FERC on Tuesday approved a settlement reducing Southern California Edison’s 2018 base transmission revenue requirement (TRR) and return on equity, and a partial settlement on the utility’s 2019 request for an ROE increase to reflect wildfire risks.
The commission approved an uncontested settlement in a dispute over SCE’s 2018 base TRR and revisions to its formula rate methodology (ER18-169-002). It set the case for hearing and settlement procedures in late 2017, saying that although SCE proposed a reduction in its TRR, “a further decrease may be warranted.” (See FERC Sets Hearing on SCE Tx Rates; Glick Dissents.)
The commission approved the deal after its endorsement by FERC trial staff, which said the settlement “provides numerous benefits to customers,” including increased transparency of the utility’s cost inputs and “near-immediate rate relief.”
Investigators found that Southern California Edison power lines sparked the Thomas Fire, which killed two people in December 2017 and led to mud flows that killed 21 more. | U.S. Forest Service
SCE had proposed a base ROE of 10.3%. The settlement reduces that to 9.92%, exclusive of the 50-basis-point CAISO adder and project-specific adders equivalent to 0.78%.
The true-up TRR for 2018 was set at $1.079 billion. SCE had sought a TRR of $1.169 billion, down from $1.189 billion in 2017.
The settlement also adjusts how SCE calculates its capital structure, limits its recovery of incentive compensation and allows more time for stakeholders to discuss draft annual updates with the company.
The utility also agreed to pay up to $350,000 for the California Public Utilities Commission’s consultant to participate in the CAISO transmission planning process, the transmission maintenance and compliance review, and the 2019 formula rate annual update and settlement negotiations. SCE and the CPUC also agreed to continue discussions on potential rate design modifications.
SCE’s proposed two-year limitation on correction of errors was eliminated.
FERC had required SCE to file a replacement transmission rate recovery mechanism as part of a settlement over its original formula rate, which took effect in 2012. SCE had recovered its TRR through stated rates after unbundling its retail transmission rates and transferring operational control of its transmission network to CAISO in 1997.
SCE Wins 12.47% ROE in Temporary Deal
The commission on Tuesday also approved a partial settlement reducing SCE’s ROE from 17.62% to 12.47% as settlement proceedings continue over the company’s 2019 TRR (ER19-1553-001).
SCE requested the 17.62% ROE in April, citing “dramatic material changes to SCE’s regulatory and financial conditions that have occurred” since the utility’s prior rate took effect in October 2017 — a reference to the potential for multibillion-dollar costs based on California’s strict liability standard for utility-sparked wildfires. In June, FERC tentatively accepted the increase but postponed any change for the maximum five months and set it for an evidentiary hearing. (See FERC Leery of SCE’s ROE Request for Wildfires.)
The partial settlement, which was unopposed, “does not definitively resolve any issues set for hearing but reduces SoCal Edison’s ROE on an interim basis,” the commission wrote. It noted trial staff’s comments that the commission “has not found the 12.47% ROE to be fair, reasonable or in the public interest, and that it is leaving a final determination on that issue to the existing hearing and settlement judge procedures.”
SPP launched its Western reliability coordination service Tuesday afternoon, becoming the first regional transmission organization to handle RC services in both the Eastern and Western Interconnections.
The RTO said the transition from Peak Reliability, the Western Electricity Coordinating Council’s RC provider since it was separated from WECC in 2014, was seamless and took place at noon, Mountain Time.
SPP is now responsible for ensuring the bulk electric system’s reliability for 16 entities, representing about 12% of Peak’s legacy load: Arizona Electric Power Cooperative (AEPCO); Black Hills Energy utilities Black Hills Power, Cheyenne Light, Fuel and Power Co. and Black Hills Colorado Electric; City of Farmington (N.M.); Colorado Springs Utilities; El Paso Electric Co.; Intermountain Rural Electric Association; Platte River Power Authority; Public Service Company of Colorado (Xcel Energy); Tri-State Generation and Transmission Association; Tucson Electric Power; Western Area Power Administration (WAPA) Colorado River Storage Project Management Center; WAPA Desert Southwest Region; WAPA Rocky Mountain Region; WAPA Upper Great Plains-West.
The grid operator spent more than a year working with the companies to develop its Western RC services and manage their implementation. SPP established data connections to new customers, built out systems and processes and ensured everyone was ready for the transition.
“AEPCO commends the staff at SPP for the dedication and diligence required to successfully pull off a daunting task,” Arizona Electric’s executive director of system operations, Shane Sanders, said in a statement. “AEPCO appreciates the level of detail required to bring in the project on time and on budget without any unexpected surprises or hurdles. Hats off to a job well done.”
CAISO has been providing RC services for the vast majority of WECC since July. Like SPP, CAISO jumped at the opportunity to expand its services when Peak announced last year it would wind down operations at the end of 2019. (See CAISO RC Wins Most of the West.)
Canadian entities BC Hydro and the Alberta Electric System Operator are serving as RCs for their footprints, accounting for another 14% of the WECC’s load.
WECC CEO Melanie Frye called the transition a “major reliability milestone” and lauded Peak’s leadership and staff for providing “high-quality RC services” up until the last moment of Peak’s existence.
“The transition to multiple RCs represents a significant accomplishment for all new RCs, their customers, Peak Reliability, and the overall reliability and security of the bulk power system in the Western Interconnection,” she said.
“We greatly appreciate the work of Peak, CAISO and SPP to make the transition as smooth and seamless as possible,” said WAPA COO Kevin Howard.
SPP framed its Western RC services as “laying the foundation” for additional offerings as part of its Western Energy Services portfolio. The RTO already administers the Western Interconnection’s unscheduled flow mitigation plan for six utilities, and it will launch an energy imbalance service in 2021. (See WAPA, Basin, Tri-State Sign up with SPP EIS.)
The RTO has been a NERC-certified RC in the Eastern Interconnection since 1997, managing about 40 GW of load. Its RC service territory now extends from the Canadian border to the Texas Panhandle.
FERC rejected transmission rate challenges on Monday against Potomac Electric Power Company (Pepco) and Delmarva Power & Light that challenged the accounting of each utility’s prepaid pension assets in its annual update.
Delaware Municipal Electric Corp. and the Southern Maryland Electric Cooperative in January questioned the prudency of the utilities’ combined $522.5 million in retirement contributions, suggesting the costs were voluntary and inappropriately included in their 2018 transmission base rates.
Both Pepco and Delmarva participate in a consolidated retirement fund with Atlantic City Electric Co. and Baltimore Gas & Electric. Parent company Exelon manages the account and determines annual contribution requirements for each utility, based on federal law and an internal policy that mandates at least a $300 million contribution until fully funded. Pepco and Delmarva raised transmission rate bases last year by $34.5 million and $12.4 million, respectively, to account for the prepaid pension assets.
SMECO said Exelon’s policy lacks transparency and its funding strategy remains unclear, noting the contributions go above and beyond federal mandates — arguments FERC rejected in its order Tuesday (ER09-1159). DEMEC’s complaints against Delmarva were likewise dismissed, just as they were in a near-identical challenge to the company’s 2016 annual update (ER09-1158).
“The commission did not say [in 2016] that an expenditure is imprudent if it exceeds the minimum funding requirements established by federal pension laws, or that there is a serious doubt about the prudence of an expenditure just because it is not required by federal pension laws,” FERC wrote. “SMECO’s argument runs contrary to the commission’s prudence standard because it suggests that Pepco was limited to a single correct act — making cash contributions that matched minimum funding obligations under federal law — rather than having discretion in its decision-making.”
DEMEC’s attempts to solicit refunds from Delmarva for accumulated deferred income tax (ADIT) associated with two retired transmission facilities also failed, since the utility paid the ADIT balance to the appropriate government authorities per IRS procedure.
FERC also said Delmarva acted appropriately when it used historical formula rate methodology to true-up rates between Jan. 1, 2018, and May 31, 2018, despite the fact the federal income tax rate had dropped from 35% to 21% that year.
Questions about the utility’s accounting of software-related expenses as miscellaneous intangible plant costs, which raised the rate base by $10,000, were also dismissed as unproblematic because the category accounts for licensing, an “intangible” element of software.
FERC on Monday accepted revisions to PJM and MISO’s joint operating agreement (JOA) but declined a broader review of how interregional planning coordination could be improved with SPP (ER20-34, ER20-36).
MISO and PJM filed identical sets of JOA revisions in October that clarified the coordinated system plan (CSP) process, corrected errors and addressed inconsistencies in earlier versions. The revised JOA:
Clarifies that a CSP study including a more complex, longer duration study provides for, but does not require, the development of a joint model;
Clarifies that construction of interregional transmission projects is subject to the regional tariff in which the facilities will be constructed;
Removes the interregional market efficiency project criterion that at least one dispatchable generator in the adjacent market has a generation-to-load distribution factor of 5% or greater;
Removes references to use of a joint model from the determination of benefits; and
Removes a legacy provision that allows testing of any project against interregional cost allocation criteria outside a CSP study.
The RTOs said the revisions reflect their stakeholder processes and “are intended to improve and add greater clarity to the development of the CSP process.”
Units of International Transmission Co. told FERC the revisions were an improvement but said more changes were needed to address planning coordination with SPP.
The companies also said the JOA between MISO and PJM disfavors interregional transmission projects with more broadly-applicable benefits and FERC should consider “elevating interregional transmission planning processes to a more equal footing with their respective regional counterparts.”
FERC rejected ITC’s arguments as out of scope.
PJM and MISO footprints | MISO, PJM
Interconnection Changes Approved
On Tuesday, the commission also approved changes tightening MISO’s site control requirements in the definitive planning phase (DPP), the final step of its interconnection studies (ER20–41).
Under the new rules, effective Dec. 4, MISO will require a demonstration of 100% site control 90 days before the DPP begins. It will also eliminate its $100,000 cash deposit in lieu of demonstrating site control.
MISO also is making the M2 milestone payment 50% at-risk unless an interconnection request is withdrawn before the start of DPP phase I. The commission agreed with the RTO that the change would discourage interconnection customers from submitting speculative projects and reduce the harm caused by project withdrawals.
Sparrows Point, Md. — New signs of life are emerging amid the rubble of what used to be the world’s largest iron and steel mill.
Tradepoint Atlantic, which is redeveloping the 3,300-acre site of the former Bethlehem Steel Sparrows Point, calls its project a “modern industrial revival.” But instead of manufacturing the skeletons of bridges, office buildings and warships on the site, Tradepoint Atlantic is building infrastructure for international trade and e-commerce.
With access to ship, rail and truck transportation, supported by the heavy industrial electrical and other utility services left from the steel mill, this “intermodal logistics hub” has already attracted Amazon and Baltimore-based Under Armour, which have neighboring warehouses totaling 2 million square feet. Home Depot and Floor & Decor are about to open even bigger distribution facilities nearby. And Volkswagen has leased 115 acres as a terminal to handle the import of 120,000 cars annually.
One place that will be doing at least some manufacturing is the 45-acre site Denmark-based Orsted is developing as a staging area for its 120-MW Skipjack offshore wind farm planned near the Maryland-Delaware border.
Sparrows Point is one of four ports being developed for OSW on the East Coast, with nine others under consideration, according to the Business Network for Offshore Wind.
Orsted, the world’s leading offshore wind developer with about one-quarter of world market share, is investing $38.2 million in Sparrows Point to satisfy the “local content” requirement Maryland regulators demanded in their contract to purchase Skipjack’s offshore renewable energy credits. Orsted also is making port investments in Rhode Island ($40 million in ProvPort and Quonset), Long Island (an operations and maintenance hub in Port Jefferson) and New London, Conn. ($57.5 million in a joint venture with Eversource Energy).
On Monday, Tradepoint and Orsted hosted an open house and tour for about 100 people — including local union officials, a state senator and former Bethlehem Steel workers — curious about the plans.
The visitors saw workers driving piles into the site of the “LoLo” (lift on, lift off) berth, where cranes will move heavy equipment. That is perpendicular to the “RoRo” (roll on, roll off) berth. The two comprise a 15-acre dockside operations area, which is designed to handle loads as heavy as 15 tons per square meter.
Adjacent to that will be a 115-acre manufacturing and “laydown” area, where the 351-foot turbine blades and even longer monopiles will be stored. The laydown area could grow, said Russell Williams, a Tradepoint business development associate who led the tour. “For the size and weight of the components for offshore wind, we need a lot of space and we need a lot of heavy [load-bearing capacity],” he said.
Orsted also will have access to the 1,200-by-200-feet dry dock, which could be used for assembling gravity-based turbine foundations.
For starters, much of the equipment for the windfarm — including the monopiles and blades — will be imported from Europe to Sparrows Point for assembly. Only the external platform, suspended internal platform (housing for electronics and switch gear), boat landings and anode cage, will be manufactured locally initially.
“Obviously, the long-term goal would be to manufacture [the blades and monopiles] here, but for the first round of projects that’s not really feasible,” said Zach Finucane, an Orsted manager of the project.
Using the Chesapeake & Delaware Canal as a shortcut to the Atlantic, Orsted’s staging facilities will be about 94 miles from Skipjack (which is in the federal government’s Delaware Wind Energy Area, although it will sell its output to Maryland ratepayers).
Growth Opportunities
The Atlantic Coast between Cape Hatteras, N.C., and Cape Cod, Mass., has seen the most interest from OSW developers in the U.S., due to its strong winds, the shallow waters of the continental shelf and its large, energy-hungry coastal population.
Brandon Burke, policy and outreach director for the Business Network, notes six states in the region — Massachusetts, Vermont, New York, New Jersey, Maryland and Virginia — have renewable portfolio standards of at least 50%. The region also will need capacity to replace retiring nuclear and coal plants, he noted.
Burke said state commitments exceed the capacity of the OSW leases the federal government has issued on the East Coast. “We are encouraging the federal government to issue additional leases, and we do see that coming, particularly in the New York Bight,” which stretches from the Cape May Inlet in New Jersey to Montauk Point on the eastern end of Long Island, he said.
Orsted site plan | Tradepoint Atlantic
Orsted hopes to win all the permits it needs for Skipjack by 2021, with installation beginning in 2022 and commercial operations later that year.
The new technology has resulted in a potential roadblock: The Maryland Public Service Commission announced last month it had opened a comment period on Skipjack and US Wind’s project in the state’s wind energy area after learning the turbines for both will be about 200 feet taller than originally planned.
PSC spokeswoman Tori Leonard said she could not speculate on what action, if any, the commission will take after reviewing the comments. She denied a report that the commission was reconsidering its orders granting the wind farms ratepayer subsidies, saying it was taken out of context.
Finucane said Orsted is optimistic the review will not delay its timeline. “Obviously there’s always risks [of delay] to any construction project. We’re hopeful that’s not going to be a showstopper.”
SAN ANTONIO — Two environmental groups that say regulated utilities’ practice of self-committing coal plants is costing ratepayers have a point, RTO officials said Monday, even as they challenged the groups’ estimates.
The issue is also attracting scrutiny from state regulators.
The Sierra Club released a study last month that estimates that “captive ratepayers” in MISO, SPP, ERCOT and PJM paid $3.5 billion more for energy from 2015 to 2017 because of the “noneconomic dispatch relative to the potential procurement of energy and capacity on the market.”
Meanwhile, the Union of Concerned Scientists (UCS) will release a study early next year that indicates that if MISO economically dispatched all its generation, average wholesale power prices would rise 3% but production costs would drop 11%. That would lower consumer costs, UCS Senior Energy Analyst Joe Daniel said during a Nov. 19 breakfast panel at the National Association of Regulatory Utility Commissioners’ annual meeting. “The market surplus, the relative profitability of the MISO system, would improve by 64%,” Daniel said.
The group, along with the Sierra Club and consumer advocates, has raised concerns about coal plants owned by vertically integrated utilities that self-commit, or run out of merit at times when their production costs exceed the wholesale market price.
The Sierra Club said out-of-merit operations suppress market prices, estimating that MISO’s median hourly market price would have been about $7.70/MWh (30%) higher if coal units had economically dispatched in 2017. “Improved dispatch practice would reduce customer costs, improve market revenues for efficient generators and renewable energy operators, and substantially reduce emissions,” it said.
Coal production costs are frequently above market prices, according to UCS. | Union of Concerned Scientists
‘Markedly Different Behavior’
The organization said the decision to operate consistently out of merit is not based on coal generators’ constraints alone, such as slow ramp rates, large fixed-price fuel contracts and avoiding the thermal stresses of repeated start-ups. “For example, within PJM, where most power units are merchants (i.e. unregulated), coal units generally operate in accordance with market prices. The few regulated coal units, owned by Dominion [Energy] or American Electric Power, demonstrated a markedly different behavior, operating in far more hours than warranted by market prices.”
Dominion did not respond to Sierra Club’s observations in detail Monday, saying in an email only: “Our customers expect clean energy that’s also affordable and reliable. We deliver just that, with enough solar and wind energy in operation or under development in Virginia by 2022 to power 750,000 homes. We’re proud of what we’ve accomplished and plan to do more.”
AEP’s Melissa McHenry said the report “does not provide an accurate portrayal of AEP’s generation unit operations within the RTOs” and said RTOs could improve efficiency through multiday dispatch and by sharing forecasted unit operation data.
AEP bids its generation into the markets to allow it to be economically dispatched, but the coal plants’ long start-up time makes it necessary to commit the units “to ensure they are available to produce benefits for our customers,” she said.
“During periods in which AEP anticipates sustained low prices, AEP does offer coal units for commitment and decommitment,” McHenry said.
RTOs Respond
ERCOT said it doesn’t comment on reports that are not staff’s own. Beth Garza, director of ERCOT’s Independent Market Monitor, said on Monday she had not reviewed the report and cautioned against assessing the results of decisions after the fact. “There are legitimate reasons why commitment decisions may appear uneconomic after the fact,” Garza said. “Specific examples are the load forecast didn’t materialize, or actual wind generation was higher than forecast.”
SPP said self-commitment “is not inherently and totally undesirable,” noting a self-committed unit may displace a more expensive one from running. But SPP spokesman Derek Wingfield acknowledged that self-commitments “may limit a market operator’s ability to dispatch generation as economically as possible” and said that SPP studies have shown there is room for “further optimization” in the markets through “further reduction of self-commitments.”
MISO conducted a study on multi-day commitments in 2017 that showed “significantly lower production cost savings” than Sierra Club’s report, spokesperson Julie Munsell said. “MISO’s generation owners and operators are in the best position to know all of the factors and requirements to optimize the reliable and efficient operation of their assets,” Munsell said.
The Union of Concerned Scientists says that if MISO economically dispatched all its generation, average LMPs would rise 3%. MISO says its own study of self-commitments showed a “significantly lower production cost savings.” | Union of Concerned Scientists
PJM spokesman Jeff Shields did not comment on the Sierra Club report but acknowledged that although units that self-commit on their own can’t set LMPs, they do change the offer stack “and can ultimately impact what the marginal unit may be.”
Self-committing units that provide an operating range and offer curve and allow PJM to dispatch them are eligible to set prices. PJM doesn’t assess “outright” penalties, but self-scheduled units are subject to operating reserve deviation charges, Shields said.
PJM Independent Market Monitor Joe Bowring said the Monitor’s analysis of coal plants at risk of retirement — which it defines as units for which the forward-looking net revenue from PJM markets does not cover going-forward costs — “does not support the conclusion that regulated units are uneconomic in PJM.”
“We think the UCS analysis is insightful, and we are continuing to develop more detailed analysis of self-scheduling practices in PJM using unit-specific, confidential data not available to UCS,” Bowring said.
Regulatory Recovery
UCS and Sierra Club say that by running the plants out of merit when their production costs are greater than wholesale market prices, utilities can recover fuel and operations and maintenance costs through regulatory proceedings. Sierra Club said its study estimated coal plants with negative revenue lost more than $3.8 billion in 2015-2017 when accounting for fixed O&M costs and revenues from MISO’s and PJM’s capacity markets. State ratemaking likely makes the utilities whole for their losses, Sierra Club said.
Annie Levenson-Falk, executive director for the Minnesota Citizens Utility Board, noted that the UCS study indicates that the state’s two largest entities — Xcel Energy’s Northern States Power and ALLETE’s Minnesota Power — could have realized $85 million to $90 million in gross savings had their coal units been dispatched economically.
“Those are substantial numbers, and it raises concerns for us,” Levenson-Falk said during the NARUC session. “Clearly, this is a problem in the way the plants are operating. In Minnesota, we’re moving quickly to a much higher level of renewable power. You talk about not just generating to meet load, but scheduling variability.”
FERC Commissioner Richard Glick, seated next to Levenson-Falk, was asked whether it was time for the federal commission to get involved.
“This is primarily, at this point, a matter for the state[s],” he said. “Certainly, we’re looking at it. It potentially could have a significant impact on the transparency in the markets we regulate and the price signals to market entry.”
“We can agree and disagree on whether it’s a state issue. I think it’s a game of hot potato,” said Indiana Utility Regulatory Commissioner Sarah Freeman, drawing a wry smile from Glick.
State Investigations
Minnesota and Missouri regulators have picked up the potato by opening investigations into self-commitment. Minnesota Public Utilities Commissioner Matt Schuerger said his commission opened the proceeding as an information-gathering process.
“I do think there are legitimate reasons for self-committing and scheduling, but things can be done better to save customers money,” he said.
Schuerger said the PUC also has potential questions around the reliability unit commitment (RUC) process. “ISOs like MISO have built their reliability commitment process on a large chunk [of generation] coming in at self-commitment,” he said.
“When I got to FERC, I thought I knew about markets,” Glick said last month. “The general notion is you bid in at marginal costs. The ones that bid in the lowest get what they’re needing. Where people aren’t bidding in at the marginal cost, sometimes they’re being told they’re not bidding high enough.
“A significant part of some of these markets, especially MISO and SPP, are not having a truly functional market. That raises a broader question of whether markets are functioning well and sending the right price signals.”
Ted Thomas, chair of the Arkansas Public Service Commission, suggested market monitors might be the right people to look at self-commitment practices.
“This is like the tip of an iceberg of a very big issue all markets will have to deal with,” he said.
SPP MMU IDs Problem
Indeed, SPP’s Market Monitoring Unit called self-commitment a problem two years ago and has been focused on the issue ever since. Its 2016 State of the Market report jived with a 2017 Sierra Club study that found SPP utilities with coal plants generated $300 million in excess costs in 2015 and 2016, costs that consumers picked up. (See Report: Costly Coal Undermining SPP Market, Bilking Consumers.)
The MMU is planning to release its own report on self-commitment within SPP in the next two weeks. Executive Director Keith Collins on Monday said the study results are “directionally” similar to Sierra Club’s latest report, but at a lesser magnitude. The MMU study found only about a 7% increase in costs when units were economically dispatched, as compared to the Sierra Club’s 30% figure.
Collins said the MMU used a day-ahead model in running its study, using historic bids and offers for additional granularity.
“The Sierra Club talks about more advanced forward markets that send a clear commitment signal. We, in our analysis, found that that is potentially a key factor in the analysis,” he said. “Our study found that if you made no change to the market and you just told resources to participate in the market, not only do you increase prices, you increase production costs. When you add a second day to the optimization, you effectively get the benefits of reduced production costs and you do get the increase in price. With a second day … you can capture most of the benefits of addressing the lead-time resources you see self-committing in the market.”
Recommendations
The Sierra Club report suggests commissioners examine the utilities’ market self-commitment and self-scheduling practices through investigations, expanded fuel or rate-case dockets, or during resource-planning reviews. The group also urges regulators to consider disallowing operational costs in excess of market necessity.
Thomas and Freeman last month responded with their own suggestions.
“Meet analysis with analysis … but determine what is going on operationally,” Thomas said. “There are formal and informal things we can do. There are suggestions, and there are carrots and sticks. My normal approach is to start with informal suggestions, because that’s easy, and proceed until the normal collision.”
Freeman argued against what she called adversarial proceedings. She invoked the name of noted regulatory attorney Scott Hempling, who she said preaches aligning interests, as opposed to balancing them.
“If ever there was an issue ripe for aligning interest, this is one of them,” she said. “Everyone wants to achieve those really favorable economic numbers that Joe has shown.”
The U.S. Senate on Monday voted 70-15 to confirm Dan Brouillette as secretary of energy.
Brouillette spent most of the day as acting secretary, after Rick Perry resigned on Sunday. Prior to that he had served as deputy secretary since August 2017, when the Senate confirmed him 79-17.
His confirmation was expected. He enjoyed mostly bipartisan support at his nomination hearing last month before the Senate Energy and Natural Resources Committee, which quickly moved to advance him to the floor by a 16-4 vote. (See Danly, Brouillette Advance to Senate Floor.)
The Senate on Nov. 21 voted 74-18 to invoke cloture on Brouillette’s nomination just before it adjourned for the month, setting up Monday’s vote.
The Senate confirms Dan Brouillette as secretary of energy Dec. 2.
Shortly before the vote, Sen. Ron Wyden (D-Ore.) called for a delay on Brouillette’s confirmation until the Senate received more information about Perry’s role in U.S.-Ukrainian relations, central to the House of Representatives’ inquiry into impeaching President Trump.
Wyden cited the fact that Perry had traveled to Ukraine in May for the inauguration of President Volodymyr Zelenskiy and provided him with a list of suggestions for the supervisory board of Naftogaz, the country’s state-owned energy company. The Associated Press reported that two of Perry’s political supporters secured a potentially lucrative oil and gas exploration deal from the Ukrainian government soon after the inauguration, and that one of them, Michael Bleyzer, was on Perry’s list.
Bill Taylor, the acting U.S. ambassador to Ukraine, testified to the House last month that Perry — along with U.S. Ambassador to the E.U. Gordon Sondland and Kurt Volker, special U.S. envoy to Ukraine — ran a “highly irregular” channel of U.S. policymaking toward Ukraine. Perry has refused to testify before the House. At his ENR Committee hearing, Brouillette said he had no knowledge of any conversations Perry might have had with Ukrainian officials about the matters the House is investigating. (See Brouillette Poised to Become Energy Secretary.)
Wyden noted that Brouillette is already serving as acting secretary. “Western civilization is not going to end if the Senate insists on getting some answers to the questions I’ve presented this afternoon,” he said.
Sen. Joe Manchin (D-W.Va.), ranking member of the ENR Committee, spoke in support of Brouillette. “I know some of my dear colleagues have some concerns about questions they want answered,” he said. “I did get some of those from him. He assured me his answers were accurate and correct.”
Record low energy prices persisted for the first nine months of the year in PJM, and so too did rumblings from legacy generators losing money over it.
But the loud grievances of some shouldn’t outweigh the benefits to the many, the Independent Market Monitor said in its quarterly State of the Market report, urging stakeholders to be wary of sweeping changes to the markets.
“There is no reason to overturn the key components of the PJM capacity and energy markets,” the Monitor wrote in its report, published Nov. 14. “There is no reason to create convoluted capacity market rules to exclude any competitive offer from any technology including renewable and nuclear technologies. There is no reason to artificially increase energy prices to benefit nuclear and coal plants.”
The sentiments echo the Monitor’s warning in August that PJM’s markets “remain under attack” from those who think its outcomes shortchange them. (See Monitor: PJM Markets Remain Under Attack.)
PJM’s footprint and its 21 control zones | Monitoring Analytics
Instead, the Monitor said, stakeholders should focus on the “refinement of market rules” to “ensure the continued effectiveness of PJM markets in providing customers wholesale power at the lowest possible price, but no lower.”
The Monitor also said that a market-based carbon price — such as that of the Regional Greenhouse Gas Initiative — would serve PJM better than unit-specific subsidies or “inconsistent” renewable portfolio standard rules.
“Implementation of a carbon price using RGGI or a similar market mechanism by the states would mean that the states control the carbon price and that no FERC approval would be required and no PJM rule changes would be required,” the Monitor said. “The carbon price would become part of the marginal costs of power plants, and the impacts on production and consumption decisions would be market based. States would control the resulting revenues. This is the case regardless of the number of PJM states that join RGGI or a similar market.”
In the interim, natural gas plants will continue displacing coal-fired resources, and some nuclear units will lose money while sellers’ efforts to artificially control those elements will keep PJM’s capacity market uncompetitive, the Monitor said.
“The fact that some plants are uneconomic does not call into question the fundamentals of PJM markets. Many generating plants have retired in PJM since the introduction of markets, and many generating plants have been built since the introduction of markets. The level of potential retirements of coal and nuclear units does not imply a reliability issue in PJM and does not imply a fuel security issue in PJM.”
Energy Prices, Congestion Trending Down
Energy prices dropped 30% compared with the same time frame a year earlier, and congestion decreased by two-thirds, the Monitor said.
LMPs dipped from $39.43/MWh in the first nine months of 2018 to $27.60/MWh through September. Lower fuel costs contributed to nearly half the decline, the Monitor said.
As a result of the record low prices, many generators — including FirstEnergy Solutions’ two Ohio nuclear plants — won’t recover costs. (See related story, Ohio Supreme Court Dismisses FES Nuke Lawsuit.) The Monitor’s analysis concludes that average energy market net revenues decreased by 52% for new combustion turbine units; 32% for combined cycle; 82% for new coal plants; 32% for a new nuclear plant; 74% for a new diesel units; 29% for a new onshore or offshore wind installation; and 19% for a new solar installation.
New Recommendations
The Monitor’s highest priorities center around ensuring effective market power mitigation and updates to PJM’s real-time security-constrained economic dispatch (RT SCED) methodology, which stakeholders are exploring through a special session of the Market Implementation Committee. (See “5-Minute Dispatch and Pricing,” PJM MIC Briefs: July 10, 2019.)
To address market power issues, the Monitor said PJM should commit units based only on their parameter-limited schedules when the three-pivotal-supplier test is failed or during high-load conditions, such as cold- and hot-weather alerts or more severe emergencies.
PJM should also approve one RT SCED case for each five-minute interval to send dispatch signals and calculate prices using the same approved SCED case.
PJM should model generators’ operating transitions and peak operating modes.
PJM should revert to the method for the calculation of implicit balancing congestion charges used prior to April 1, 2018.
Fleetwide cost-of-service rates used to compensate resources for reactive capability should be eliminated and replaced with compensation based on unit-specific costs.
The market efficiency process used to calculate the cost-benefit ratio of reliability-based regional transmission expansion projects should be eliminated because it is not consistent with a competitive market design.
The Ohio Supreme Court last week rejected FirstEnergy Solutions’ attempt to block a referendum to repeal $150 million in subsidies for its two nuclear plants.
Four of the court’s seven judges dismissed FES’ lawsuit, citing a “lack of justifiable controversy.” While the court documents offer no further elaboration, the referendum effort against FES’ plant subsidies failed in October, and its future — including whether petitioners will get extra time to gather the necessary signatures for inclusion on the November ballot — pends before the same court.
“The decision by the Ohio Supreme Court is a victory for Ohio’s electric customers and recognizes the attempted referendum on HB 6 is over,” Tom Becker, an FES spokesperson, said in email to RTO Insider on Monday. “Those opposed to the bill were unable to gather the requisite number of signatures to initiate a referendum; therefore there is no longer a need for the court to rule on the case.”
Ohioans Against Corporate Bailouts began a campaign against Ohio’s House Bill 6 the same day Gov. Mike DeWine signed the legislation in July. In October, however, the group said it fell nearly 45,000 signatures short of the count necessary for the referendum’s inclusion on the 2020 ballot.
Perry Nuclear Power Plant, located about 40 miles northwest of Cleveland | FirstEnergy
In its lawsuit, FES argued the new ratepayer fees collected for its nuclear plants — ranging from 80 cents to $2,400/month — are equal to a tax, making the underlying legislation ineligible for the petition that the group was circulating for a ballot referendum. The lawsuit named both the group and Secretary of State Frank LaRose, the state’s chief election official, as defendants. (See FirstEnergy Challenges Nuke Vote in Ohio Supreme Court.)
Gene Pierce, spokesperson for Ohioans Against Corporate Bailouts, had a different interpretation of the last week’s ruling.
“The Ohio Supreme Court decision correctly rejected FirstEnergy Solutions’ argument that HB 6’s billion-dollar bailout is not subject to referendum, one of many desperate and greedy FES maneuvers trying to deny Ohioans’ right to vote on bad legislation,” Pierce told RTO Insider in an email. “The argument was ridiculed from the first time it was aired in public, and this legal proceeding was a waste of the Ohio Supreme Court’s time and taxpayers’ money.”
Pierce’s group had asked a federal court to issue a preliminary injunction against HB 6, claiming 38 days of its 90-day allowance to collect signatures were wasted in a “blackout period” during which it sought the attorney general’s approval of the petition’s language before circulation could begin. The suit, filed in the U.S. District Court for the Southern District of Ohio in October, also alleged a well-funded opposition used illicit tactics to undermine its effort.
But Judge Edmund A. Sargus Jr. denied the group’s request later that same month, saying only the state Supreme Court can determine whether state law thwarted the group’s ballot petition — a review the panel has not yet indicated whether it will undertake. (See Federal Court Denies Nuke Petition Extension.) Attorneys for the group appealed Sargus’ ruling Nov. 22.
MISO may have to devise new lines of communication, rethink its data management and alter dispatch rules to give distributed energy resources access to its markets.
Those opinions were laid out at a special Nov. 26 workshop focusing on DER assets’ communication and visibility to the MISO control room.
DER Program Manager Kristin Swenson said the RTO may have to develop new means of communication to provide visibility into distributed resources in the footprint.
“We’ve been pretty locked into this [Inter-Control Center Communications Protocol] world,” she said, referring to the predominant system of real-time data exchange for RTOs and ISOs. “There are a lot of other communication options.” She added that MISO will have to ensure the cybersecurity of communication with DERs and aggregators.
Wisconsin Public Service Commission policy analyst Ryan Kohler, who also participates in the Organization of MISO States, said collecting DER insights is particularly challenging considering that no standardized DER data policy exists across states or RTO/ISOs.
“There’s a cost to this; there’s a question of how all these [data-gathering methods] are going to work together,” Kohler said. “As penetration levels increase, it’s going to be essential that we know what’s going on.”
Kohler said DER operators are going to have to predict their resources’ behavior, be able to react in real time, and maintain forecasts for and historical data of their resources.
“It does take a specialist to get information like this. … So we’re putting the call out. It’s going to take a lot of folks with the same knowledge,” Swenson said, asking that MISO’s utilities make sure their representatives at DER workshops specialize in DER operations.
MISO control room | MISO
Kohler also said the question remains about what data DER operators need to share with RTO/ISOs in order for them to be able to respond to dispatch instructions.
Advanced Energy Management Alliance Executive Director Katherine Hamilton said aggregators will help DERs meet ISO/RTO dispatch instructions and facilitate communication.
Swenson said that while MISO currently receives real-time load information, it receives no detailed or real-time information directly from devices or aggregations.
“We’re interested in how that evolution will affect us,” she said, adding that MISO is asking how much data it can realistically handle without being overwhelmed.
Answer in Aggregate?
Aggregator Enel X North America’s Nicholas Papanastassiou said his company already offers virtual power plants with market optimization engines that crunch weather data, site-specific costs and price forecasts to update market offers to RTOs. He said virtual power plants provide services that are “beyond simple telemetry.”
“Many other industry players have similar forms of this,” he told MISO staff and stakeholders.
Papanastassiou said it’s best if DERs are allowed to participate both in the retail and wholesale markets as much as possible, though he allowed that some issues might arise if DERs are held to an RTO’s must-offer requirement when they planned on not being available.
MISO Managing Assistant General Counsel Michael Kessler said the RTO’s must-offer requirement applies to capacity resources. Currently, MISO resources are barred from providing capacity if they also furnish output to areas outside the RTO.
Kessler said MISO hasn’t yet examined how a DER would become a capacity resource.
“We’re going to have to explore how these dual participations will line up with essential reliability services,” Kessler said.
Voltus CEO Gregg Dixon said the issue isn’t technology and metering, but dual rulesets from the states and RTOs.
“This isn’t rocket science,” he said of the technology involved for metering. He added that states should invite aggregated DERs into the wholesale market, where the states can benefit from both wholesale market resource adequacy credit and their DERs handling local needs.
“States sign up for the socialized benefits of a wholesale market. Yet, states don’t take full advantage of the benefits,” Dixon said.
MISO said its “key” future issue is aggregation. The RTO currently doesn’t allow aggregation beyond its pricing nodes or local balancing authorities, depending on how demand response resources have registered. And so far, only MISO’s Type II DR resources are eligible for dispatch, but they must be at least 1 MW in size.
Market design engineer Congcong Wang said a large aggregation across multiple transmission and distribution interfaces would affect transmission flow calculations, the RTO’s congestion management and create locational pricing inaccuracies.
Mission:data President Michael Murray predicted that MISO will end up using “hybrids” of metering and data-gathering practices, given its large footprint of different state jurisdictions and utility models. He said it was difficult to imagine the RTO imposing just one metering type. Mission:data is a 35-member nonprofit that encourages customer data access policies across the country.
“A lot of these utilities are becoming IT platforms, and they need to be regulated like IT platforms,” Murray said, adding that states might consider designating centralized repositories for information.
“We’re all kind of dealing with this new frontier of working together,” Minnesota Public Utilities Commission DER specialist Michelle Rosier said.
The DER workshop was one of several MISO has hosted over 2018 and 2019, with plans to host more in 2020.
Swenson said MISO’s next DER workshop on Feb. 25 will focus on how the resources will impact the current transmission planning process.
“Because of the changes we’ve seen to the distribution system … our planning horizons may take too long. They’re very, very long,” Swenson said.
MISO also plans to hold another workshop in March on how DERs might contribute to its markets in the future.
