Page 1206 – RTO Insider

January 13, 2020

FERC Rejects Mystic Cost-of-service Amendment

By Michael Kuser

FERC on Thursday rejected Constellation Mystic Power’s request to allow it or ISO-NE the option to terminate the second year of its two-year cost-of-service agreement to keep Mystic Units 8 and 9 in operation until May 31, 2024 (ER19-1164).

The commission in December 2018 approved the agreement, which ISO-NE sought to prevent plant owner Exelon from retiring the 2,274-MW plant when its capacity supply obligations expire in May 2022. (See FERC Approves Mystic Cost-of-Service Agreement.)

Mystic said it sought to amend the agreement because matters pending before FERC left it uncertain about recovering its investment in assets related to the operations of its on-site Everett LNG terminal — formerly known as Distrigas — during the term of the agreement.

The proposed amendment would have allowed ISO-NE to terminate the agreement on May 31, 2023 — after the first year of the agreement — while permitting Mystic to end the agreement on the same date after giving the RTO notice by Friday.

FERC Mystic Generating Station — Exelon’s Mystic Generating Station, on the Mystic River in Everett, Mass. A wind turbine owned by the local water authority to power a pumping station is on the right.

Protesters argued the termination provision would give Mystic the unilateral right to end the agreement even if ISO-NE determined that the units are still needed for fuel security purposes for Forward Capacity Auction 14, which covers the second year. They contended that termination would allow Mystic to renegotiate the terms of a commission-accepted agreement and exert market power by threatening to withdraw the units from service.

Mystic countered that those concerns would be addressed by ISO-NE’s future fuel security market mechanisms and a clawback provision in the agreement.

In rejecting the amendment, FERC recounted that it had pushed back the deadline for Exelon to submit its retirement decision for Units 8 and 9 for FCA 13 from July 6, 2018, to Jan. 4, 2019 — one month before the auction. In response to Mystic’s early delist bids in 2018, ISO-NE had studied the impact of retiring the units and determined that their loss would present an unacceptable fuel security risk, it said.

The commission noted ISO-NE sought to avoid potential load shedding and violation of NERC reliability standards that the RTO’s modeling showed would occur if Units 8 and 9 were to retire. Based on this modeling, the commission opened an investigation under Federal Power Act Section 206 that pushed ISO-NE to begin to address the reliability threat posed by the region’s fuel security challenges. Because the RTO’s modeling showed a need to retain Units 8 and 9 for a two-year period, it proposed Tariff provisions for a two-year term.

The commission said that although several components of the agreement have yet to be finalized, “we find that this uncertainty has not changed substantially from the time that Mystic executed the [agreement] for a two-year term.”

Commissioner Richard Glick concurred in part and dissented in part.

“As protesters explained, granting Mystic’s request to add a unilateral termination provision to its cost-of-service agreement would give Mystic another opportunity to extract every last penny from the region’s customers without any countervailing benefit,” Glick said. “Given that customers are already on the hook for Mystic’s full cost-of-service, I do not see how adding a ‘heads I win, tails you lose’ provision to the agreement would be a just and reasonable result.”

Glick agreed with the commission’s conclusion but said it mistakenly repeats its belief that Mystic is needed for fuel security and, therefore, cannot be allowed to back out of its cost-of-service agreement.

“Because I do not share that belief, I dissent from the portions of today’s order that rely on that rationale to support the outcome,” Glick said. “Instead, I would reject Mystic’s proposed amendment on the basis of its potential to further harm the region’s customers.”

Fuel Cost Violation

In a separate order Friday, the commission approved a consent agreement requiring Exelon to pay a civil penalty of $32,500, disgorgement of $101,156 and interest of $15,324 for an error that resulted in Mystic Unit 7 being overcompensated in some cases (IN20-3).

The unit can run on either natural gas or No. 6 fuel oil and requires a blend of both to start up. But beginning in December 2014, Unit 7’s supply offers said the generator used fuel oil only to start up, the result of an error in an internal spreadsheet, FERC said.

As a result, the unit was overcompensated when it was not dispatched economically but then was called on by ISO-NE to operate for reliability, FERC said.

The error was not recognized until August 2016, when the ISO-NE Internal Market Monitor began an investigation of the unit’s fuel use.

FERC said Exelon corrected the problem after the Monitor’s inquiry and cooperated with the subsequent investigation by the commission’s Office of Enforcement.

January 13, 2020March 23, 2026

Trump Admin Proposes Streamlining NEPA Reviews

By Michael Brooks

President Trump’s Council on Environmental Quality last week proposed easing environmental regulations on infrastructure projects, calling for tighter deadlines and more formal agency cooperation in the federal government’s project reviews.

The Notice of Proposed Rulemaking, published Friday in the Federal Register, is intended to speed up the National Environmental Policy Act review process, which Trump called “outrageously slow and burdensome” and a “regulatory nightmare.”

“It takes many, many years to get something built,” Trump said Thursday at a White House press conference announcing the proposal, dubbed the “One Federal Rule.”

“The builders are not happy. Nobody is happy. It takes 20 years. It takes 30 years. It takes numbers that nobody would even believe.”

NEPA requires that federal agencies, including FERC, prepare environmental assessments (EAs) before taking any “major action,” including approving proposed infrastructure projects under their jurisdiction. If an agency finds that a project as proposed would produce significant impacts to the environment, it must then produce an environmental impact statement (EIS), which includes suggested changes that would lessen those impacts. FERC, for example, can call for alternative routes for proposed natural gas and oil pipelines.

Trump NEPA — President Trump announces CEQ’s proposed updates to NEPA implementation in the Roosevelt Room of the White House on Jan. 9. | *The White House*

CEQ’s proposed rules would narrow what classifies as a “major federal action” to “make clear that this term does not include non-federal projects with minimal federal funding or minimal federal involvement such that the agency cannot control the outcome on the project.”

The new rules would give agencies one year to complete EAs and two years for EISes.

“The Council on Environmental Quality has found that the average time for federal agencies to complete environmental impact statements is four and a half years,” Chairwoman Mary Neumayr said at the press conference. “Further, for highway projects, it takes over seven years on average, and many projects have taken a decade or more to complete the environmental review process. These delays deprive hardworking Americans of the benefits of modernized roads and bridges that allow them to more safely and quickly get to work and get home to their families.”

NEPA stipulates that a “lead agency” is responsible for conducting the environmental review process on projects subject to multiple agencies’ approval, but the law and CEQ’s regulations are unclear regarding what the responsibilities of the lead agency are. The proposal would clarify “that the lead agency is responsible for determining the purpose and need and alternatives in consultation with any cooperating agencies. … Cooperating agencies should give deference to the lead agency and identify any substantive concerns early in the process to ensure swift resolution.”

“Today’s proposal would empower lead agencies to make executive decisions when more than one agency is involved in the process and will streamline the permitting process without compromising environmental protections,” EPA Administrator Andrew Wheeler told reporters.

Cumulative Impacts

Disagreements over FERC’s responsibilities under NEPA have been a source of partisan tension between commissioners, which former Commissioner Cheryl LaFleur said affected their work on other dockets. (See FERC’s ‘Rifts’ Only Widened in 2019.) The disagreement stems from the Republican commissioners’ May 2018 decision to no longer include estimates of greenhouse gas emissions in the commission’s NEPA assessments.

CEQ’s proposal, if upheld, would negate this debate. “CEQ proposes to strike the definition of cumulative impacts and strike the terms ‘direct’ and ‘indirect’ in order to focus agency time and resources on considering whether an effect is caused by the proposed action rather than on categorizing the type of effect,” according to the proposal. “CEQ’s proposed revisions to simplify the definition are intended to focus agencies on consideration of effects that are reasonably foreseeable and have a reasonably close causal relationship to the proposed action. In practice, substantial resources have been devoted to categorizing effects as direct, indirect and cumulative, which … are not terms referenced in the NEPA statute.”

The proposal does not give any specific guidance on how agencies should consider emissions in their reviews. That’s because, according to CEQ, it “does not consider it appropriate to address a single category of impacts in the regulations.”

Environmentalists have argued that “indirect effects” include a project’s effect on climate change, leading to courts ruling that projects’ GHG emissions, including carbon dioxide, be considered in agencies’ NEPA reviews. But the proposal says that “effects should not be considered significant if they are remote in time, geographically remote or the product of a lengthy causal chain. Effects do not include effects that the agency has no ability to prevent due to its limited statutory authority or would occur regardless of the proposed action.”

CEQ also noted that it issued a draft rule in June that would guide agencies in their consideration of emissions. It’s unclear, however, how this new rule would affect the June draft, which contains references to the “direct” and “indirect” impacts of emissions.

Comments are due March 10. CEQ will hold public hearings on the proposal at EPA Region 8 headquarters in Denver on Feb. 11 and at the Interior Department in D.C. on Feb. 25.

Reaction

Predictably, Democrats and environmentalists blasted the NEPA proposal, while Republicans and industry celebrated it.

“The lack of clarity in the existing NEPA regulations has led courts to fill the gaps, spurring costly litigation, and has led to unclear expectations, which has caused significant and unnecessary delays for infrastructure projects across the country,” said Don Santa, CEO of the Interstate Natural Gas Association of America. “The Council on Environmental Quality’s proposed rule is an important step in restoring the intent of NEPA by ensuring that federal agencies focus their attention on significant impacts to the environment that are relevant to their decision-making authorities.”

“For the past 50 years, NEPA has been an essential part of the public process, providing critical oversight that the federal government relies on to fully understand the potential implications of projects that can harm people’s health and the environment,” said Gina McCarthy, CEO of the Natural Resources Defense Council and former EPA administrator. “We will use every tool in our toolbox to stop this dangerous move and safeguard our children’s future.”

“While I am still reviewing the details of this proposal, antiquated federal regulations often stand in the way of critical infrastructure and other important projects that can create jobs, improve our standard of living and energy security, and yet still fully protect the environment,” said Sen. Lisa Murkowski (R-Alaska), chair of the Senate Energy and Natural Resources Committee. “The president and his advisers deserve credit for leading the charge to bring our 1970s-era permitting processes into the 21st century.”

“Much, though not all, of what is being proposed is positive,” the Bipartisan Policy Center said in a statement. “Efforts to increase the clarity of process, curtail uncertainty and diminish conflicts among agencies that contribute to delays are welcome improvements.

“The rule also contains some overreaches that are unnecessary and will extend the very litigation the rule is designed to diminish,” the BPC added. “Unfortunately, the administration’s constructive proposals are being colored by its irresponsible position on climate change.”

During the 2016 presidential election, Trump called climate change a hoax perpetrated by China. On Thursday, however, when asked by a reporter if he still thought that, he backed away.

“No, no, not at all. Nothing is a hoax. Nothing is a hoax about that,” the president said. “It’s a very serious subject. I want clean air. I want clear water. I want the cleanest air with the cleanest water.” He then noted a 2016 book that heralded him as an “environmental hero.”

January 13, 2020

MISO Market Subcommittee Briefs: Jan. 8, 2020

CARMEL, Ind. — MISO will revisit its Tariff to better define how aggregators of retail customers (ARCs) participate as demand resources as more aggregators line up for market participation.

FERC in 2012 approved MISO’s ARC participation model, which lays out how end-use customer groups can offer demand response into the markets aggregated at the load-serving entity level. Rules found in Module C of the Tariff lay out aggregator registration, creation of a commercial pricing node, certification of each retail customer and the RTO’s communication of the volume of DR cleared in the day-ahead market.

“For quite a long time, we didn’t have a lot of participation, but in the last few years, we’ve had significant ramp-up,” MISO Principal Adviser of Market Design Mike Robinson told stakeholders at a Market Subcommittee meeting Wednesday.

Robinson said MISO should clarify what information ARCs need for registration and what responsibilities are required of ARCs, LSEs, relevant regulatory authorities, local balancing authorities and MISO. He also said the RTO needs a better process to avoid the double-counting of aggregated DR assets and should make clearer ARCs’ requirements around metering and settlement.

MISO also must establish a clearer timeline for ARC notifications approval deadlines, Robinson said, adding that it would reorganize the ARC section in Module C so it describes participation cohesively, from registration to settlement.

Through the edits, MISO will ensure there’s no “unfair or artificial barriers to participation” imposed on ARCs, Robinson said. He said it will especially focus on the registration process, which has been criticized as confusing by some members.

MISO is accepting stakeholder opinions on the Tariff edits through Jan. 22. Robinson said he would return to the MSC in February to discuss proposed changes.

Monitor Examining SPP’s Fall Transfer Derate

Independent Market Monitor David Patton said he continues to investigate SPP’s November request to reduce flows on the contract transmission path between MISO’s Midwest and South regions.

During a quarterly market recap, the Monitor repeated concerns about the request that MISO cut its regional dispatch transfer (RDT) limit flows to 1,500 MW on an unusually cold Nov. 13 — a move that cost the RTO an additional $876,383 in congestion that day. (See “Tricky Mid-November,” MISO Avoids Fall Emergencies.)

“It was relatively expensive for MISO to derate the [RDT limit], and we don’t have all the answers yet,” Patton told stakeholders. “Communications are continuing with SPP on this event.”

Patton said SPP should have made some sort of intermediate move, including requesting unit redispatch or transmission loading relief, before calling for a transfer limit derate.

Stakeholders asked if the Monitor was investigating compliance violations on SPP’s part.

“I think they are allowed to ask for a [derate],” Patton responded. “I think if there’s a compliance issue it may be not providing proper justification for the derate request. But that’s a minor point, I think, in comparison to the larger concern that it’s an expensive action and there are a number of better options that are less costly.”

Patton said SPP may lack incentive to provide “more surgical solutions” rather than what he described as the “blunt instrument” and “sledgehammer” of cutting flows on the regional dispatch transfer.

“Clearly SPP isn’t going to have to pay this bill to derate the RDT,” Patton said.

Stakeholders asked why MISO simply didn’t cut its non-firm exports into the Southern Co. territory at the time to avoid straining the transfer limit. Patton said cutting exports pre-emptively could have created a bigger problem for Southern, which was also struggling to furnish adequate supply in the cold.

“This gets into the nebulous area of what you do pre-contingency versus what you do post-contingency,” he added.

— Amanda Durish Cook

January 12, 2020

Newsom Budget Reiterates PG&E Takeover Threat

By Hudson Sangree

SACRAMENTO, Calif. — Gov. Gavin Newsom released an outline of his proposed 2020-2021 budget Friday that included language reiterating his threat to take over Pacific Gas and Electric should the utility fall short of the requirements of Assembly Bill 1054, a landmark measure he signed in July.

“We’ve decided to put it in the budget so there’s no ambiguity,” Newsom told a packed briefing room of reporters at the State Capitol. “We have a break-the-glass scenario. If we have a utility — an investor-owned utility, in this case PG&E — that does not meet the mandates set forth in 1054 … then the state will have no choice but to be in a position to take over that utility in order create a framework for safe, affordable, reliable service for the state of California.”

The governor’s January budget proposal is an outline that will get fleshed out in the coming months, prior to the traditional “May revise” that the State Legislature acts upon. It did not include specific figures for any PG&E takeover, though the potential amount would likely be tens of billions of dollars.

Newsom Budget — California Gov. Gavin Newsom presented his annual budget proposal at the State Capitol on Friday. | © *RTO Insider*

The company’s market capitalization now is $5.4 billion, but some think it is undervalued considering its assets, including 106,681 circuit miles of electric distribution lines and 18,466 circuit miles of transmission. PG&E stock, which closed Friday at $10.20/share, was as high as $70/share before the fires of Oct. 2017. PG&E’s territory encompasses 70,000 square miles of Northern and Central California.

Whether the state would truly want to assume the responsibility for PG&E’s aging transmission and distribution systems remains in doubt. The legislature would need to appropriate the money for any takeover and, under AB 1054, the Public Utilities Commission would need to approve the transfer of utility assets. And some critics have questioned whether Newsom would seek to follow through on his threat or is merely seeking to score political points now that the utility has become so unpopular.

$700,000 in Support

A Washington Post investigation in November found Newsom and his wife had accepted more than $700,000 from PG&E, its foundation and employees during his political career as mayor of San Francisco, lieutenant governor and governor. The utility and its employees helped fund Newsom’s political campaigns, ballot initiatives and inauguration festivities while also supporting his wife’s foundation and film projects.

Newsom told reporters Friday he wasn’t grandstanding.

“Make no mistake that I included it in the budget because I’m serious about it,” the governor said Friday. “And if you think it was just words on paper, I can assure you … my time off during the holidays was time [spent] on this issue, focused on what that [takeover] would look like [and] what it would not look like, including a potential legislative play in the short term.”

PG&E: On Track to Exit Bankruptcy

PG&E had no immediate reply Friday to Newsom’s comments. But the company assured a gathering of investors late last week that it was on track to exit Chapter 11 bankruptcy by the end of June, as AB 1054 requires, allowing PG&E to participate in a $21 billion wildfire insurance fund established by the state.

In a presentation to the Evercore ISI Utility Conference on Thursday and Friday, PG&E said it was on the “path to [an] expeditious Chapter 11 exit through the fair settlement of wildfire claims and pending regulatory proceedings, progress with legislative initiatives, and establishment of a multiyear investment and rate roadmap.”

In particular, the utility noted it had settled with three core groups that filed claims from the massive wildfires of 2017 and 2018 ignited by PG&E equipment. Fire victims have agreed to accept $13.5 billion in cash and stock, while insurers and other holders of subrogation claims had agreed to an $11 million all-cash settlement. Counties, cities and other local government entities had accepted a $1 billion settlement. (See Judge OKs PG&E Deals with Fire Victims, Insurers.)

PG&E’s restructuring plan must still be confirmed by the U.S. Bankruptcy Court in San Francisco and approved by the CPUC. AB 1054 requires the commission to find that the plan and the “electrical corporation’s resulting governance structure … [is] acceptable in light of the electrical corporation’s safety history, criminal probation, recent financial condition and other factors deemed relevant by the commission.”

PG&E is on criminal probation after being convicted in federal court of six felonies stemming from the September 2010 San Bruno gas pipeline explosion, which killed eight people in a suburban neighborhood. State fire investigators found its equipment failures responsible for a series of fires in Northern California wine country in October 2017 and for the Camp Fire, the state’s deadliest and most destructive wildfire, which killed 86 people and leveled the town of Paradise in November 2018.

Calls for a public takeover of all or part of PG&E’s system have escalated. San Francisco offered PG&E $2.5 billion for its assets there. The utility rejected the offer, but San Francisco leaders say they haven’t given up. An effort led by San Jose Mayor Sam Liccardo continues to gain supporters among cities and counties. (See Pressure Grows for Public Takeover of PG&E.)

The governor said Friday he has remained in personal contact with Liccardo and others regarding their efforts.

‘Escalating Enforcement Process’

Newsom’s budget summary said that “after PG&E’s decades of mismanagement and neglect of its critical infrastructure, failed efforts to improve its safety culture, and its disruptive implementation of public safety power shutoffs, the company that emerges from bankruptcy must be poised for transformation as required by AB 1054. The budget reflects necessary support for the administration’s efforts to achieve the required transformation of PG&E within the bankruptcy process.”

“However, if protecting Californians’ interests and ensuring the necessary transformation requires further intervention, including a state takeover of the utility, the administration will work with the legislature to secure necessary statutory changes, appropriations to support transactional and planning costs, and liquidity measures. Consistent with the administration’s commitment to maintain a balanced budget and strong fiscal resiliency, any such action would be carefully structured in a manner that safeguards the state’s general fund.”

Newsom’s statements built on his discussion of a possible public restructuring of the state’s largest utility in November, when the governor said his backup plan for PG&E’s future consisted of reorganizing it, possibly with an “ISO-like structure” akin to California Could Restructure PG&E, Governor Says.)

In December, Newsom wrote a letter to CEO Bill Johnson, saying PG&E’s restructuring plan fell short of his expectations. He called for PG&E Corp. and its utility subsidiary to have more directors from California and for its reorganization plan to provide for an easier means to a state takeover, should it become necessary.

The letter, which Newsom filed with U.S. Bankruptcy Judge Dennis Montali, also called for “strict, clearly defined operational and safety metrics to which the reorganized company will be held accountable” and an “escalating enforcement process that provides for greater oversight of the reorganized company.”

January 12, 2020

PJM MIC Briefs: Jan. 8, 2020

VALLEY FORGE, Pa. — PJM’s Independent Market Monitor said Wednesday that recently approved maintenance adders to the synchronized reserve calculation allow resources to withhold from the reserve market and increase offers above competitive levels.

To remedy this, the IMM’s Catherine Tyler told the MIC to set the synchronized reserve operations and maintenance cost included in Manual 15 to zero. Market sellers could still submit alternate O&M cost calculations to PJM and the Monitor for review using an exception procedure outline in Section 1.8 of the manual.

Stakeholders on the Energy Price Formation Senior Task Force agreed last year that O&M costs for synchronized reserve offers should be removed from PJM’s market rules. That docket is still pending before FERC (EL19-58).

PJM’s Market Implementation Committee met Jan. 8 at the Conference and Training Center in Valley Forge, Pa. | © *RTO Insider*

Tyler said that a specific provision in Manual 15 allows steam unit synchronized reserves to include O&M costs attributable to a heat rate increase in their offers. The incremental energy offer curve and the no-load costs outlined in Schedule 2 of the Operating Agreement and the manual already account for this, Tyler said.

Sharon Midgley, Exelon’s director of wholesale market development, questioned why stakeholders would make this change while FERC has yet to rule on the energy price formation filing.

“The intent is to value resources more appropriately than how they are valued today,” she said. “This really decreases the value of reserves. … It’s doing the exact opposite of what the package’s intent was. Really focusing on one tiny component to us doesn’t seem right at this point in the process.”

“This is overstating costs for reserves, and it’s inappropriate and incorrect,” Tyler said. “Any other market design changes around reserves that would affect the price are completely separate from this.”

Stakeholders will vote on the potential manual change at the February MIC meeting.

Order 841 Update

Andrew Levitt, of PJM’s Applied Innovation Department, said work continues on the RTO’s brief to FERC due March 11 regarding its proposed 10-hour minimum runtime rule for energy storage resources offering into the capacity market.

FERC accepted most of PJM’s storage rules in October, but set the RTO’s 10-hour proposal for a paper hearing to determine whether it was just and reasonable. PJM requested a 90-day extension for its brief on Nov. 26.

In the filing, PJM said it needed extra time to engage with stakeholders after noting the sheer volume of protests over the proposed rule.

“Such dialogue will allow PJM to explore potential alternative approaches, as well as to ensure that all sides better understand each other’s respective positions,” the RTO wrote.

— Christen Smith

January 12, 2020

PJM PC/TEAC Briefs: Jan. 7, 2020

VALLEY FORGE, Pa. — PJM’s Planning Committee last week endorsed revisions to Manual 14F that would remove the competitive exemption for Form 715 local planning criteria transmission projects.

The change follows a September ruling from FERC Opens Local Tx Projects to Competition, Cost Sharing.)

PJM’s Planning Committee met on Jan. 7 at the Conference and Training Center in Valley Forge, Pa. | © *RTO Insider*

The directives came in two orders prompted by the D.C. Circuit Court of Appeals’ August 2018 remand that found FERC erred when it assigned all the costs for two Form 715 transmission projects proposed by Dominion Energy to the Dominion zone.

Critical Infrastructure Oversight

The Critical Infrastructure Stakeholder Oversight Task Force will hold its first meeting Jan. 27, PJM’s Christina Stotesbury said.

The PC approved the task force’s issue charge last month after several delays. The group will consider whether the RTO must develop governing document language to deal with transmission system enhancements designed to reduce the number of critical assets identified under NERC’s critical infrastructure protection standard CIP-014. (See “Critical Infrastructure Mitigation,” PJM PC/TEAC Briefs: Dec. 12, 2019.)

Stotesbury said the task force will recommend governing document changes within six months.

Order 845 Update

PJM’s Susan McGill said staff have until Feb. 17 to address several outstanding issues on its compliance with FERC Order 845: identification and definition of contingent facilities; provisional and surplus interconnection service; and incorporation of advanced technologies. The commission on Dec. 19 accepted six of the 10 changes the RTO proposed in its first compliance filing on the order, which is intended to increase the transparency and speed of the generator interconnection process (ER19-1958).

McGill said PJM will bring manual changes for the accepted revisions to the PC for a first read in February.

Capacity Import Study

PJM’s capacity import study completed last month shows the RTO can handle the 3,500 MW of capacity benefit margin (CBM) emergency assistance assumed available in the 2019 Reserve Requirement Study.

The anticipated allocation of CBM differs from 2019 because of increased generation dispatch in the Niagara area of NYISO that reduced import capability in the North supply zone from 412 MW to 120 MW. Withdrawn deactivation requests of several large units in PJM also increased import capability from the West 1 zone from 1,104 MW to 1,402 MW.

– Christen Smith

January 12, 2020

Court Says it Lacks Authority to Decide Entergy Suit

By Amanda Durish Cook

Entergy Mississippi has scored a major victory in an 11-year-old rate battle brought by the state’s former attorney general, who claimed the utility overcharged its customers.

Mississippi Chancery Court Judge Dewayne Thomas last month issued a ruling dismissing the case, deciding the court lacked the jurisdiction and expertise to hear the matter (25CH1:08-cv-02086).

Former Mississippi Attorney General Jim Hood filed the lawsuit in 2008, alleging that hundreds of thousands of Entergy customers paid too much because the company ran its own inefficient, older generation instead of purchasing less expensive wholesale power. Hood argued that Entergy owed up to $2 billion in damages from 1998 to 2013 as a result of its self-dealing.

Entergy Mississippi CEO Haley Fisackerly countered that the utility acted in the best interest of its customers. The company has argued that it did purchase power from third parties but also needed to run its own generation for the sake of reliability.

“Entergy Mississippi has some of the lowest rates in the country. We’re proud of our reputation for integrity in our business practices, which decades of clean audits prove,” Fisackerly said Thursday in a statement.

He also expressed satisfaction that the court agreed it wasn’t equipped to make a decision on utility rates.

“We have consistently maintained that a courtroom is not the proper forum to address issues about utility rates paid by customers and are grateful the Chancery Court carefully considered the issue and ruled in our favor,” Fisackerly said. He also pointed out that the company is subject to oversight from FERC and the Mississippi Public Service Commission. Those two agencies are “tasked with ensuring we treat our customers fairly,” Fisackerly said. Entergy has long argued that the complaint should be heard before FERC or the PSC if it were to proceed at all.

Current Attorney General Lynn Fitch, who took office a day after the ruling, has until Jan. 29 to appeal the court’s decision. Fitch did not respond to a request for comment.

The lawsuit’s lengthy history ended where it began — in county court, though the case mostly played out in the U.S. District Court for the Southern District of Mississippi. A four-day trial in April ensued before the district court remanded the case to the Chancery Court for lack of subject matter jurisdiction.

In his decision, Thomas cited FERC’s exclusive jurisdiction in filed rates and the Entergy System Agreement (ESA), which steered the Entergy operating companies from 1982 until 2013. Interpretation of the ESA has long been a source of disagreement in FERC proceedings. (See La. PSC Complaints Denied in Entergy System Disputes.)

“Because resolving the dispute in this matter involves the consideration and interpretation of the ESA, a FERC-approved tariff, this court must conclude that the matter falls within FERC’s exclusive jurisdiction,” Thomas wrote.

Hood early in 2019 called Entergy a “poor corporate citizen.” His out-of-state counsel also brought a similar $1 billion suit against Entergy Texas, which was also dismissed in 2015 on the basis of federal regulatory pre-emption by a Texas appeals court. Hood, a Democrat, was defeated in November’s gubernatorial election.

January 12, 2020

SPP Breaks 18-GW Barrier for Wind Production

SPP last week produced more than 18 GW of wind energy for the first time, less than four months after breaking the 17-GW barrier.

The latest record came at 6:08 p.m. Wednesday, when wind production hit 18,259 MW. That exceeded the previous wind peak of 17,861 MW set on Dec. 11. SPP first cracked 17 GW on Sept. 30, when wind production peaked at 17,107 MW.

SPP wind production — Jan. 20 Wind Mark | *SPP*

ERCOT holds the grid operator record with a 19,672-MW wind peak, set last January.

SPP has more than 22 GW of wind capacity.

— Tom Kleckner

January 12, 2020

Cuomo Sets New York’s Green Goals for 2020

By Michael Kuser

New York Gov. Andrew Cuomo signaled last week that his state will this year continue to step up efforts to decarbonize its economy with an eye to spreading the benefits.

New York Green Goals — Cuomo delivers the State of the State address. | *NYDPS*

“We must accelerate our transition to renewable energy, because the clock is ticking,” Cuomo said in his State of the State address Wednesday in Albany.

The Climate Leadership and Community Protection Act (A8429) signed into law last July calls for 70% of New York’s electricity to come from renewable energy resources by 2030, and for electricity to be 100% carbon-free by 2040. It also nearly quadrupled New York’s offshore wind energy target to 9 GW by 2035.

The law’s clean energy mandates also include doubling distributed solar generation to 6 GW by 2025, deploying 3 GW of energy storage by 2030 and raising energy efficiency savings to 185 trillion BTU by 2025.

Cuomo earlier in the week announced that the New York State Energy Research and Development Authority (NYSERDA) will solicit at least 1 GW of offshore wind energy this year and that a new $20 million Offshore Wind Training Institute at state college campuses on Long Island would begin training 2,500 workers next year.

The state last July awarded offshore wind contracts to Equinor’s 816-MW Empire Wind project and to the 880-MW Sunrise Wind, a joint venture of Ørsted and Eversource Energy. It also plans to commit $200 million to public investments in port infrastructure improvements to serve the new offshore wind industry.

“The creation of the Offshore Wind Training Institute is a critical step in developing the next generation of workers here in New York, who will serve as the backbone for the state’s offshore wind industry and clean energy future for decades to come,” Boone Davis, CEO of Atlantic Offshore Terminals, a developer of offshore wind supply facilities, said in a statement.

Think Big

NYSERDA this year also plans to award development funds to 21 large-scale solar, wind and energy storage projects across upstate New York, totaling more than 1,000 MW of renewable capacity and 40 MW of energy storage capacity.

“People say you have to choose between a strong economy and a healthy planet, but nothing could be farther from the truth,” Cuomo said. “The economy of tomorrow is the green economy.

“This year, let’s go big with an ambitious expansion of electric vehicles and attract the growing industry. It’s a win-win for our environment and our economy,” he said.

Cuomo announced he had chosen Binghamton University professor Stanley Whittingham, winner of the 2019 Nobel Prize in chemistry for his work with lithium-ion batteries, to lead a task force to provide the state with “the most aggressive road map to the e-vehicle future.”

Spectrum News quoted Whittingham on Friday: “The easiest vehicles to convert from internal combustion to electric are fleet vehicles, whether the state can take initiative to start converting hundreds of vehicles to electric, convert all the buses to electric.”

Cuomo said the New York Power Authority (NYPA) should plan and build a statewide functional network of charging stations.

The agencies will work with private industry to ensure that one or more fast-charging locations are available in each of the state’s 10 Regional Economic Development Council regions by the end of 2022, that every travel plaza on the New York State Thruway has charging stations by the end of 2024 and that a total of at least 800 new chargers are installed statewide over the next five years.

“Let’s use our collective government purchasing power and make sure that 25% of public transit bus fleets are electrified by 2025 and 100% by 2035,” Cuomo said. “Let’s make $100 million in Green Bank financing available to locate or expand EV manufacturers and suppliers in the state.”

The Green Bank of New York is a state-sponsored investment fund that helps leverage private financing for clean energy industry companies.

NYSERDA and NYPA will provide additional incentives to build more renewable projects and build them faster, focusing on opportunities upstate, and they will build new transmission lines to get the power to consumers who need it downstate, the governor said.

New York also will work this year to reduce fossil fuel consumption in buildings, with NYSERDA launching a $30 million retrofit program to demonstrate solutions for high-profile commercial and multifamily buildings.

NYSERDA will ask property owners, developers, equipment manufacturers and energy efficiency providers to propose ways to cut energy consumption and greenhouse gas emissions from buildings.

January 12, 2020February 12, 2025

NYISO Focus Turns to Grid ‘Transition’

By Michael Kuser

RENSSELAER, N.Y. — NYISO on Wednesday unveiled a plan to devote about one day a month in 2020 for stakeholders to discuss reliability and market issues related to the challenge of integrating a slew of clean energy resources into the grid over the next few years, a transition driven primarily by state policy.

“Until the markets reflect the cost of the environmental attributes that we’re trying to maximize, it is difficult to get renewable energy from upstate to the load centers downstate,” Mike DeSocio, the ISO’s director of market design, told the Installed Capacity/Market Issues Working Group (ICAP-MIWG).

NYISO last month published a 122-page “Grid in Transition” report, which will serve as the starting point for stakeholder discussion.

New York’s clean energy goals are reshaping the grid. | NYISO

Organized wholesale electricity markets have brought improved resource efficiency, “but there is more work to be done to deliver additional clean energy into New York City,” DeSocio said.

“New York’s electricity industry is transforming from a grid that is powered by traditional central-station, controllable fossil fuel generation to non-emitting, weather-dependent intermittent resources and distributed generation,” the report said.

Last year’s Climate Leadership and Community Protection Act (A8429) mandates the state to get 70% of electricity from renewable energy resources by 2030, develop 9 GW of offshore wind energy by 2035 and reach 100% carbon-free electricity by 2040.

The state’s clean energy goals also include doubling distributed solar generation to 6 GW by 2025, deploying 3 GW of energy storage by 2030,and upping its energy efficiency savings to 185 trillion BTU by 2025.

Reliability vs. Resilience

DeSocio said that reliability and resilience were much the same thing, with reliability the desired outcome, and resilience the means of achieving it.

Couch White attorney Kevin Lang, representing New York City, disagreed, saying that the two terms mean different things.

“In the city’s view, when it comes to resilience, the concern is the weakest link in the line or system,” Lang said. “At present, no reliability metric measures this factor.”

With respect to the grid transition discussion, Lang commented that the market provides signals for generation but not for transmission, adding that it is not clear that transmission is wholly a market responsibility.

Lang agreed with DeSocio’s response that the markets may not be the sole source of signals regarding the need for new transmission.

The grid paper did a good job of emphasizing the market, “but the afternoon will come when you need reserves, but also need energy prices not to be in scarcity pricing,” said Mark Reeder, representing the Alliance for Clean Energy New York (ACE NY).

“If you squeeze the high prices into a narrow band of hours, I wonder whether the ISO has thought about scarcity pricing,” Reeder said. “I worry about the exercise of market power.”

New York state economy-wide GHG emissions history and future reduction goals | NYISO

DeSocio replied that the ISO has thought about the topic, which it refers to as shortage pricing.

“The shortage pricing construct can be the right kind of signal for resources able to respond very quickly, from off to on in a very short period of time,” DeSocio said.

On carbon pricing, DeSocio said the ISO has done its job and that it’s up to the state to now act on the issue.

“We hope for a carbon pricing signal within the next six months, whether carbon pricing is a good idea or to stop talking about it,” he said. “We are not abandoning carbon pricing, but at the same time, we’re not talking about it much because it’s in the state’s hands to indicate where to go.”

The MIWG took over last January from the Integrated Public Policy Task Force (IPPTF), a joint effort between the ISO and the state’s Public Service Commission that spent a year-and-a-half developing the carbon pricing proposal released in December 2018.

The state must put a price on carbon in its electricity market if it hopes to meet the aggressive timelines of the decarbonization goals set out in the new law, the co-author of NYISO’s carbon pricing study, Analysis Group’s Sue Tierney, said in October. (See Carbon Pricing Vital to NY Goals, Study Author says.)

In addition, NYISO has registered support for carbon pricing in New York from many organizations, the latest of which is the New York League of Conservation Voters, which included support for carbon pricing in its 2020 Legislative Agenda.

“Putting a price on carbon is the only way New York can even come close to meeting its emissions goals,” Mark Younger of Hudson Energy Economics said Wednesday.

Howard Fromer, director of market policy for PSEG Power New York, said the state government acted to meet an environmental challenge, and that “markets have been successful at addressing environmental concerns, the most dramatic evidence being the reductions in nitrogen oxides and sulfur oxides over the past couple decades.”

Discussion Process

Energy market design specialist Ashley Ferrer presented a rough outline of the process for the grid transition discussions this winter and spring.

Associate capacity market design specialist Emily Conway laid out the timeline through May, with ICAP/MIWG meetings on grid transition reliability and market issues scheduled for Feb. 4, March 6 and 26, and May 11.

NYISO has scheduled stakeholder meetings from January to June 2020 to discuss topics related to the transformation of the grid. | NYISO

The outline referred stakeholders to potential questions in a project planning and market product file from last September, which included the following under reliability and market considerations:

What are appropriate market structures for assuring reliability in the 2030 and 2040 cases?
How to set reliability requirements and measure reliability with a system made of renewables and storage of different durations?
How to accommodate potentially reduced [uninstalled capacity] contribution arising from correlated renewable outages?
What role should real-time retail pricing play to assure customer load reductions when correlated outage events occur?
Where should the cost of loss of load be considered?
NYISO will kick off the discussion of each specific topic, followed by stakeholder presentations. Stakeholders need to submit materials for ISO review six business days before the meeting. Materials will be posted three business days prior to the working group meeting, consistent with current procedures.