to the public and press. | NEPOOL
RTO Insider pointed to another special privilege enjoyed by NEPOOL: its so-called “jump ball” filing rights at FERC. In cases when ISO-NE submits a market rules proposal that differs from one approved by the Participants Committee on a 60% vote, that provision entitles NEPOOL to file a competing proposal that the commission can adopt in full.
“This is an extraordinary right because it negates the right an RTO/ISO would otherwise have for its [Federal Power Act] Section 205 filing to be accepted if just and reasonable (or not unjust and unreasonable), rather than having to demonstrate that its filing is superior to alternatives,” RTO Insider contended.
The publisher also contended that, given NEPOOL’s role in transmission planning, failure to provide openness and transparency violates FERC Order 890. Banning the press and public from meetings also discriminates against smaller entities and potential new entrants to the New England market, the complaint said.
The publisher noted that ISO-NE, through NEPOOL, is the only RTO/ISO in the country that bars the press and public from its stakeholder process. “NEPOOL is well aware of this uniqueness, but nowhere in its 15-page transmittal letter in support of formalizing its press ban does it attempt to explain why ISO-NE/NEPOOL are fundamentally different from all the other RTO/ISOs,” the complaint said. “Nowhere does NEPOOL explain why secrecy is critical for it and it alone.”
RTO Insider said that if the power pool can justify its press ban as a “private” entity desiring secrecy, “its special powers and privileges should be transferred to an open stakeholder process within ISO-NE, and the ISO-NE resources devoted to NEPOOL (currently $2.6 million annually) should be devoted to an open stakeholder process within ISO-NE.”
NEPOOL Docket
RTO Insider also will file the complaint as a protest in the docket opened by NEPOOL (ER18-2208).
No one else has thus far filed substantive comments, although Consolidated Edison, Avangrid, Public Citizen and New Hampshire Consumer Advocate D. Maurice Kreis have filed motions to intervene. FERC extended the deadline for comments in that docket by 10 days to Sept. 14.
“Somehow the nation’s other six RTOs manage to make difficult policy choices without a secret governance body for stakeholders,” Kreis said in a June 25 blog post on InDepthNH.org.
Kreis told RTO Insider that he found the argument that press attendance will have a chilling effect on NEPOOL stakeholder discussions “to be cosmically unpersuasive.”
“I don’t get to go to a lot of NEPOOL meetings. Having third-party summaries of meetings [from the press] is going to help me do my job,” he said.
FERC last week approved a reduced return on equity for Pioneer Transmission’s portion of a recently completed 765-kV line in Indiana.
The commission’s Aug. 30 order reduces Pioneer’s ROE to 10.82% from the 12.54% approved in 2009, which included a 150-basis-point (bp) adder as a new interregional project (ER18-1159).
Pioneer, a joint venture of American Electric Power and Duke Energy, will use the ROE in its formula rates to recover costs for it and Northern Indiana Public Service Co.’s 65-mile, 765-kV Greentown-to-Reynolds line.
Pioneer in March proposed to adopt MISO’s 10.32% base ROE for transmission owners, with a 50-bp adder for RTO participation and the 150-bp adder for new transmission.
FERC allowed the base ROE and adder for RTO participation but denied the 150-bp adder because the current project does not include PJM.
Regional Processes
The Pioneer Project was intended as a single, $1 billion, 240-mile project across MISO and PJM to address “a critical shortage of high voltage transmission” in Indiana and help transport new wind generation from the state’s southwest to its central and northern regions.
At the time the project was proposed a decade ago, the MISO-PJM interregional planning process did not have “a tariff mechanism in place for evaluating and approving an interregional project such as the Pioneer Project that provided benefits to both RTOs,” according to Pioneer.
The company said it broke the project into smaller segments to be reviewed under PJM’s and MISO’s separate regional processes after encountering difficulties getting the RTOs to approve the line as an interregional project.
Pioneer and NIPSCO took up a $347 million Greentown-Reynolds line, which was approved in MISO’s 2011 multi-value project portfolio. This June, the MISO Board of Directors voted to add Pioneer as a MISO TO, and Pioneer has handed over operational control of the completed line.
FERC said the 150-bp adder would not go into effect “unless and until the project is approved by the regional transmission planning processes of [PJM and MISO] and there is a commission-approved cost allocation methodology in place.”
FERC said because the line had been broken into regional segments, it could not meet the condition that the Pioneer Project be included in both the PJM and MISO transmission plans. Pioneer had argued that the condition was no longer applicable or should be waived because the project “continues to be a large-scale transmission project and the first 765-kV transmission facilities in MISO’s service area.”
In its Aug. 30 order, FERC said Pioneer was free to apply for the new transmission incentive again once it could satisfy the requirement.
“Our denial of the 150-basis-point ROE adder is without prejudice. If Pioneer satisfies the commission’s previously stated conditions, then Pioneer may make a Section 205 filing to seek to prospectively implement the full 150-basis-point ROE incentive that the commission previously granted,” FERC said, adding that it “continues to value transmission rate incentives as a tool to encourage investment in new transmission.”
“In that vein, we encourage Pioneer to continue its efforts to complete the Pioneer Project,” the commission said.
NYISO’s Management Committee agreed Wednesday to relax its minimum 20-MW constraint reliability margin value in its initiative to price transmission constraints on 115-kV facilities.
The ISO’s Tariff currently requires at least 20 MW be set for any non-zero constraint reliability margin value used in the day-ahead and real-time markets
David Edelson, NYISO manager of operations performance and analysis, noted as an example that a 20-MW CRM equals 13% of the rating for 115-kV lines with post-contingency limits of 150 MW, limiting them to 130 MW in dispatch.
115-kV transmission line | Exponential Engineering
By contrast, for a 345-kV circuit with a 1,550-MW post-contingency rating, a 20-MW CRM represents only about 1% of the line rating.
Edelson said the ISO wants to limit CRMs to no more than 10% of a facility’s rating to allow for the continued pricing of transmission constraints on lower-voltage lines.
NYISO wants to change the Tariff to permit CRMs of less than 20 MW until it can implement enhancements under its constraint-specific transmission shortage pricing project. The ISO said the timing of that project is subject to stakeholders’ prioritization and scheduling.
The ISO would publish on its website a list of transmission facilities and interfaces assigned a CRM other than 20 MW.
The rule change will be presented to the Board of Directors for approval in September. The committee approved the proposal unanimously by a show of hands.
The Public Utility Commission of Texas last week approved a settlement agreement reducing AEP Texas’ annual revenue requirement (ARR) by $27 million, largely to reflect last year’s federal income tax legislation (Docket No. 48222).
AEP Texas agreed to reduce the revenue requirement in its distribution-cost recovery factors (DCRFs) to $55.6 million, with AEP Central’s ARR cut by $21.2 million and AEP North’s by $5.8 million.
Commission staff, the Alliance for Retail Markets (ARM) and several cities served by AEP signed on to the agreement. Texas Industrial Energy Consumers and the Office of Public Utility Counsel did not sign the agreement, but they are not opposed to it.
The changes, effective Sept. 1, reflect the reduction in the federal income tax rate from 35% to 21%.
The commissioners approved similar settlement agreements filed by CenterPoint Energy (Docket 48226) and Oncor (Docket 48231).
CenterPoint, which requested an ARR of $82.6 million effective Sept. 1, agreed to $42.4 million, rising to $63.7 million in September 2019, reflecting other tax changes.
Oncor agreed to a DCRF based on an ARR of $15.2 million, also effective Sept. 1. The utility had requested an ARR of $19 million.
Left to right: Commissioners Shelly Botkin, DeAnn Walker and Arthur D’Andrea share their thoughts | Admin Monitor
PUC Chair DeAnn Walker expressed reservations with the AEP settlement during the commission’s Aug. 30 open meeting, noting that state statutes require DCRF adjustments “be applied by the electric utility on a systemwide basis.” She pointed out that the commission’s 2016 approval of the merger of AEP Texas Central and AEP Texas North into AEP Texas required the company to maintain separate divisions with separate rates, riders and tariffs (Docket 46050).
“Systemwide rates would require a rate that is in effect for the entire AEP Texas system,” Walker said, pointing to the settlement agreement’s separate DCRF rates for AEP’s Central and Northern divisions.
AEP legal counsel Melissa Gage said the company’s interpretation of the law “wasn’t intended to mean systemwide in terms of AEP Texas as a whole, but on a division basis.”
Steve Davis, representing ARM, agreed with AEP’s interpretation and said the case posed “an odd situation.”
“It’s kind of hard to make it all fit correctly,” he said. “You have the statutory language, then you have the commission’s order in the merger case, which talks about separate rates” until some point in the future, he said. “Maybe there’s a path in future DCRF cases to follow to get to where you want to go.”
The commissioners saved further discussion on the proceeding for their closed session, which apparently eased Walker’s concerns. “I’m fine with moving forward,” she said afterward.
Commissioner Arthur D’Andrea pointed out the DCRF order is temporary, as AEP Texas is scheduled to file a full rate case in May. AEP Texas’ 8.96% rate of return last year was below that authorized by the commission during its last rate proceeding, according to the company’s 2017 earnings monitoring report.
Hearings Set for AEP Texas Legal Cases
AEP Texas also figured in two orders on the commission’s consent agenda.
The PUC first approved a procedural schedule for AEP’s bid to recover about $415 million in system restoration costs for 2017’s Hurricane Harvey. The schedule includes a Nov. 13-14 hearing before an administrative law judge (Docket 48577). AEP has proposed using a portion of its excess deferred taxes created by last year’s federal tax legislation to reduce the system restoration costs it will recover from consumers.
The commission also approved a procedural schedule in the company’s dispute with Rio Grande Electric Cooperative over which utility will serve certain customers in a Uvalde subdivision (Docket 47186).
An ALJ ruled on Rio Grande’s request for a cease-and-desist order in June, finding that AEP lacked the authority to serve some, but not all, of the customers in the disputed area. The case is of interest to retailers because Rio Grande’s service territory is not open to retail competition while competition was introduced in AEP’s footprint in 2002.
The procedural schedule for the second phase of the case includes a hearing to be held Oct. 31.
Commissioners Grant CCN to Tx Project — and Pole
The commission granted AEP Texas and Brazos Electric Power Cooperative a certificate of convenience and necessity for a jointly owned transmission line after the parties agreed to name a pole marking the midway point between them (Docket 47691).
Under the CCN, the two companies will each construct and operate half of the 138-kV transmission line southeast of the Texas Panhandle. The 20-mile line will connect Brazos’ Gyp switching station to AEP’s expanded Benjamin substation.
AEP Texas’ Jerry Huerta (left), Brazos Electric’s Bill Spears | Admin Monitor
The utilities have yet to determine which one will own the pole, which represents a new interconnection point between the two. After jokingly offering to paint the pole two different colors, the utilities’ legal counsel took advantage of free time during the commissioners’ executive session to agree on a name for the pole: Gyp-to-Benjamin Terminus.
“We thought long and hard about the name but came up with what’s written there,” AEP’s Jerry Huerta said, as the commissioners stared quizzically at their documents.
The project will cost an estimated $20 million. No word on how much the terminus pole will cost.
Entergy Texas Gets OK for 230-kV Line
The commissioners also granted a CCN to Entergy Texas for a proposed 230-kV line north of Houston (Docket 47462). The line is one element of a MISO western region project identified in its 2015 Transmission Expansion Plan that will provide economic benefits to MISO South. It will be between 33 and 45 miles long and cost up to $140 million, depending on the final route. Entergy plans to energize the line in June 2020.
October Workshop to Review ERCOT’s Summer Performance
The commission will hold a workshop in late October to review ERCOT’s market performance this summer (Project 48551). The workshop is intended to be an open meeting, with all three commissioners attending.
The commission in March directed ERCOT to exclude reliability unit commitments from online reserve capacity used in the calculation of the operating reserve demand curve price adder. It said at the time that further market design changes would be examined after an analysis of the market’s summer performance.
Luminant Accepts $1.1M Penalty for 2015 Violations
The PUC on Aug. 17 approved a settlement agreement with Luminant, in which the generation company agreed to pay a $1.1 million administrative penalty for violations in 2015. Luminant was fined for telemetering a down ramp rate of zero for 15 quick-start units when they were operating near full capacity for four days that summer, preventing ERCOT from dispatching the units down.
In his “Counterflow” column in the July 31 issue of RTO Insider, Steve Huntoon makes the unusual argument that because offshore wind costs more than onshore wind (i.e., requires more subsidies) offshore wind is a waste of money by a factor of 11:1 according to the Lazard study. Thus, we should build only onshore wind and forget about offshore wind.
Burdock | Business Network for Offshore Wind
However, there is plenty of evidence that offshore wind costs are rapidly coming down, and that some of offshore wind’s key benefits, especially its proximity to the population centers along the U.S. East Coast and job creation, make it a good value for ratepayers.
Mike O’Boyle, electricity policy manager for Energy Innovation, recently cited a Lawrence Berkeley National Laboratory (LBNL) study that showed “the high capacity factors of offshore wind, the coincidence of wind with customer demand, and the potential locations adjacent to congested coastal load centers like New York and Boston already make offshore wind an economic option.”
The LBNL study also found that the “market value” of offshore wind — considering energy, capacity and renewable energy certificates (RECs) — varies significantly along the U.S. East Coast, and “generally exceeds that of land-based wind in the region.”
The dramatic unveiling on Aug. 1 of the Massachusetts Department of Energy Resources’ 6.5-cents/kWh (in 2017 dollars) price for the Vineyard Wind project really brings this point home. In fact, the state estimates that Massachusetts electricity customers will see $1.4 billion in direct and indirect benefits over the 20-year life of the Vineyard Wind contract.
But there’s a larger problem with Mr. Huntoon’s claims that the Lazard study tells us that offshore wind is too expensive, and that the PJM territory has plenty of room for onshore wind. They center around transmission and distribution, which were “other factors” that were not included in the scope of the Lazard analysis. The simple fact is that most people don’t want to live near major electric transmission lines, which is why several transmission projects in New York and New England have been voted down by local and regional boards, and why New Jersey has virtually no onshore wind farms — and no plans to build any.
Several PJM states have a lot of land to build onshore wind; however, in coastal states like Maryland and New Jersey, the onshore wind resource is very small and as mentioned above difficult to site. According to the American Wind Energy Association, Maryland ranks 31st (191 MW) and New Jersey ranks 39th (9 MW) in installed onshore wind capacity. AWEA also estimates between 101 to 500 direct and indirect jobs are supported by onshore wind in both states.
| BithEnergy
Mr. Huntoon says the offshore wind jobs are a scam. It is hard to scam job creation when the Maryland Public Service Commission requires as a condition of the offshore renewable energy credit (OREC) order that US Wind and Skipjack invest $1.8 billion of in-state spending to spur the creation of almost 9,700 new direct and indirect jobs. Not only that, the two offshore wind developers must contribute $74 million in state tax revenues over 20 years.[1] Remember, those numbers must be met before one penny is paid to the developers. (OREC payments are not provided until the project is built and the offshore wind turbines are generating power.)
Mr. Huntoon is correct when he says, “It is critical that we make the most of our collective money” — a tenet the PSC understood when it decided to finance Maryland’s two offshore wind projects as a way to meet the state’s renewable portfolio standard and generate jobs. Maryland’s primary objective for its RPS is to foster the development of renewable energy resources within Maryland, but this goal has largely not been borne out.[2] Maryland’s data suggest that a significant portion of its REC costs paid for out-of-state onshore wind and solar. In fact, every year electricity suppliers in Maryland purchased greater numbers of out-of-state RECs to comply with the RPS. The Maryland Energy Administration (MEA) estimates that in 2015, Maryland ratepayers paid more than $76 million for RECs that were generated out-of-state. MEA estimates that as much as $186 million, if not more, has been spent to acquire non-Maryland RECs.[3] There is no in-state spending requirement, nor Maryland tax revenue generated, with these out-of-state projects — just millions of state ratepayer dollars going to other states. Isn’t that the real scam?
So, if we consider that offshore wind is a proven power producer in Northern Europe; offshore wind turbines are getting much bigger (see General Electric’s 12-MW turbine) and more productive than onshore turbines; offshore wind is stronger and more consistent than onshore wind; and offshore costs are coming down faster than anticipated, you can see why states like Massachusetts, New York, New Jersey and Maryland are counting so heavily on offshore wind. Yes, it’s going to take some upfront investment to establish the industry in the U.S., but those costs will be more than offset by the superior value provided by offshore wind over the next 20 to 30 years and beyond.
Liz Burdock is executive director of the Business Network for Offshore Wind.
Generating Clean Horizons was an effort to stimulate this goal because the RPS on its own did not result in clean electricity generation within the state. ↑
A controversial bill to help California utilities pay for wildfires sparked by power lines cleared the State Legislature on Friday night and was sent to Gov. Jerry Brown.
SB 901 would allow the state’s investor-owned utilities to issue cost-recovery bonds, to be repaid by charges on customers electric bills, with the approval of the Public Utilities Commission.
Proponents argued it was a way to keep Pacific Gas and Electric and other utilities solvent at a time when wildfires are larger, more intense and far more costly than in prior years. Climate change is often blamed for the more deadly and destructive fires.
“SB 901 is a comprehensive approach that attacks the problems on multiple levels,” said Sen. Bill Dodd (D-Napa), the measure’s co-author, during Friday’s floor debate.
Critics called it a giveaway to utilities that, through their own negligence, allowed power lines to ignite trees and brush that are tinder dry from years of drought.
“This bill rewards their bad behavior,” said Sen. Jerry Hill, a Democrat who represents the Silicon Valley.
The bill was the subject of intense wrangling this summer.
A July 24 proposal by Brown would have done away with California’s broad use of inverse condemnation, a legal doctrine that holds utilities strictly liable for fire damage. Many argued that overturning the longstanding doctrine would leave fire victims without quick compensation. That part of the governor’s plan was not included in the bill.
Instead, a conference committee of Senate and Assembly members met seven times in recent weeks to hear testimony and gather information to redraft the measure. The committee approved a revamped proposal in a late-night scramble Tuesday, and its report passed the Senate and Assembly by ample margins Friday as the legislature neared its midnight deadline for passing bills.
The rewritten measure would maintain the state’s strict liability standard and require the PUC to determine the reasonableness of a utility’s fire safety practices in deciding whether costs can be passed on to ratepayers.
SB 901 would also require utilities to adopt wildfire mitigation plans and would create a commission to examine catastrophic wildfires associated with utility infrastructure. It would levy fines on utilities that fail to adhere to their fire-prevention plans.
As a result, utilities that once supported the measure turned against it, while insurers, plaintiffs’ attorneys and local governments switched their opposition to support.
| U.S. Dept. of Agriculture
The bill’s 100-plus pages also ease rules for tree cutting and address the disposal of the massive amounts of dead wood and brush that fuel wildfires. It would spend $1 billion over five years on fire prevention.
The bill also includes a “stress test” that instructs the PUC to “consider [an] electrical corporation’s financial status and determine the maximum amount the corporation can pay without harming ratepayers or materially impacting its ability to provide adequate and safe service.”
The provision applies only to last year’s wildfires, including the highly destructive blazes of October 2017 that killed dozens of residents and leveled thousands of homes in Napa and Sonoma counties. A large part of the city of Santa Rosa burned in the wind-whipped flames.
State investigators have determined that PG&E’s equipment was responsible for a number of the most destructive fires from that time and the company will face $15 billion or more in liability, according to some estimates.
The PUC would apply the stress test “to extract the maximum amount possible” from PG&E’s investors, Dodd said. Letting PG&E slip into bankruptcy would result in customers paying higher rates and would compromise the state’s efforts to reduce greenhouse gasses and to tap into greater amounts of renewable energy, he said.
Wildfires have burned 1.2 million acres in California already in 2018. The causes of most of the fires have yet to be determined. The blazes included the Mendocino Complex of fires that have burned more than 400,000 acres in the mountains north of San Francisco.
Brown has not yet indicated whether he will sign or veto the measure. He has until Sept. 30 to decide.
A measure to expand CAISO into an RTO for Western states failed to clear the legislature for the third time in three years.
AB 813 languished in the Senate Rules Committee, where it was sent Aug. 16, and never made it to the Senate floor during the last night of the State Legislature’s 2017-18 session Friday.
The measure would have initiated the process of changing CAISO’s governing structure from one controlled by Californians to a multistate enterprise.
Previous efforts to authorize CAISO’s expansion have stalled during the past two years in the face of strong opposition both inside and outside of California. (See CAISO Regionalization, 100% Clean Energy Bills Fizzle.)
“AB 813 was a missed opportunity for Western states to modernize the grid and promote new clean energy investments,” Lauren Navarro, senior policy manager for the Environmental Defense Fund’s California Clean Energy initiative, said in a written statement. “While we are disappointed AB 813 didn’t pass, we remain committed to supporting the state’s efforts to integrate more renewables and removing barriers to regional energy trading.”
“The world looks to California for clean energy leadership and we remain dedicated to encouraging the state to lead by example,” Navarro said.
A solar farm in California’s Mojave Desert. | U.S. Dept. of the Interior
Some labor unions opposed AB 813, arguing it would reduce in-state renewable energy construction projects and siphon jobs from California.
The bill divided environmentalists, some of whom believed an integrated Western grid would hasten the switch to clean energy regionally. Others, including the Sierra Club, opposed linking California’s cutting-edge energy efforts to the coal-burning states of the interior West.
Publicly owned utilities, such as the Sacramento Metropolitan Utility District, also opposed the measure.
Barry Moline, executive director of the California Municipal Utilities Association, told RTO Insider last month that the Western Energy Imbalance Market is already doing a good job of allowing energy trading as needed among Western states without building new transmission from wind farms in Wyoming or solar farms in Arizona to consumers in California. (See CAISO Regionalization Bill Cast on Uncertain Course.)
“I don’t buy the argument that we have to regionalize to take advantage of opportunities elsewhere,” Moline said.
Others contended the regional grid was needed to allow clean energy to be traded and allocated further in advance than the EIM allows. California’s solar energy peaks during midday, when in-state energy use is low, while solar arrays and wind farms in the interior states come online during California’s times of high consumption. Trading renewables would benefit all involved, proponents argued.
“We need to be able to operate the system as a congruent whole,” said Carl Zichella, Western transmission director for the Natural Resources Defense Council, one of the bill’s main proponents.
Zichella remained hopeful this week that the bill would escape the Rules Committee and be taken up for debate on the Senate floor. Recent amendments imposed a nine-month waiting period for the bill’s provisions to take effect, giving the legislature and new governor time to review any proposed changes in CAISO’s governance.
Brown is nearing the end of his last term as governor, and some critics said it would be unfair for his successor to be denied input on such a sweeping plan, Zichella noted.
In the end, however, the amendments were insufficient to quiet the controversy that has long surrounded the regionalization effort, and the bill died a quiet death in the Rules Committee.
PJM and MISO said Tuesday they plan to partner on an extra study to better coordinate their incremental auction revenue rights (IARRs) processes, although details have yet to be sketched out.
The RTOs will perform a preliminary transmission upgrade study to ensure that transmission allocations are granted to developers “to the extent they cause no harm to existing transmission allocations” to participants in their congestion management process, which include neighboring balancing authorities. The new study would rely on the same topology assumptions found in planning studies for IARRs and seek to ensure that proposed upgrades will produce the requested firm flow entitlements.
“Admittedly, we’ve not put pen to paper to write out the study process,” PJM Manager of Market Simulation Brian Chmielewski said during an Aug. 28 Joint and Common Market conference call.
MISO and PJM first signaled that they would seek to improve ARR coordination in May. (See MISO, PJM Seek Incremental ARR Coordination.) Both RTOs offer IARRs, which are created by transmission upgrades that allow additional capability. IARR megawatts are awarded for the additional capability created for the life of the facility or 30 years, whichever is less, and valued each year based on annual financial transmission rights auction clearing prices. However, PJM offers an additional option that allows IARRs to be awarded when “any party” agrees to fund transmission upgrades necessary to support them. PJM and MISO coordinate studies of IARR requests when they impact flowgates.
Chmielewski said the proposed study contains the risk that preliminary results will diverge from final study results of firm flow entitlements because of timing, given that the final transmission upgrade study is performed only after upgrades are put in service.
“That’s a risk that we’re aware of and we’re working through,” Chmielewski said.
MISO and PJM staff say there’s another sticking point: PJM’s requirement to guarantee that least 80% of ARR megawatts are available even when the MISO system is impacted. MISO said the “potential risk to value” for its stakeholders precludes it from making guarantees on future firm flow entitlement allocations.
PJM Director of Energy Market Operations Tim Horger said PJM must be careful not to over-allocate rights based on the 80% requirement, and that it’s possible PJM won’t be able to guarantee the 80% share if upgrades affect the MISO system. He said one such upgrade affecting the MISO system has already occurred, and though the RTOs were able to coordinate it to satisfy PJM’s requirement, future upgrades could be trickier.
MISO and PJM staff plan to return to the JCM in November to discuss draft revisions to the joint operating agreement to incorporate the study, Chmielewski said.
The SPP Regional Entity’s Board of Trustees on Thursday officially terminated the RE’s regional delegation agreement, shutting it down effective 5 p.m. CT Friday.
The trustees approved a motion to terminate the agreement during a brief phone call that was delayed until Trustee Steve Whitley could join Chair Dave Christiano and create a quorum. Staff patched Whitley in over a speakerphone from SPP headquarters. Trustee Mark Maher was unable to attend.
The meeting was a formality, as FERC in May approved the RE’s dissolution, effective Aug. 31 (RR18-3), and the transfer of its 122 registered entities to the Midwest Reliability Organization and SERC Reliability Corp. (See FERC Approves Dissolution of SPP RE.) The order ended a reliability oversight role that had been a source of concern at the commission and NERC and revised the delegated agreements among NERC, MRO and SERC to reflect their new geographic footprints.
The RE has been working since then to transfer data and files to its members’ new REs and purging its own files.
“We have absolutely nothing left, other than a bank account,” RE President Ron Ciesiel told the trustees. He said the RE’s books will be closed in about a week, and the remaining funds transferred to NERC, MRO and SERC.
“We’re ready to close the doors,” said Ciesiel, noting he and remaining RE staffers Kevin Perry and Joe Gertsch would be “mustered out” of SPP following the conference call. Ciesiel said the rest of the RE’s original staff have been placed elsewhere within the RTO or “made other decisions.”
MRO CEO Sara Patrick joined with Ciesiel, Christiano and Whitley in complimenting staff and the entities for their work during the transition.
“I know this was an unprecedented development, and certainly not something anyone anticipated,” she said. “I appreciate it’s gone as smoothly as it has.”
“I think our registered entities are in good hands,” Christiano said.
NERC will assume the compliance monitoring and enforcement of the RTO for two years following the delegated agreement’s termination date, after which it will determine a successor.
Christiano closed the call by uttering “sine die” — business adjourned, with no appointed date for resumption.
SPP Files for Cancellation of WAPA Operating Agreement
SPP filed with FERC on Aug. 28 to cancel its joint operating agreement with the Western Area Power Administration (ER18-2326).
The JOA was rendered moot by SPP’s integration of the Integrated System in October 2015, when the WAPA-Upper Great Plains Region transferred functional control of its transmission facilities to the RTO.
The agreement, which dates back to 2012, expired by its own terms on June 21. SPP filed a three-year extension in 2015 that was accepted by FERC.
