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.
Less than two years after rolling out its major queue redesign, MISO is once again poised to file generator interconnection process changes to help manage the record volumes in its queue.
The changes involve milestone payments and site control requirements and are aimed at encouraging stalled projects to withdraw from the queue earlier in the process. (See “Further GIP Alterations,” Little Work Needed to Comply with Order 845, MISO Says.) The queue now contains about 530 projects totaling almost 90 GW.
“MISO has to better manage the number of non-ready projects entering the queue,” Manager of Resource Interconnection Neil Shah said during an Aug. 27 Interconnection Process Task Force conference call.
Site Control
MISO’s changes would maintain the acreage requirement for a developer’s site control but would scale back some of the acreage requirements proposed in July, with 50 acres/MW for wind generation, 5 acres/MW for solar generation, 0.1 acre/MW for electric storage resources and a flat 10 acres for a conventional generation facility. The RTO had originally proposed 1 acre/MW for battery storage and 50 acres for conventional generation, but MISO stakeholders said requiring that much land was excessive.
Shah said most stakeholders prefer an acreage-per-megawatt site control requirement.
Additionally, the RTO now says it will allow developers to submit site control for smaller acreage amounts provided they submit an analysis from an independent consultant supporting the reduced requirement.
MISO also said the $10,000/MW cash deposit that developers can alternately provide if a state’s regulatory restrictions limit site control will now be refundable when a developer either withdraws its project from the queue or submits proof of site control. The RTO still proposes that the developer “submit adequate documentation demonstrating regulatory restrictions” to be eligible for the $500,000 minimum, $2 million maximum cash deposit in lieu of showing site control.
“We’ve incorporated that flexibility based on stakeholder feedback,” Shah said.
MISO will also require interconnection customers to submit documentation for exclusive site control 90 days prior to the start of the queue’s definitive planning phase as opposed to the time of queue application, as originally proposed.
Shah said the new 90-day window is needed to screen site control documentation.
Vikram Godbole, MISO resource utilization director, pointed out that most generation interconnection customers do not furnish all required information with queue applications.
“About 90% of the applications MISO receives are incomplete for various reasons. That’s just not acceptable. If MISO is going to make progress, we have to work together,” Godbole said.
He said MISO is currently working to automate the online submission process for queue applications.
“That’s not done, but we’re getting ready for that,” Godbole said, adding that stakeholders should begin sending complete applications and site control documentation in preparation for an automated process that will likely not accept unfinished applications.
Milestones
MISO is also walking back its proposal to incorporate upgrade costs found in affected systems studies into the last of three milestone payments. The milestone fee will now be a flat 20% of necessary network upgrade costs, instead of a combined 10% of upgrades identified in the studies and 10% of network upgrades.
Finally, the RTO said it will refund the entire first milestone payment of $4,000/MW if a customer withdraws its project before it reaches the beginning of the definitive planning phase.
“I think what you’re seeing here is a good compromise achieved with stakeholders,” Godbole said.
MISO staff said they will present final Tariff revisions at the Sept. 26 Planning Advisory Committee meeting. The RTO hopes to file queue Tariff revisions sometime in October or November.
Back-to-Back Queue Revisions
Some stakeholders asked why MISO is pursuing queue changes so early into implementing its three-phase queue design, accepted by FERC in early 2017. (See FERC Accepts MISO’s 2nd Try on Queue Reform.)
Shah responded that MISO must heed stakeholder feedback and FERC complaints over queue delays. In an April order in response to a complaint about delays, FERC warned MISO about its delays and urged it to consider improvements to its queue process. (See “No Ringing Endorsement,” FERC Sides with MISO in Queue Design Dispute.)
“We have heard loud and clear from complaints filed at FERC that MISO’s revised process after queue reform is still not working for them,” Shah said. “Interconnection customers want MISO to reduce delays. … Not doing anything is probably not an option right now.”
Shah added that he could not guarantee that the new revisions will enable all wind developers to meet production tax credit deadlines.
Stakeholders on Monday said they remain skeptical of a MISO-SPP plan to eliminate the RTOs’ joint model in favor of using their respective regional models to estimate and divide the cost of interregional projects.
The RTOs announced the plan last month. (See MISO, SPP Loosen Interregional Project Requirements.) They will also examine all types of interregional projects by both an adjusted production cost (APC) and avoided cost benefit metrics, a departure from current practice. Currently, only reliability interregional projects are evaluated using both metrics. Public policy interregional projects are limited to an avoided cost metric while economic interregional projects are limited to an APC metric.
But stakeholders are still questioning how MISO and SPP will ensure equitable cost allocation between the RTOs absent a joint model.
SPP Interregional Coordinator Adam Bell said some stakeholders may have misunderstood elements of the proposal after its was revealed in July, including a mistaken assumption that the RTOs would use their regional models to calculate each other’s benefits and cost allocation. He confirmed that each RTO would calculate only its own benefit from a proposed project.
“SPP will not be calculating MISO’s benefit,” Bell reassured stakeholders during an Aug. 27 MISO-SPP Interregional Stakeholder Planning Advisory Committee conference call.
However, staff said they will not create identical adjusted production cost calculations in their regional models, which multiple stakeholders say are a must if project candidates are to be judged consistently across RTOs.
“There are differences [in our regional models],” Bell said. “We are not proposing that the regional calculations of adjusted production costs be exactly the same. … It’s kind of a situation of who’s to say which has the better APC benefit calculation. They are different, and that’s not something we’re proposing to change at this point.”
MISO Planning Adviser Davey Lopez said the unique APCs used in the regional models only highlighted the need to remove the joint model. He said the RTOs should be free to evaluate interregional projects in the same manner that they evaluate regional projects.
“In my view, I think that’s extremely equitable cost allocation,” Lopez said, adding that both methods have been accepted by FERC.
“SPP values transmission the way SPP values transmission, and the same can be said of MISO. … We’re going to be making decisions based on how each region values transmission,” Bell explained.
RTO staff also pointed out that under the existing interregional process, project candidates must still undergo disparate regional reviews in addition to the joint model.
But some stakeholders said that under the new process, MISO and SPP have the potential to get hung up on what portion of project costs the other one owes.
“What I fear is going to result from this — because of the way each is going to calculate benefits — that they’ll view their share of the cost of these benefits as being unfair,” said The Wind Coalition’s Steve Gaw, adding that interregional projects might still not be built as a result.
Lopez said that it was difficult to envision that projects that have passed benefit metrics on both sides of the seam would be passed up because one RTO feels slighted over costs.
“I’ve been to too many of these [meetings] to have faith in that being the case,” Gaw responded.
However, MISO and SPP say they are open to aligning their regional models to examine project benefits over the same number of years. MISO’s regional model currently gauges new transmission value for the first 20 years of the life of a facility, as the MISO-SPP joint operating agreement prescribes, while SPP looks over 40 years.
Lopez said the RTOs will continue to discuss the benefit timelines, though he added that he was not suggesting that MISO would use anything other than a 20-year timeline. He said MISO viewed the question as both RTOs using the JOA-prescribed timeline or continuing to rely on the existing processes with differing timelines. Multiple stakeholders said the RTOs should align the timescale.
MISO and SPP will continue to work on the new interregional project process through fall, with final JOA revisions targeted in October or November.
PJM’s transmission owners have floated a proposal that would comply with FERC’s show cause order on their planning processes by adding input opportunities — along with complexity — for tracking project development.
PPL’s Frank “Chip” Richardson explained the process developed by the TOs and PJM during a conference call Tuesday. Instead of mirroring PJM’s existing processes for baseline projects, which are developed to address violations of regional or national reliability criteria, the process for supplemental projects will have a more detailed and structured pathway for stakeholder engagement.
A comparison between TOs’ current and revised processes for planning supplemental projects. | PJM
Supplemental projects are transmission expansions or enhancements developed by TOs to address their individual planning criteria and maintain their assets, so they sidestep PJM’s analysis for inclusion in its Regional Transmission Expansion Plan. The new planning process was outlined in FERC’s order but has received stakeholder focus as TOs developed the implementation details.
Of particular interest to planners has been FERC’s determination that the three steps of project planning — defining assumptions and criteria for analysis, identifying needs, and choosing a solution — each receive its own meeting with time before and after to provide input. Richardson cautioned that parts of the last two might bleed into each other. When talking about a problem, “the natural question is, ‘What are you going to do about it?’” he said. “It’s hard not to talk about the solution when you talk about the need, so you’ll have to have a little bit of forgiveness.”
The proposal also clarifies that TOs can submit revisions to their local plans (which include supplemental projects) to the RTEP throughout the year. TOs said they plan to maintain their existing practice of having an annual review of the models, criteria and assumptions that underpin the projects in December or January of each year. This information supports PJM’s development of base-case planning models that allow stakeholders to model any project to see how it might change flows on the grid.
PJM’s Aaron Berner said staff are still unsure whether they will create separate slide decks to review supplemental versus baseline high-voltage projects. The difference has come under consideration because the D.C. Circuit Court of Appeals ruled earlier this month that high-voltage supplementals should be eligible for regional cost allocation and PJM staff indicated that might mean the projects have to go through the RTEP analysis. (See AMP Offers ‘Best We Can Do’ on PJM Tx Planning.)
Complexities
American Municipal Power’s Ed Tatum, who has championed a proposal to add details and rules to the TOs’ plan, highlighted several concerns with the plan’s structure. For one, he said, it’s tough for stakeholders to be prepared for meetings when the project presentations are posted 10 days prior to the meeting. AMP has members in nine states and over multiple TO zones.
Richardson acknowledged that if the goal is to model all of the potential solutions that TOs consider, “that’s quite ambitious, and it will be challenging.” He suggested stakeholders focus “on those things that would actually have some impact on them directly.”
Tatum asked whether TOs will explain why their preferred solutions are chosen over other options. Richardson said he believed TOs agreed to discuss other options that they “seriously considered,” but that they don’t plan to work on solutions “that they are not intending to pursue but may have considered.”
“I think many people had the same reaction … ‘Wow this is pretty complex,’” Richardson acknowledged.
He said TOs plan to convene stakeholder reviews of the process in the first and third quarter next year.
