WASHINGTON — Should FERC should begin requiring supply curve analyses in its merger reviews? It’s a no-brainer to Cynthia Bogorad, who has attempted to submit them as an intervenor challenging acquisitions.
“I’ve got black and blue marks to show that that … has not been a very successful strategy, because you don’t have the data or the time to get the data in [the] 60 days” allowed for filing a protest, Bogorad, a partner at Spiegel & McDiarmid, said during a panel discussion at last week’s Energy Bar Association annual meeting.
“And the commission has in my experience been very reluctant to accept intervenor analysis. We’ve presented a strategic bidding analysis in a case that the commission just said, ‘No, don’t do that.’ So, I think …. the commission [requiring merging companies to provide the analyses] would be very important because it’s hard to get them in [evidence] otherwise.”
The commission said it was considering changes in its merger policy in a September 2016 Notice of Inquiry (RM16-21). It noted that its market power evaluation for mergers, which are regulated under Section 203 of the Federal Power Act, differs from that used in market-based rate applications under Section 205. The commission asked for input on several issues, including whether it should add supply curve and market share analyses to its reviews, and whether it should require applicants to submit consultant reports and other internal reports that assess the competitive effects of the merger, as the Justice Department does. (See FERC Considers Changes to Market Power Analyses.)
FERC currently requires merger applicants to perform a competitive analysis screen unless they can show that the acquisition does not increase their generation capacity in the relevant geographic markets or that the increase is de minimis. The screen includes a delivered price test (DPT), which has been essentially unchanged since its introduction in 1996 and generally focuses on the short-term energy market “with far less detail and attention given to the other relevant products,” FERC said.
Mike Naeve, a partner with Skadden, Arps, Slate, Meagher & Flom, said FERC’s screening already prevents acquisitions that have no competitive harm.
“If we decide on top of that we’re going to add three or four other screens … I think there would be a lot more false positives,” Naeve said. “And I also think the amount of time and money and effort to prepare and advise clients for these filings [will] go up astronomically. So, the question is: Is the current process so flawed that it needs to be fixed?”
Naeve also was not convinced that FERC needs to adopt DOJ’s tools.
“As long as I’ve been doing this, I don’t know [of] a transaction where the commission said this transaction looks fine with us … and the DOJ, using these other methodologies and tools … says, ‘Oh, there’s a problem there FERC that you missed because your methodology is too simple.’ I don’t think that’s ever happened.”
Amery Pore, an economist in FERC’s Office of Energy Market Regulation, disagreed with Naeve’s characterization of the potential changes, which the commission is still reviewing. The comment period in the NOI expired in December 2016.
Flexibility?
“I guess one way to read the NOI would be to see these additional tests as extra hurdles to jump through,” Pore said. “But alternatively, you could think of them as employing the flexibility that was actually considered back in 1996 when the DPT wasn’t intended, when it was implemented, to be the screen to use.”
“If these were alternative tools to show it really is a false positive and there aren’t competitive problems, then I think we would all say that’s worth doing,” Naeve agreed. “But I would also say you [should not] need to do it in your application unless you have a screen failure.”
Naeve said he’s seen intervenors opposing mergers submit “very simplistic” supply curve analyses.
“To do it right you have to take into consideration a lot of factors … like the [generators’] ramp rates [and] minimum run times and minimum down times; the fact that sometimes in an RTO-type market … a transmission constraint that raises prices on this side of the constraint actually lowers prices on the [other] side of the constraint, so if you have generation there you’re actually losing money. … There’s just a lot of factors [that affect] the profitability of withholding.”
“That’s why it’s hard for intervenors to do it in the 60 days they have to protest,” Bogorad replied.
Mark Niefer, deputy chief legal advisor in the Justice Department’s Antitrust Division, said it’s important to avoid inconsistencies between DOJ and FERC reviews because the potential harm to consumers is so high.
“You’re talking about markets that are tens of billions of dollars in size, such that a very, very small exercise of market power over a very short period of time can impose harm on consumers … that are in the tens of millions of dollars,” he said. “So, my own personal preference when conducting a merger analysis [is] to tend to try to avoid false negatives rather than false positives. I just think the stakes are too high. And I think history bears that out. If you look back at California — the exercise of market power [during the 2000-2001 Western Energy Crisis] pretty much put a damper on restructuring in the United States. … And I think that damper still is in place.”
The panel was moderated by Eric Korman, vice president of Analysis Group.
WASHINGTON — FERC’s delay in responding to a 2017 appellate ruling vacating its order on New England transmission rates has created the risk of an endless series of “pancaked” rate cases, a panel told the Energy Bar Association’s annual meeting last week.
The D.C. Circuit Court of Appeals’ April 2017 Emera Maine ruling overturned FERC’s 2014 order setting the base return on equity for a group of New England transmission owners at 10.57%. The court said the commission failed to adequately explain why the previous 11.14% rate was unjust and unreasonable. (See Court Rejects FERC ROE Order for New England.)
“We’re in a huge amount of uncertainty right now. The Emera decision has essentially taken everything and flipped it up into the air, and now we’re all waiting to see what happens next,” said Nina Plaushin, ITC Holdings’ vice president for regulatory, federal affairs and communications. “It’s as close to a thriller as you get in doing utility regulation.”
In the 2014 ruling, the commission voted 4-0 to change the way it calculates ROEs for electric utilities, moving to a two-step discounted cash flow (DCF) process it has long used for natural gas and oil pipelines that incorporates long-term growth rates. But the commission split 3-1 over its first application of the new formula, tentatively setting the ROE for the New England TOs at three-quarters of the top of the “zone of reasonableness,” a departure from the prior practice that used the midpoint in the range (EL11-66-001). (See FERC Splits over ROE.)
FERC rejected the TOs’ argument that the commission lacked authority to change the ROE without showing it is outside the zone of reasonableness.
“There’s no protection from being in the range [of reasonableness], so any complaint can come in and [cite] a number that’s slightly lower than your number and then you’re in a hearing,” Plaushin said. “And that’s why this Emera remand is so important, because we need to figure out how we’re deciding what goes to hearing and what doesn’t. It can’t just be that I proved a number different than yours.”
Customers filed new complaints even as previous ones were still pending, she noted, because of the 15-month limit on refunds under the Federal Power Act. The clock starts on the date of the utility’s rate filing.
Plaushin said the zone of reasonableness can differ based on changes in interest rates and other inputs, or as utilities are added to or subtracted from the proxy group.
In June 2016, she noted, an administrative law judge determined 10.68% as the top of the range in a complaint against MISO TOs. This was little more than three months after another ALJ, ruling on the third complaint against the New England TOs, found the top of the range at 12.19%, with 10.9% as the midpoint.
“It just doesn’t seem to make sense. It just has to do with the fact of when they filed. … [New England] got lucky. They filed when there was a good number. And one of the things the commission will [have] to consider is: Do you really want to get into a situation where people are trying to game their ROEs by doing multiple filings just so they can track volatility?”
David E. Pomper of Spiegel & McDiarmid, who argued the Emera case for Massachusetts, predicted there will be more complaints challenging rates. “I’m certain of that,” he said. “There’s a lot of ROEs out there that are still way above the cost of equity.”
He agreed with Plaushin about the risk of a never-ending cycle of filings.
“I think that probably something we can all agree on is … if the results of the litigation changes dramatically from case to case, there’s something wrong with the way you’re reaching decisions,” he said. “That creates incentives to keep filing in the hope that you’ll get lucky.”
“The solution will be in the answer to the remand in Emera,” Plaushin said in an interview later, acknowledging FERC’s response was slowed by its loss of a quorum last year. “Hopefully that will establish better parameters, so we don’t have as many serial cases.”
Former FERC Commissioner Suedeen Kelly, a partner at Jenner & Block, who moderated the session, noted the increase in ROE challenges since 2011. The panel also featured Robert S. Kenney, Pacific Gas and Electric’s vice president of regulated affairs, who discussed the impact of ROEs on his company’s ability to adapt to distributed energy resources and protect the grid from cyber threats.
RTO technical staff are currently devoting time to creating a better market user interface — the nonpublic webpages MISO uses to accept energy bids and offers, MISO Senior IT Director Curtis Reister told the Market Subcommittee on Thursday.
The new interface is expected to work with Internet Explorer, Microsoft Edge, Chrome and Firefox. Reister said MISO sometimes forces users to use older versions of browsers for combability with the old interface.
He could provide no release date for stakeholders to peak at the new interface but said the RTO would keep them updated on progress.
MISO CEO John Bear last month said he expects about 200 employees to spend 100,000 hours total on the platform replacement project.
Final Uninstructed Deviation Proposal
MISO’s final proposal for dealing with generators’ uninstructed deviations from dispatch instructions appears to strike a balance between the views of RTO staff and stakeholders.
The plan calculates a generator’s uninstructed deviation by comparing the time-weighted average of its real-time ramp rate with its day-ahead offered ramp rate, while allowing for a 12% tolerance from set point instructions.
The proposal eliminates the RTO’s current “all or nothing” eligibility for make-whole payments, instead allowing generators to collect full payments when they respond to dispatch instructions at a rate of 80% or higher over an hour, while excluding payouts when performance rates fall below 20%. Units operating between those two thresholds would earn make-whole payments in proportion to performance. (See Monitor Backs MISO Uninstructed Deviation Proposal.)
The change would mean that a generator that fails four or more consecutive five-minute dispatch intervals within an hour by either providing excessive or deficient energy will not automatically lose its eligibility for make-whole payments.
In response to the concerns of some stakeholders that wind and solar resources would be flagged for producing excessive energy, MISO crafted an exception to its uninstructed deviation proposal. MISO Market Quality Manager Jason Howard said the RTO only plans to assess excessive or deficient energy charges on dispatchable intermittent resources during intervals when the resources are economically dispatched below the RTO’s forecast. Dispatchable intermittent resources that use their own forecasts will be charged for excessive or deficient energy like any other resource under the proposal.
Howard said the move could help eliminate any intentional under- or over-forecasting by intermittent resources in order to collect make-whole payments, an issue the Independent Market Monitor has repeatedly raised.
“I don’t think that we’re done here. We’re going to have other discussions about forecasting and intermittent resources,” Howard said.
MISO now plans to file with FERC to reflect the change by the third quarter of this year, with the new uninstructed deviation calculation in place by early 2019.
Multiple stakeholders thanked MISO staff for taking extra time to develop a compromise proposal.
MISO and PJM will pursue two separate interregional studies this year to identify potential joint transmission projects, the RTOs said last week.
One six-month study process would look for small cross-border projects, while a two-year effort would seek to uncover potential major interregional projects, stakeholders learned during a May 11 conference call held by the RTOs’ Interregional Planning Stakeholder Advisory Committee (IPSAC).
2nd Round of TMEPs
The shorter-term study will identify targeted market efficiency projects (TMEPs), a project category the RTOs created in 2017, subsequently approving a five-project portfolio in December. This category of smaller interregional projects is intended to target historical congestion along the RTOs’ seams.
Staff from both RTOs said the study would concentrate on historically binding flowgate constraints that have amassed at least $1 million in congestion charges. MISO and PJM have experienced about $500 million in congestion payments on more than 200 market-to-market flowgates in 2016 and 2017. PJM interregional engineer Alex Worcester said $200 million of that congestion will be addressed by planned upgrades, both by regional fixes and the five planned TMEPs.
“But there’s a bulk $300 million of congestion left on the seams that can be investigated,” Worcester said.
The second TMEP study will be conducted much like the first, and the RTOs hope to complete review of historical congestion along the seams by the end of June, Worcester said. The study will examine why flowgates were binding and determine whether transmission outages caused the problem.
The RTOs have committed to working with equipment owners associated with the congestion this July to zero in on which equipment is limiting the flow of electricity and discuss potential upgrades. By October, the RTOs hope to have completed an evaluation of project ideas and submit project recommendations for approval by their respective boards of directors.
TMEPs must cost less than $20 million, be in service within three years of approval and provide historical congestion relief that is equal to or greater than construction cost within the first four years of operation. The construction cost is divided between MISO and PJM based on the percentage of congestion relief benefits.
The two RTOs approved a $20 million, five-project TMEP portfolio last year, with projects in Illinois, Indiana, Michigan and Ohio; all are upgrades to existing systems. Project costs are on average allocated 69% to PJM and 31% to MISO, based on projected benefits, which are expected to reach $100 million. (See FERC Conditionally OKs MISO-PJM Targeted Project Plan.)
Northern Indiana Public Service Co.’s Miles Taylor asked if MISO and PJM would consider speeding up the process to get projects approved by the end of summer.
MISO’s Adam Solomon said his RTO may be open to the idea, but he added it would be difficult to expedite the process, considering that the grid operators must complete an analysis and obtain approval from both boards before moving forward with TMEPs.
Some stakeholders asked the RTOs to consider generation retirements when studying historical seams congestion, as retiring generation could alleviate congestion on its own. Solomon said the study process is already equipped to collect that type of information.
2-Year IMEP Study
MISO and PJM have also agreed to begin a more traditional two-year coordinated system plan study to identify more expensive seams projects called interregional market efficiency projects (IMEPs), none of which have been approved by the RTOs.
For the more involved study, Worcester said each RTO will develop an economic regional model and study project suggestions submitted by stakeholders. IMEP proposals must be submitted to both regional processes, with the proposal window open from Nov. 1, 2018, to Feb. 28, 2019, according to PJM Tariff rules. Board approval of potential IMEPs would take place by the end of 2019.
Before approval, proposals will be reviewed multiple times: first to determine eligibility, then to calculate interregional cost allocation and the share of regional benefits. A third review tests the projects against each RTO’s regional criteria, while the fourth and fifth evaluations involve getting approval from both the staff and boards for both RTOs.
“It seems like one of the goals MISO and PJM have is to remove the triple hurdle. What I’m seeing here is a five-hurdle,” Wind on the Wires’ Natalie McIntire remarked. “It just seems like we should have less review.”
Worcester said only three of the reviews result in a pass/fail outcome for a project. The first review simply determines if the project would be eligible under IMEP requirements, while the second only serves to get an idea of project cost benefits, he said.
MISO and PJM last conducted a coordinated system plan in 2016 and 2017, ending the process without recommending any projects. One serious contender, a proposed 30-mile, 138-kV line near the Indiana-Illinois border, ultimately failed the joint 5% generation-to-load-distribution factor test, which requires each RTO to show that at least one of its generators has at least a 5% impact on the affected flowgate. (See MISO, PJM Ponder Interregional Study.)
Axe 5% GLDF Test
As a result of the last two-year study, the RTOs plan to revise their joint operating agreement to remove the 5% generation-to-load-distribution factor test, instead letting each of their regional processes determine flowgate impacts. Solomon said the edits will also remove references to a MISO-PJM joint model study requirement, as the joint model was eliminated in FERC compliance filings in response to a 2013 complaint from NIPSCO on the RTOs’ interregional process. (See “No Joint Model,” FERC Signals Bulk of NIPSCO Order Work Complete.)
Solomon said MISO and PJM want the revisions in place before opening the IMEP project proposal window in November. For that to happen, Solomon said the changes should be on file with FERC no later than July.
CARMEL, Ind. — A recent MISO study slightly overestimated actual capacity offers in the 2018/19 Planning Resource Auction, stakeholders learned this week.
The RTO’s loss-of-load expectation (LOLE) study predicted about 143.3 GW of capacity in the Planning Resource Auction, while the auction itself attracted about 141.8 GW in offers, MISO Resource Adequacy Senior Engineer William Buchanan reported during a May 9 Resource Adequacy Subcommittee meeting.
MISO said three factors played into the difference between the study results and auction outcome:
PJM completed its third Incremental Auction in early March after the LOLE analysis was complete, which increased exports.
The LOLE used forecasts submitted in November 2016, while the PRA relied on forecasts with reduced load growth submitted in November 2017.
The LOLE study was completed before the latest round of Attachment Y retirement notice submittals, which were not included in modeling.
Buchanan also said a year-over-year decrease in transmission losses shaved peak load by about 426 MW.
MISO cleared 135 GW of capacity during the 2018/19 PRA last month, with nine of its 10 local resource zones clearing at $10/MW-day. The lone outlier was Zone 1 — covering parts of Wisconsin, Minnesota and the Dakotas — which cleared at $1/MW-day. (See MISO Clears at $10/MW-day in 2018/19 Capacity Auction.)
In more detailed results released this week, MISO cleared slightly less than 49 GW of coal capacity, down 3.3 GW from last year’s cleared volumes, while natural gas capacity was up about 2 GW at 51 GW. Cleared wind capacity remained relatively static at 2.2 GW, while solar capacity more than doubled from 180 MW to 461 MW. Nuclear capacity remained steady at 12.5 GW.
Capacity Import Limit Change
Some MISO stakeholders said they were caught off guard by an unexpected drop in capacity import limits used in the auction compared with preliminary auction data.
Consumers Energy’s Jeff Beattie asked why the auction’s actual CILs changed from the first published limits by “hundreds of megawatts.” He said the changes were a departure from previous years, when draft preliminary and final preliminary CILs remained relatively static.
“Zone 5 changed by more than 500 MW in the capacity import limit,” Beattie said.
Harmon said the RTO simply updated the limits for known exports out of the system to non-MISO load as it became aware of the changes. He said MISO may investigate requiring stakeholders to provide more information earlier.
From February to mid-March, when limits were finalized, MISO’s preliminary CILs fluctuated anywhere from 752 MW in Missouri’s Zone 5 to no change in Michigan’s Zone 7.
Vistra Energy’s Mark Volpe said MISO could do more to telegraph the limit changes to its stakeholders ahead of the auction.
“We did not hear a discussion as to why they changed. MISO needs to be more transparent,” Beattie said.
Laura Rauch, MISO manager of resource adequacy coordination, said the RTO would try to improve transparency in next year’s auction.
Exelon’s David Bloom said he was “begging” MISO to make preliminary PRA data easier to locate on its website.
MISO will meanwhile continue to make predictions for out-year capacity import and export limits, but it will use a new process of analyzing only those zones expected to bind on their import or export limits — or fall short of procuring local clearing requirements. MISO’s Matt Sutton said the RTO will now review those zones with its Loss of Load Expectation Working Group (LOLEWG) and then perform analyses on selected zones. Results will first be shared with the LOLEWG.
Sutton said the technical design of the new process will also be taken up at the LOLEWG.
MISO last month said it would revise its practice of forecasting long-term capacity import and export limits after proposing in early spring to discontinue them. (See “Reprieve for Out-year Import and Export Limit Estimates,” MISO Resource Adequacy Subcommittee Briefs: April 11, 2018.)
SACRAMENTO, Calif. — The California Energy Commission rocked the energy world Wednesday when it unanimously approved a mandate requiring new homes in the Golden State to include rooftop solar, making it the first state to move to adopt such a rule.
The 2019 Building Energy Efficiency Standards would apply to most newly constructed buildings and additions to existing structures built after Jan. 1, 2020, requiring builders to add solar panels and encourage battery storage systems and heat pump water heaters to improve energy efficiency. They also update standards for indoor and outdoor lighting by incentivizing maximum usage of LED lighting in non-residential buildings.
The proposed rules also include three other major components in addition to solar: updated thermal envelope standards that prevent interior/exterior heat transfer; residential and nonresidential ventilation requirements; and nonresidential lighting requirements. California for the first time extended the standards to health care facilities.
The package still requires approval from the state’s Building Standards Commission. CEC spokeswoman Amber Pasricha Beck told RTO Insider the building commission usually approves what the CEC sends over.
In discussion ahead of the vote, CEC members said the measure will cut energy bills and reduce greenhouse gas emissions, noting that the cost of solar panels has dropped dramatically in recent years. The vast majority of comments filed in the proceeding favored the changes.
CEC Chairman Robert Weisenmiller said that California has expanded its economy in recent years even while reducing greenhouse gas emissions. Implementing the standards will require close work between the commission and the building industry, which he said he wants to keep “vibrant.”
“This is just a milestone, but there is a hell of a lot of work to go between now and 2020, and we really have to keep our eye on the ball to make this work smoothly,” Weisenmiller said. “There will be some surprises, and we will need to stay on top of this, but the bottom line is we are going to focus on making this happen.”
“Once we get there, yeah, we can talk about the future,” he added.
The CEC’s Wednesday meeting drew an unusually heavy media interest for a commission decision, and by the evening even the BBC had picked up the story.
The measures will make it more expensive to build new homes in a state already known for some of the highest housing and construction costs in the country, but the commission said it will be worth the expense.
While the new standards will add about $9,500 to the cost of a new home, they will save homeowners $19,000 in energy and maintenance costs over 30 years, the CEC said. The changes would add about $40 to the average monthly mortgage payment but save $80 per month on heating, cooling and lighting bills. Nonresidential buildings will use about 30% less energy under the standards, mainly because of lighting upgrades, according to the agency.
The explosion of rooftop solar in California has led to massive amounts of solar output coming online and offline each day as the sun rises and sets, requiring increased use of fast-ramping generation resources to compensate for the variability. Asked about the impact on California’s “duck curve” that illustrates the steep ramps, CAISO spokesman Steven Greenlee said Thursday that zero-net energy home projections are included in the CEC’s Integrated Energy Policy Report (IEPR) forecasts, which the ISO uses in its transmission planning process.
“Our planning already takes into consideration state policies,” Greenlee told RTO Insider. “We have been managing increasing amounts of renewables coming onto the grid for many years and use the IEPR forecasts for transmission planning. However, as the amount of renewables on the system grows, grid operators need increased visibility into behind-the-meter resources, including developing practices for aggregated information sharing and operational coordination.”
Solar Energy Industries Association CEO Abigail Ross Hopper said: “This is an undeniably historic decision for the state and the U.S. California has long been our nation’s biggest solar champion, and its mass adoption of solar has generated huge economic and environmental benefits, including bringing tens of billions of dollars of investment into the state.”
California Building Industry Association CEO Dan Dunmoyer said the standards “struck a fair balance between reducing greenhouse gas emissions while simultaneously limiting increased construction costs.”
Parties issuing statements in favor of the proposal include the Natural Resources Defense Council, Habitat for Humanity San Joaquin County, California Solar & Storage Association, California Air Resources Board, Southern California Edison, Pacific Gas and Electric, and Tesla.
Opposition to the standards was mostly limited to individual commenters, some addressing aspects of the standards other than the rooftop solar mandate.
At the meeting, longtime Colorado-based energy attorney and consultant Peter Esposito said he only learned of the rooftop solar proposal on Tuesday.
“I initially thought it was ‘fake news,’ and I would like to add that I think you are making a big mistake,” Esposito said. He advocated against a technology-specific approach and said consumers should be able to choose how to meet greenhouse gas emission goals.
“Please don’t lock out other technologies,” he said, without being specific as to what particular technologies he was referring to.
The Public Utility Commission of Texas on Thursday delayed its final approval of Southwestern Public Service’s request to build a 478-MW wind farm in West Texas, allowing the company and other parties in the docket time to provide written answers to the regulators’ latest questions and recommend further revisions to the draft order (46936).
SPS said it could make a reply filing on May 16, clearing the way for the PUC’s final approval during its May 25 open meeting.
PUC Chair DeAnn Walker apologized for the two-week delay, saying she developed the questions as she reviewed the proposed order.
PUCT Chair DeAnn Walker (left) and Commissioner Arthur D’Andrea share a laugh. | PUCT
“I fully intended to get it done today,” she said. “If anything should be clear to anyone in this industry, it’s that I need to be comfortable with what I sign.”
The wind farm is part of a 1.23-GW project by SPS parent Xcel Energy that will provide renewable energy to SPS customers in Texas and New Mexico. The utility says the project will save its retail customers about $1.6 billion in energy costs over its 30-year life.
PUC staff filed a draft order on May 9 that revised its previous version, eliminating provisions rendered moot by a settlement reached in March between SPS and staff, the Department of Energy, the Office of Public Utility Counsel (OPUC) and seven other consumer groups, area cooperatives and landowners.
Walker filed a memo that same day outlining her concerns about SPS’ exceptions to the latest order. She said some rate-related findings suggested in the order would be more appropriately made in a future rate proceeding, and that some sections of the order “lack the clarity” necessary for inclusion in a PUC filing.
She focused much of her discussion on the order’s proposal to recover costs by flowing production tax credits through fuel, asking the parties to explain why the commission should deviate from its “well-established principles” of matching costs and benefits.
“The benefit of production tax credits flowing through fuel accrues to some customer classes more than the costs those same customers bear through their base rates,” Walker wrote. “Conversely, customers who bear more of the costs in their base rates receive less of the benefits, because they flow through fuel. This does not meet the commission’s typical matching principle.”
Attorney Rex VanMiddlesworth, representing Texas Industrial Energy Consumers, said the PTCs should flow through fuel as they are earned, pointing out that they are used when bidding into the markets.
“You’ve got to have those PTCs going through fuel, otherwise the fuel costs won’t reflect the actual [bid] … into the LMPs. You would be bidding in at -$28, and the customers wouldn’t be getting that -$28,” VanMiddlesworth said. “PTCs are kind of a classic energy allocation. When we have a rate case, if it’s litigated, I wouldn’t be surprised to say at least part of the PTC ought to be allocated on an energy basis.”
SPS President David Hudson reminded the commission that the utility has said the wind farm will be an energy resource, rather than a capacity resource.
SPS’ legal counsel Ron Moss, with President David Hudson to his left, answers questions. | PUCT
“Our intention all along is to allocate the base rate case cost on energy,” Hudson said. “It’s going to be consistent with how the fuel goes back and the PTCs go back. Everything is going to be synchronized. It’s just some parties thought there might be a capacity addition in the future.”
“We’ve never had a plant like this. Every other plant we had was to meet demand,” he said.
VanMiddlesworth said the SPS facility is being built “largely because of PTCs,” which make it profitable over the first 10 years.
“You have your decision then, we have our rights to address it at that time,” he said. “We don’t foresee it as a problem. We do want the ratepayers to get the PTCs as they’re earned.”
Rayburn Country Picks 44.6 Miles of Trinity Valley Assets
The commission also approved the transfer of certificate of convenience and necessity rights for 44.6 miles of existing 138-kV transmission lines in East Texas from Trinity Valley Electric Cooperative to Rayburn Country Electric Cooperative (Docket No. 47951).
Rayburn already owns or leases more than 360 miles of 138-kV lines that serve wholesale loads in both ERCOT and SPP. The transferred facilities are operated in ERCOT.
Connecticut’s General Assembly on Wednesday passed a bill that doubles the amount of renewable energy utilities must use to serve load — 40% by 2030 — while also revoking net metering guarantees that ensure rooftop solar owners earn retail prices for their excess electricity.
The bill now goes to Gov. Dannel Malloy, who said the legislation (SB 9) will help cut emissions and create “good jobs in the green economy, all while decreasing costs for ratepayers.”
Connecticut state capitol building in Hartford
The bill also extends $8 million in renewable incentives for commercial users and allows them to sell their output to utilities in 15-year contracts. The new law creates a 25-MW community solar program for residential customers who cannot afford to install their own solar panels.
Peter Rothstein, president of the Northeast Clean Energy Council, said in a statement that while the bill “contains a robust expansion of the state’s renewable portfolio standard,” it also includes “counterproductive provisions that will significantly harm the state’s rooftop solar market.”
Net metering “will essentially be dismantled,” Rothstein said.
A coalition of solar developers, solar proponents and environmental groups, including SunRun, Vote Solar and the Connecticut Citizen Action Group, had also urged state lawmakers not to pass the law without amending its net metering language.
“Instead of restricting customers’ ability to choose solar and imposing a cap on solar investment, the bill’s community solar program should be strengthened to expand solar access,” the coalition said. “Rather than building Connecticut’s local clean energy economy, the current bill language puts the future of solar in Connecticut and thousands of jobs at risk.”
WASHINGTON — A panel of electricity industry leaders — including Public Service Enterprise Group CEO Ralph Izzo — came to the House Energy Subcommittee on Thursday prepared to talk about the importance of transmission infrastructure, but the visit was mostly in vain.
Votes on the House floor kept the hearing to about 90 minutes, most of it taken up by the prewritten opening statements by subcommittee leaders and the panelists. Subcommittee members barely asked any questions, and none were directed to either Izzo or Jennifer Curran, MISO vice president of system planning.
In the little time allotted to them, the panelists made clear that FERC Order 1000, which opened transmission development to competition in 2011, was not working as intended, with very few projects being approved.
But they differed in their overall assessment of the order. Izzo called for Congress to outright abolish the rule, while former FERC Commissioner Tony Clark repeated his past assertion that the order was “well-intentioned” but clearly needs revisiting by the commission.
The order replaced RTOs’ “collaborative, bottoms-up approach to transmission planning with a complex bureaucracy, where the name of the game is completing a compliance checklist that may not actually result in transmission development,” Clark said. He pointed to MISO’s multi-value projects as an example of pre-Order 1000 developments that were impactful.
Rob Gramlich, president of energy consultancy Grid Strategies, submitted detailed written testimony highlighting the benefits of the grid in lowering consumers’ costs and allowing access to resources in other regions. Among his recommendations was that the Energy Department use the never-applied Section 1221 of the 2005 Energy Policy Act, which allows the secretary of energy to designate transmission corridors in the national interest and for FERC to site and permit projects in those corridors.
“I recommend that for specific extra-high-voltage (e.g., 500 kV and up), long-distance lines that provide broad multistate reliability benefits and long-term consumer benefits, where state approval has been withheld after thorough consultation, DOE and FERC should be encouraged to be willing to use the current authority,” Gramlich wrote.
In the little time she spoke, Curran only gave general information about her RTO, lauding its transmission planning processes and reliability record. Also in attendance were Edward Krapels, CEO of Anbaric Development Partners, and John Twitty, executive director of the Transmission Access Policy Study Group.
FERC should let RTO stakeholder processes work and not issue broad and costly new mandates, most commenters told the commission in its proceeding on grid resilience (AD18-7).
RTO Insider’s review of more than 60 of the dozens of comments filed ahead of the May 9 deadline indicated widespread support for RTOs’ requests in their initial filings in March for time to discuss the issues with stakeholders, more coordination with natural gas operators and more information on cyber threats. (See RTO Resilience Filings Seek Time, More Gas Coordination.)
But many commenters criticized PJM’s call for setting firm deadlines for rule changes, saying the RTO’s proposals would increase costs without necessarily improving resilience. Several commenters, including Edison Electric Institute and the National Rural Electric Cooperative Association (NRECA), suggested FERC schedule one or more technical conferences on the issue. Numerous commenters called for cost-benefit analyses of any new requirements.
“The record in this proceeding does not support any universal resilience standard or tariff changes requirements to be applied to all RTOs/ISOs. To the contrary, the record demonstrates that RTOs/ISOs have different resilience issues and priorities, and requiring all RTOs/ISOs to follow PJM’s proposed schedule on the issues pertinent to PJM will undermine each RTO/ISO’s efforts to address the specific challenges within its region,” they said. “Thus, the commission should reject PJM’s requests and allow individual RTOs/ISOs to pursue the resilience-related issues and initiatives they have identified in their region through collaborative efforts with their stakeholders and pursuant to the time frames they have established.”
Others, including the Advanced Energy Management Alliance, agreed that RTOs should continue their existing efforts to address their unique challenges. “PJM’s explanation of the need for changes to certain energy and ancillary market rules is helpful to inform the commission as to areas PJM is working on, but PJM cannot ask FERC to require rule changes to be filed in pre-emption of the stakeholder process or development of an evidentiary record that change is necessary.”
After rejecting the Department of Energy’s call for price supports for coal and nuclear generators in January, the commission asked its six jurisdictional RTOs and ISOs to respond to two dozen questions on resilience. This week’s deadline was for responses to the RTOs’ comments.
The comments touched on topics including FERC’s jurisdiction, fuel security, cyber threats and climate change, as well as individual regional issues.
Jurisdictional Concerns
Several commenters raised jurisdictional issues, noting that states, not FERC, have authority over distribution systems where most outages occur. Arizona Public Service said NERC’s reliability standards already address resilience.
“Before taking any additional steps to address resilience, the commission [should] consider the … comprehensive federal, state and industry efforts [that] address all levels of the electric grid and significantly contribute to ensuring” resilience, APS said. The utility criticized proposals it said “are clearly focused upon expanding the role of ISOs and RTOs and are, without understanding efforts at the state level and among utilities commercially, premature.”
The Pennsylvania Public Utility Commission asked FERC to “clearly articulate” its jurisdiction regarding resilience, saying it disagrees with PJM’s assertion that resilience is “‘within the commission’s existing authority with respect to the establishment of just and reasonable rates under the Federal Power Act.’ Therefore, clear and precise justification of FERC’s authority on this matter will be beneficial prior to any initial steps in regulating resilience,” the PUC said.
Entergy also disagreed with PJM’s “overly broad” interpretation of the commission’s jurisdiction.
The Large Public Power Council (LPPC) agreed with commission’s proposed definition of resilience but urged that “to the extent further rules or standards are considered, FERC must be mindful of the statutory limits on its authority,” saying the Federal Power Act does not provide the agency a general grant of authority “to take action on reliability or resilience outside its specific statutory role in the approval and enforcement of standards.”
The LPPC also contended there is “no basis” for applying any rule governing resilience to non-RTO areas, as had been recommended by MISO and PJM. “This is not an issue within FERC’s domain in non-RTO regions, where states and localities maintain authority over generation investment decisions and cost recovery,” the group said.
The Electric Power Supply Association sees it differently. “Resilience must be a priority in all regions of the country, not only those served by independent system operators or regional transmission organizations,” EPSA said. “Therefore, it is important for the commission to extend its inquiry on the holistic examination of resilience to all jurisdictional entities, particularly transmission owners and systems outside of ISOs/RTOs.”
The American Petroleum Institute said PJM’s proposals regarding gas-electric coordination — such as requiring interstate pipelines to offer new transportation services and build new infrastructure — are unnecessary and may be beyond FERC’s jurisdiction under the Natural Gas Act.
LG&E and KU Energy warned FERC against undermining existing state processes, saying its resource planning and transmission and distribution operations are working well, and noting that it is not part of an RTO. In 2017, the utilities said, they attained their lowest forced outage rate since 2004 at 3.46% of its baseload generation.
The Transmission Access Policy Study Group, which represents transmission-dependent utilities, said FERC should give RTO stakeholders time to build consensus on issues within their purview and leave distribution systems to state and local regulators.
Cyber Threats
PJM’s Transmission Owners Agreement-Administrative Committee said their members need more information from the government on potential cyber threats. “The threat data that resides at, for example, the Department of Energy, Department of Homeland Security, National Security Council and Department of Defense is vital for the RTO/ISOs to have access to for developing and implementing effective protection mechanisms,” they said.
“Therefore, it is essential that the commission develop a process by which PJM may receive verification concerning the reasonableness of vulnerability and threat assessments based on internal government data that has not been made available to RTOs on national security grounds.”
Exelon said FERC, DOE and DHS should participate in the development of modeling scenarios and create a “design-basis threat” to provide a baseline against which RTOs can measure their resilience efforts.
Climate Change’s Role
The Center for Climate and Energy Solutions said that FERC’s scope of grid resilience lacks an acknowledgment of climate change and how it could hinder resilience.
The environmental nonprofit said that although it would prefer FERC order “an economy-wide pricing mechanism” to absorb the economic impacts and even prevent some physical impacts of climate change, it said the commission should at least ensure that wholesale power markets are “internalizing the costs of carbon emissions” through carbon pricing.
Mobile substation | AEP Texas
The center added that increasing regularity of droughts threatens cooling systems for generating stations and rising temperatures will impede the capacity of bulk transmission lines to transport power. The nonprofit called on FERC to convene a technical conference to explore best practices for an industry coping with global warming.
“Climate science and lived experience show that historical conditions are no longer a reliable predictor of future conditions,” Pacific Gas and Electric said. “As issues arise in the future, PG&E encourages the commission to consider the risks of climate change when making decisions that could affect stakeholders’ ability to make climate-smart investments, or to make other decisions to address climate resilience for the future.”
Fuel Supplies
Numerous commenters cited the certainty of fuel supplies as an essential element of resilience.
NERC said FERC should consider encouraging firm transportation, multiple pipeline connections and dual-fuel capability for gas generators. “Further, the commission could consider requiring that resource adequacy assessments account for potential reliability ramifications associated with the ‘just-in-time’ natural gas fuel delivery model.”
“Fuel security risk is the most important factor to include in the commission’s definition of resilience and in its evaluation of grid resilience generally,” the American Coalition for Clean Coal Electricity said. The American Coal Council said coal generation retirements are a threat because intermittent resources can’t always be counted on.
Basin Electric Power Cooperative said its fossil generating units continue to be affected by markets “that fail to adequately compensate resources” for providing “essential electric service” in the wholesale markets.
The North Dakota co-op called for “equity across all fuel types,” saying the RTOs’ comments did not address the “preferential treatment” wind generation receives. It said a new ramp product, “if structured appropriately,” could reflect the value of stand-by products and provide “sufficient mitigation for assets that must stay online and incur losses” to backfill wind.
The Electricity Consumers Resource Council and industrial energy users warned against using resilience as a pretext for a “bailout” of coal and nuclear plants, adding, “No action to advance resilience can be considered ‘just and reasonable’ if it has not considered the impact to consumers and how to minimize that impact.”
Americans for a Clean Energy Grid, a coalition supporting a “fully electrified” society, noted that this winter’s “bomb cyclone” forced Northeast grid operators to rely on more expensive generation such as coal, oil and dual-fuel units, even while wind output — stranded by transmission constraints — was higher than normal during the weather event. “Thus, while wind power can be more reliable than other resources during extreme winter weather, it is limited by interregional transmission constraints,” the group said.
Role of Capacity Markets
While many commenters, including EPSA and the Natural Gas Supply Association, called for market-based responses to resilience needs, the American Public Power Association and NRECA said mandatory capacity markets are not producing the resource mix needed to provide required resilience attributes. “Rather than relying on the markets, appropriately accommodating state resource policy choices in the mandatory capacity markets likely would help alleviate some of these [resilience] concerns.”
API, in contrast, warned that some of PJM’s proposals “seem to be regressing back toward an integrated resource planning world where picking winners and losers takes precedence over markets and competition.”
Role of Transmission
Many commenters noted that most outages occur on the transmission and distribution system.
ITC Holdings said the bulk power system’s resilience faces “a substantial threat from the ongoing lack of any effective, regular interregional transmission planning processes between many RTOs/ISOs,” citing MISO’s seams with PJM and SPP. “Despite the highly interconnected nature of [the MISO-PJM] seam, and despite a long history of commission exhortation to ensure sufficient coordination between the two regions, no interregional transmission project has ever been planned for or built between these two RTOs. As such, each region is unnecessarily limited in its ability to call on generating resources from the neighboring region to respond to grid emergencies.”
Although the vast majority of customer disruptions occur because of failures of the distribution system and are beyond FERC’s jurisdiction, the commission could aid resilience by integrating distributed energy resources into wholesale markets and revising Order 1000 to increase the use of non-wires solutions to transmission constraints, said a group of environmental and public interest organizations, including the Natural Resources Defense Council and Environmental Defense Fund.
Trade group WIRES said FERC should update Order 890’s transmission planning principles to include resilience as a distinct planning driver for RTOs. “Generation and fuel supply policies offer only a limited hedge against potential disruption. Moreover, while distributed resources are important for rapid recovery, they are of limited long-term capability without the grid’s transfer capabilities,” the association said.
The Energy Storage Association said FERC could enhance resilience through greater storage use, embedding the resource type into transmission planning and encouraging wholesale market participation of distribution-level storage. “Storage decouples the element of time from supply and demand,” the ESA said. “It makes non-dispatchable generators dispatchable; it makes inflexible generators flexible; and it makes inefficient cycling generators more efficient.”
The WATT Coalition, a group of companies that offer technologies to increase the delivery capability of the existing grid, urged FERC to focus on how advanced transmission technologies can improve resilience. “During times of system stress, network topology optimization, dynamic line ratings, and power flow control can help ensure reliable operation,” the group said.
It noted that ISO-NE’s relaxation of transfer limits during this winter’s bomb cyclone allowed it to import an additional 200 MW of generation from NYISO. “When it is cold, cloudy, or windy, lines are cooled, so they can physically deliver more energy without sagging or over-heating,” the coalition said.
Tesla warned against a definition of resilience that focuses on generator availability or transmission. “Distributed energy resources that are co-located with load can continue to provide electric service to customers even in the face of a complete failure of the bulk power system and are best-placed to provide resilience in a wide variety of contingencies impacting the grid,” it said.
PJM Comments Under Scrutiny
PJM’s March filing was the subject of numerous commenters.
“In its zeal to address resilience in its own market, PJM has inappropriately laid out directives and requirements for every other market to follow, according to PJM’s proposed time frames,” EPSA said.
EEI agreed, saying “it may be premature to require all RTOs/ISOs to make specific filings as requested in PJM’s comments.”
David Patton, whose company Potomac Economics provides market monitoring services to MISO, ISO-NE, NYISO and ERCOT, said adopting PJM’s proposal to allow inflexible generators to set clearing prices would have boosted MISO’s system marginal prices by 30%, based on analysis of the 12 months ending in October 2017. (See Critics Slam PJM’s NOPR Alternative as ‘Windfall’.)
“This plan is a fundamental departure from the efficient locational marginal pricing framework that has been the foundation of all successful wholesale markets in the U.S.,” Patton said. “It would, for the first time, introduce fixed costs into real-time pricing that are clearly not marginal in the real-time dispatch horizon. In effect, PJM would be requiring that the average costs of all resources needed to service load be reflected in every five-minute interval.”
The Pennsylvania PUC said it supported some of PJM’s proposals but feared that some “offered in the name of resilience may shortchange or even bypass normal PJM stakeholder deliberative processes” and warned against giving RTOs “a license to ‘gold-plate’ the generation, transmission and cyber assets of its members to achieve standards of resiliency that are disproportionate to a particular vulnerability or threat assessment.”
The regulators said they were concerned over the potential scope and costs of PJM’s proposals. “Some of PJM’s recommendations, especially in the market design arena, appear to utilize the grid resilience docket as another forum to advocate for specific market modifications, such as energy price formation, that are not immediately germane to the resilience discussion,” the PUC said.
It agreed with PJM that FERC may need to “revisit” NERC reliability standards. “However, revision of NERC standards is a complex, time-consuming process that should be allowed to proceed on its own timeline without an accelerated impetus from this docket.”
The PJM Power Providers Group (P3), on the other hand, praised the RTO’s “thoughtful recommendations” for addressing “antiquated energy price formation structures.”
“However, the stakeholder deliberations regarding this issue have been unproductive to date. Commission direction may be required for energy price formation goals to come to fruition as a means to support the commission’s resilience aims,” it said. P3 expressed concern over PJM’s proposal to permit non-market operations during emergencies, saying the commission should require the RTO to submit Tariff revisions to allow the change.
PJM also received support from American Electric Power, Dayton Power and Light and East Kentucky Power Cooperative, which made a joint filing as the PJM Utilities Coalition.
The coalition said it agrees with PJM’s recommendation that all RTOs be required to submit proposed Tariff changes to implement resilience planning criteria and develop processes for the identification of vulnerabilities.
“No meaningful steps towards a resilient system can begin without appropriate direction given by the commission that explicitly grants power to the RTO to establish resilience planning criteria and other aspects of the process,” it said. It also questioned whether the stakeholder process could address the issues. “If PJM reverts to a stakeholder process to determine resilience criteria, the process may get mired in political debates and cost allocation, and not focus on the necessary task of determining objective resilience criteria. For this reason, clear direction from FERC to guide that process is requested.”
PJM also filed reply comments, saying it wanted to provide additional information on its fuel security initiative announced April 30, clarify its proposals regarding gas-electric coordination and “provide context for its approach to this docket relative to the approach taken by certain other RTOs and ISOs.” (See PJM Seeks to Have Market Value Fuel Security.)
The Organization of PJM States Inc. (OPSI) said PJM’s filing did “not address the prudency and affordability of measures that may be implemented as a result of” the RTO’s recommendations, which it said indicate “extensions of its current mandate.”
“While not the stated intent, a future PJM could be positioned to drive transmission planning and craft new market structures in its mandate to address perceived low-probability, high-impact threats,” OPSI said. “The prospect of this expanded authority, with planning and decision-making impacting billions of dollars in investments with cost recovery from end users, may require a re-examination of PJM’s scope, governance and oversight.”
Graph on the left shows how baseload resources recover their fixed commitment costs under current LMP rules. During the peak hours, prices are typically above the resource’s marginal costs; the excess revenues in area B will exceed the amount by which the revenues fail to cover average costs in area A. Under the PJM proposal (right), LMPs would cover the average cost of all baseload resources needed to serve load. | Potomac Economics
Industrial energy users, consumer advocates for Delaware, New Jersey and D.C., and American Municipal Power, filing jointly as PJM Consumer Representatives, said the inconsistencies between the positions of PJM and those of other RTOs indicate the need for regional flexibility.
“Unlike the comments of the other RTOs/ISOs, PJM’s comments embark on an aggressively activist course, advocating positions that could result in substantial changes to PJM energy and capacity market rules, in addition to whatever changes may be necessary in transmission planning and system operations rules,” they said.
They called for a cost-benefit analysis or “prudence assessment” of any new resilience rules and said neither the 2014 polar vortex nor the 2017-2018 cold snap “justify subsidizing uneconomic coal and nuclear units … in the name of resilience.”
FirstEnergy’s regulated utilities called for urgent action, noting they sought voluntary load curtailments during the polar vortex to prevent load shedding for 142,000 customers. FERC should “immediately implement stopgap measures to preserve the operation of generators that contribute to grid resilience until a full evaluation of resilience needs is complete,” the utilities said.
FirstEnergy Solutions, the company’s merchant generation unit, said it “disagrees with the overall thrust of PJM’s comments.” It called for FERC to adopt mandatory resilience standards for RTOs and ISOs and ensure the continued operation of “critical” nuclear and coal-fired generators in the interim.
The Natural Gas Supply Association said PJM’s fuel security initiative “appears to reflect an unsupported bias against natural gas.”
“PJM states that the process of examining fuel risk will be done in a fuel-neutral manner. However, its document describing its process only refers to risks associated with greater reliance on natural gas and the language suggests that PJM has already made an unsupported predetermination that natural gas is a weak link in their ability to be reliable and resilient.”
ISO-NE
ISO-NE’s response to FERC’s identified fuel security as its resilience risk. It said potential responses include additional gas pipeline or LNG capacity, relaxing rules on dual-fuel resources and additional investments in renewables and transmission.
The New England Power Pool Participants Committee stressed that resilience solutions be worked out in the stakeholder process, calling it “a prerequisite to yield the solutions that work best for New England.”
The New England States Committee on Electricity shared ISO-NE’s perspective that fuel security presents the primary challenge to the resilience of the region’s power system. NESCOE recommended additional analysis of potential risks and cautioned “against prescriptive actions or further processes” that could impede regional or state efforts to mitigate fuel security challenges.
The New England Power Generators Association said ISO-NE’s Operational Fuel Security Analysis (OFSA) “neither captures market participant behavior in response to price signals nor the probability of any particular outcome … and therefore should not be the basis for the market solutions to be developed and later filed for acceptance with the commission.” (See Report: Fuel Security Key Risk for New England Grid.)
Eversource Energy said ISO-NE’s fuel security study “may understate the magnitude and scope of the challenges.”
“This could lead one to falsely conclude that only minor changes are required, and that commission action may be unneeded at this time. To the contrary, time is not on New England’s side,” the company said.
The company urged the commission to convene a New England-specific technical conference to determine state and federal actions to improve the region’s infrastructure, citing additional gas pipeline capacity from the Marcellus shale deposit and electric transmission to carry Canadian hydropower and on- and offshore wind.
The attorneys general of Massachusetts, Rhode Island and Vermont also cautioned against overreliance on the OFSA, which they said “relies on underlying assumptions that do not present a realistic or complete view of either the present or the future bulk power system.”
“The OFSA presents a deterministic (as opposed to probabilistic) analysis that provides no context about whether modelled events are likely to occur,” they said.
They also said the study’s approach to resilience is overly narrow, failing to consider “cyber and physical adversarial threats, technological accidents, and extreme heat and other weather events.”
The region’s local gas distribution companies recommended FERC “consider expedited review of and decisions on new natural gas pipeline certificate applications in critical fuel security regions.”
NYISO
NYISO told FERC in March that it does not face “imminent resilience concerns that require immediate action.”
The New York Public Service Commission said it agreed that ISO and stakeholder efforts to address bulk system resilience “are comprehensive and continuous,” asking for no other FERC measures beyond its “continued attention.” The PSC also agreed with the ISO’s suggestion for the commission to host a technical conference on bulk system resilience.
The Independent Power Producers of New York also supported the ISO’s approach and said FERC should not force it to abide by PJM’s suggested deadlines. “Efforts to ensure resilience should not be rushed to meet some arbitrarily short time frame unless they are justified by the evaluation of the ISO/RTO,” the group said.
The New York Transmission Owners also called on the commission to respect regional differences. “Any requirement to change course could impede resilience efforts already underway in the stakeholder process,” they said.
MISO
The Organization of MISO States said NERC standards, combined with initiatives from RTOs, state regulators, utilities, municipalities and others were enough to ensure long-term resilience. No additional rules or standards are necessary, the group said, especially those that might impede on state jurisdiction. “It is clear to the OMS that the appropriate processes are already in place to identify and adapt to the evolution of the industry and perceived threats to resilience,” the group said.
The MISO Transmission Owners emphasized that RTOs have only part of the answer to resilience, noting the role of distribution systems.
“MISO and its utility members have developed an integrated electric system that is currently sufficiently resilient, and MISO has identified no imminent resilience crises requiring commission action,” they said. “Notwithstanding MISO’s and its members’ regional efforts, enhancements to interregional coordination will promote greater resilience. Thus, while seams issues are broader than the concept of resilience, MISO is correct that the commission should not ignore the benefits of greater, more effective and efficient interregional cooperation in this proceeding.”
Entergy said it saw no need for a federal role in determining the proper long-term resource mix — “at least in MISO.”
The company called for resource adequacy to “continue to be a shared responsibility in MISO,” with state and local regulators determining the fuel mix.
“In this way, state and local regulators ensure diversity of fuel resources consistent with each area’s needs and those regulated utilities’ customers bear the cost burden and the reliability and resiliency benefits of those local regulators’ decisions,” Entergy said. “Direct federal action to regulate the long-term resource mix also could jeopardize utilities’ continued participation in MISO.”
In a joint filing, the Coalition of MISO Transmission Customers and Illinois Industrial Energy Consumers said that resilience is already central to the RTO’s reliability assessments. “The commission should not carve out resilience and treat it as a discrete characteristic of wholesale electricity markets,” they said, adding that any resilience requirements should be subject to cost-benefit analyses.
Northern Indiana Public Service Co. said that most grid innovation is happening with customer-owned technologies that connect at distribution level, urging FERC to work with state regulators to address resilience “across the entire electric value chain.” The company said that a “top-down, nationally-focused approach could overemphasize one or two parts of the overall electric system” and fail to account for the adoption of storage devices, electric vehicles, microgrids and DERs.
Alliant Energy used its comments to call for modernizing the Public Utility Regulatory Policies Act and criticize qualifying facilities “that haphazardly site themselves on the grid, causing distribution system and system planning issues.” Alliant said PURPA must be reworked to incent QF developers to concentrate on “system reliability and long-term grid stability.”
SPP
SPP’s Market Monitoring Unit emphasized the importance of creating standards and metrics to quantify and measure resilience.
“We recommend that in addition to defining resiliency, the commission and the parties should also engage in discussions to measure resiliency in order to assess whether an area has or has not attained resiliency. This measurement may also contribute in creating new market mechanisms to promote resiliency,” the Monitor said.
It pointed to SPP’s 30 to 36% capacity margins over peak needs but said that those high levels do not necessarily equate to resilience.
The MMU also said the resilience discussion should not be used “as a venue to promote certain price formation proposals.”
CAISO
The California Public Utilities Commission said the state “has made substantial efforts to ensure grid reliability and resiliency by ensuring redundancy and coordination in its energy planning efforts,” citing the deployment of distributed energy resources and smart inverters.
It also noted the state “continues to aggressively plan for a changing climate to ensure Californians have safe, affordable and reliable access to electricity.”
Nevada Hydro, which develops pump storage projects, said CAISO’s transmission planning process has fallen short in properly valuing hydropower. CAISO’s “transmission economic assessment method (TEAM) has not fully applied the method to storage projects and has not quantified the grid reliability and resiliency benefits of the projects it has examined,” the company said. It said FERC should direct RTOs to include pumped storage hydro in transmission studies and resource adequacy planning.
Southern California Edison said FERC should consider regional differences and costs. It said it shares CAISO’s view that FERC’s proposed definition of resilience is lacking.
It said the use of the term “‘disruptive events” is indistinguishable from “‘contingencies,’ which, per NERC reliability standards, refers to unexpected failures or outages of a [Bulk Electric System] component.”
Contributing to this article were Robert Mullin, Jason Fordney, Amanda Durish Cook, Tom Kleckner, Michael Kuser, Rory D. Sweeney and Rich Heidorn Jr.
