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.
Oklahoma Corporation Commission Chair Dana Murphy came up short Tuesday in her bid to become the state’s lieutenant governor, losing a runoff for the Republican nomination.
Murphy was bested by former state GOP Chairman Matt Pinnell, who received 58.1% of the vote to her 41.9%. Murphy beat Pinnell in a four-way primary in June, winning 45.8% of the vote to Pinnell’s 35.69%, less than the 50% required to avoid a runoff.
Only 295,132 Oklahomans cast ballots in the runoff, compared to 429,483 in the primary.
Pinnell will face Democrat Anastasia Pittman, a state senator from Oklahoma City, on Nov. 6.
In a concession statement issued Tuesday night, Murphy thanked supporters and called for cooperation at the State Capitol. Murphy campaigned as a problem-solver and made it a point to crisscross the state and visit as many residents as she could.
“It’s time to address the roots of problems and create lasting solutions,” Murphy said in her statement. “Going forward, I hope the next crop of leaders at the State Capitol will bring their best, put partisan politics aside and do something different.”
The lieutenant governor’s office is seen as a stepping stone to the governor’s mansion. Outgoing Gov. Mary Fallin served three terms in the higher office, but current Lt. Gov. Todd Lamb failed to make it out of this year’s Republican gubernatorial primary.
Murphy, 58, a petroleum geologist and lawyer, has sat on the OCC since 2009. Her current terms ends in 2022. She is also a past chair and current member of SPP’s Regional State Committee. (See Oklahoma Regulator Sets Sights on Higher Office.) She was applauded for not running negative ads during the two-month runoff campaign.
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.
SACRAMENTO — A bill that would require California to get 100% of its power from renewable and other zero-carbon resources by 2045 is headed to the desk of Gov. Jerry Brown.
Senate Bill 100 — the 100 Percent Clean Energy Act — passed a major hurdle Tuesday, clearing the state Assembly by a narrow margin, then sailed through the Senate Wednesday. Brown hasn’t said if he will sign or veto the measure, but it dovetails with his ambitious environmental agenda with regard to renewable power.
“This bill will continue California’s energy revolution,” said Sen. Ben Hueso (D), who voted for the measure.
Some Republicans argued against the measure, saying it would raise energy bills, while Democrats said wind and solar were now cheaper alternatives to fossil fuels.
In the Assembly Tuesday, the bill needed a majority vote in the 80-member lower house but remained on call, without the votes for passage, much of the day. It passed in the early evening by a vote of 44-32.
Other measures being weighed this week — the last of the legislature’s 2017-18 session — include a bill that would start CAISO on the road to being an RTO for Western states, letting California tap into wind power from Wyoming and solar power from New Mexico, for instance, while those states could buy California’s clean energy during times of low in-state demand. (See CAISO Regionalization Bill Set on Uncertain Course.)
CAISO’s leadership strongly supports Assembly Bill 813, which is currently being held in the Senate Rules Committee as a deal is worked out to bring it to the Senate floor. The legislature has until midnight Friday to send measures to Brown or watch the bills expire.
SB 100’s fate was unknown until the last minute Tuesday. Sen. Kevin de Leon (D), the bill’s author, had to work his Assembly colleagues on the Senate floor to get the last votes needed to pass the measure before the lower house adjourned for the day. There were a number of Democratic holdouts who had to be persuaded. Former Gov. Arnold Schwarzenegger, former Vice President Al Gore and others weighed in to encourage lawmakers to pass the measure.
In addition to requiring investor-owned utilities, publicly owned utilities and community choice aggregators to obtain 100% of their energy from renewables by 2045, the bill sets milestones along the way: 40-44% by 2024; 45-52% by 2027; and 50-60% by 2030.
The Long Island Power Authority’s proposal to exempt “beneficial electrification” from carbon charges received a mixed reaction Monday at a meeting of the Integrating Public Policy Task Force (IPPTF).
Ground source heat pumps are cited as a type of “beneficial electrification” which causes a net reduction in carbon emissions. | EPA
LIPA’s David Clarke said beneficial electrification (BE) — load growth that improves load factors and results in net reductions in carbon emissions — could increase generator margins while reducing fixed costs and should be supported by policymakers. Clarke cited as examples vehicle electrification and switching from oil-fired boilers to ground source heat pumps.
Clarke acknowledged the complexity of carving out BE loads for separate rate treatment but said it could be accomplished without skewing dispatch. He proposed treating BE load growth as having no marginal carbon impact, meaning it would not pay the carbon component of the LBMP.
“I think the question here is: Is there a consensus … around the idea of trying to include beneficial electrification in this proposal?” Clarke asked. “I’m willing to at least try to illustrate that it might benefit large groups of stakeholders.”
Kevin Lang, representing New York City, said Clarke had proposed an “interesting concept.”
But other stakeholders indicated no appetite for including the issue in their current deliberations, saying it should be delayed or handled by retail regulators rather than in the wholesale market.
One stakeholder who asked not to be named said the proposal raised numerous issues. “If you include extensive switching to heat pumps, a utility can very quickly become a winter peaking operation rather than a summer peaking operation. This then raises the question of forward capacity markets and so forth. How much does it cost to have the extra capacity in place for winter weather?”
Because thermal loads tend to be very “peaky,” resulting in more start-up operations, adding such loads raises issues of environmental justice, the stakeholder said.
“Any policy maker who gets into the subject of electrification should be able to stand up in front of a crowd of people like this and draw a curve of carbon monoxide, unburned … carbon emissions during the startup of even a natural gas turbine, and be able to comprehend how ugly that start-up process is during the first hours of operation and where that exhaust is going. We need to be very careful about increasing peaky types of grid loads.”
Mark Younger, of Hudson Energy Economics, said measuring carbon savings from beneficial electrification is very complicated.
“We would be going through a huge amount of complication to try and address something that realistically should lower the average carbon cost … fairly little,” he said. “I look at this and I say this seems like a perfect thing to not try and address at all at the wholesale level. … If someone wants to put together a retail rate design that is targeted to beneficial electrical uses and therefore has some degree of savings on maybe some of the fixed costs, the distribution costs … that’s a perfectly appropriate thing certainly for DPS [Department of Public Service] to consider.”
Clarke recommended awarding the social cost of carbon offsets through load-serving entities, which he said would allow for continued funding of LSE carbon abatement programs and incent LSEs to encourage BE load growth. The state Public Service Commission would retain its jurisdiction over how offset revenues are treated at the retail level.
Erin Hogan, director of the state Utility Intervention Unit, agreed with Younger, saying “it’s premature to try and address this now.”
She said the issue could be revisited once policymakers develop criteria for BE and once the NYISO develops its bottom-up forecast.
“The issue that I take issue with is that all beneficial electrification is good. To the extent there’s low penetration, the fixed costs could be spread over more megawatt hours. However, if the penetration is so high that the utilities then have to revamp their systems, all those little transformers in neighborhoods might have to be resized. Those costs could go up exceptionally high,” she said, noting that her office filed comments in the “New Efficiency New York” docket asking the PSC to develop criteria for defining BE.
Under Clarke’s proposal, loads qualifying as BE would have to improve load factors and prevent increases in regulated natural gas customers’ fixed costs. Policymakers should consider offsetting increases in fixed costs to electric customers resulting from load growth at sub-transmission feeders and distribution lines, he said.
Lang said New York City “is looking closely” at beneficial electrification, predicting it “will be bigger” than Younger suggested.
“If [the impact is] tiny, it’s tiny,” said Clarke. “That’s not the issue. I’m thinking down the road this is going to be big. Beneficial electrification, especially if [carbon emissions] were only monetized in the electric sector, is going to be a huge thing. And we’re going to be penalizing — if we keep doing what we’re doing — load growth that reduced carbon … by charging it a carbon charge even though its net effect on carbon is negative.”
Import Carbon Pricing
Clarke also gave a presentation on addressing imports from grid operators that already incorporate carbon prices. NYISO staff have suggested treating imports as if New York had no carbon policy, saying it may be too complicated to use the actual hourly marginal energy rate [MER] of external RTOs.
Clarke said the ISO’s proposal “gives neither an efficient carbon-free dispatch nor efficient dispatch when damage costs are considered” using the social cost of carbon.
Under Clarke’s proposal, the ISO would back out the price of carbon in each external zone and compare it to the New York price, less its carbon price based on the New York MER. “If MERs are similar, why not get more power from ISOs/RTOs where the cost of power absent carbon charges is lowest?” he asked.
The draft assumes the status quo — known as Option 1 — of treating imports as if New York had no carbon policy.
NYISO’s Mike DeSocio said, “I haven’t heard compelling arguments” for considering ways to value clean resources outside New York, known as Option 2.
Pallas LeeVanSchaick, of the ISO’s Market Monitoring Unit, challenged the “premise that Option 2 is complicated and hard to implement, and Option 1 is straightforward. … I don’t think it’s as straightforward as you think it is.”
Jordan Grimes, of Morgan Stanley, said beginning with Option 1 and later switching to Option 2 would be “untenable for markets.”
He asked whether the ISO had considered how the decision would be viewed under the U.S. Constitution’s Interstate Commerce Clause.
“The courts could say … you guys looked at two options, and Option 2 was the less discriminatory option — and that’s on record — and the ISO decided to go with Option 1 because it was easier.”
He said NYISO could learn from CAISO. “The way they tax imports largely works,” he said.
ISO attorney James Sweeney responded, “We haven’t identified anything from the interstate commerce area that would be a deal breaker for either option.”
Mike Mager, representing the Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, said the draft is missing many details that must be decided before NYISO stakeholders vote on any proposal. “It’s problematic to expect people to [vote] to implement one of the most significant market rule changes in the history of the NYISO without any clarity on what the social cost of carbon would be and how and when it would be updated,” he said.
NYISO’s DeSocio said “it’s difficult to foreshadow the kind of process the Public Service Commission would undertake” to set the cost of carbon. “We would hope they would be consistent with other [PSC] programs. From an efficiency standpoint, having different costs of carbon doesn’t seem like a good path forward.”
