FERC approved cost allocations for projects involved with northern New Jersey’s Bergen-Linden Corridor (BLC) last week (ER17-725) but left room for revisions based on a challenge to the original allocation (EL15-67).
In last week’s order, FERC denied requests for clarification and rehearing and accepted PJM’s Tariff revisions that allocate costs for the BLC projects to Neptune Regional Transmission System, Hudson Transmission Partners and Linden VFT.
FERC’s offices in Washington, D.C.
Linden and the New York Power Authority had requested clarification on PJM’s allocations. NYPA noted that Hudson’s responsibilities for the projects increased by $10.17 million after the company previously carried no responsibility for the upgrades. PJM failed to explain how modeled flows on the system could have changed so significantly since the RTO last performed its analysis, the agency contended. Hudson owns the merchant transmission facility NYPA uses for energy exports into New York City.
Linden argued that the solution-based distribution factor (DFAX) method bases its allocation on power flow, making it “particularly ill-suited” for non-flow-based projects, like the BLC.
FERC dismissed these complaints, explaining that they “challenge the cost allocation method in PJM’s Tariff rather than whether PJM properly applied its Tariff,” but it conditioned the approval on the outcome of Linden’s separate challenge to the allocation method itself.
“We find that PJM has correctly applied its Tariff, and the question of whether the Tariff provision regarding cost allocation is just and reasonable is pending before the commission in other proceedings,” the order said.
FERC Commissioner Cheryl LaFleur concurred with the order but wrote separately to note her dissent on the denial of Linden’s original challenge to the allocation methodology. Several organizations, including NYPA and Linden, requested rehearing of the issue, which FERC granted in June 2016.
New York is fine-tuning plans for meeting its 2030 renewable energy target and closing the books on the energy efficiency programs that it has used since 2008.
The New York Public Service Commission earlier this month approved orders implementing the second phase of the state’s Clean Energy Standard (CES) and approving the conclusion of its Energy Efficiency Portfolio Standard (EEPS).
| NY DPS Webcast
The CES adopted last year by the PSC mandates that 50% of the electricity used in New York be generated by renewable energy sources by 2030. In a Nov. 16 order, the PSC largely approved its staff’s recommendations for implementing Phase 2 of the CES, which will add quarterly renewable energy credit (REC) auctions (Case 15-E-0302).
The order also continues limits on the sale or transfer of Tier 1 RECs and institutes a “divergence test” to identify and correct REC supply/demand imbalances.
The New York State Energy Research and Development Authority will continue monitoring generators’ carbon emissions, managing REC procurement and setting Renewable Energy Standard (RES) targets for load-serving entities three years in advance.
Rhodes | NY DPS Webcast
PSC Chair John Rhodes said the new order “sets out the procedures and methods and fund management rules for NYSERDA to implement the next phase of the Clean Energy Standard, and including, importantly in my view, providing rolling future visibility for the Renewable Energy Standard targets for 2018 through 2021.”
Burman | NY DPS Webcast
Commissioner Diane Burman abstained, saying the PSC’s instructions were “not detailed enough.”
The order “still is leaving holes for decision-making that I’d like to see a lot more finality in, including the state energy plan and other things we need to address more holistically,” she said.
Under the new rules, NYSERDA will offer for sale all the Tier 1 RECs in its account quarterly, with unsold RECs offered in the next auction. NYSERDA had two auctions in 2017, one each at the end of the first and third quarters.
The quarterly sales will allow LSEs “greater awareness of the actual load served during the preceding quarter, which may encourage LSEs to purchase NYSERDA’s RECs when offered, thereby improving NYSERDA’s cash flow and reducing NYSERDA’s working capital requirements,” the commission said.
The commission rejected a request by the state’s utilities to allow LSEs to trade NYSERDA-procured Tier 1 RECS for the 2018 compliance year, continuing the existing ban. “A near-term change in REC sales and trading under the Renewable Energy Standard program would be out of alignment with the [Value of Distributed Energy Resource Proceeding, Case 15-E-0751] order and the expected evolution of REC trading rules in future years,” the commission said. “The implementation of the quarterly REC sale process will limit the potential exposure of an LSE over- or under-procuring RECs from NYSERDA, thus eliminating the need of trading NYSERDA-purchased RECs among LSEs.”
The commission also rejected proposals by environmental groups that the 2018-2021 targets be evenly distributed to allow developers to take advantage of expiring federal tax credits. Instead, the commission continued the state’s back-loaded approach, saying it “is based on the expected three-year development and construction cycle between the receipt of a NYSERDA award for Tier 1 RECs and a facility’s ability to start producing RECs upon commercial operation. In other words, the targets reflect realistic expectations regarding availability of Tier 1 RECs as the RES program ramps up.”
The PSC disagreed with the environmental groups’ criticism that the staff proposal lacked LSE targets through 2030. “Providing a mandated trajectory out through 2030 at this time would undoubtedly require adjustments in the later years to account for changes in statewide electric load, and other factors. … Therefore, the trajectory through 2021 for the revised LSE targets provided in the Phase 2 proposal is deemed sufficient to provide enough certainty for planning purposes for LSEs, renewable developers and other market participants.”
As part of its annual compliance reporting, NYSERDA will publish its methodology for calculating the statewide fuel mix to provide “transparency in accounting for the historic renewable baseline, the mandated targets, the voluntary market and other activities for measuring progress towards the 50-by-30 goal,” the commission said.
Palmero | NY DPS Webcast
NYSERDA will report on the program’s finances, including REC sales, alternative compliance payments, program expenses and surpluses or shortfalls, annually. If any cumulative surplus is more than 25% of the contractual Tier 1 REC payment obligation to generators for the current year, NYSERDA must propose a use for the excess portion that is in the ratepayers’ interest.
“We don’t expect there to be a lot of [alternative compliance payments], at least in the near term, because we’re trying to match the amount of RECs that will be available to the LSE obligation, but if there is a fund sitting there, NYSERDA will propose what they will do with the excess,” said Christina Palmero, deputy director of the state Department of Public Service’s Office of Clean Energy.
NYSERDA also was directed to develop criteria for combining aggregated and co-located facilities into a single Tier 1 bid for 2019. “Allowing aggregated and co-located facilities to bid as single facility for Tier 1 solicitations appears to be a prudent addition to the rules,” the commission said.
Concluding the Energy Efficiency Portfolio Standard
In a separate order, the PSC also voted to conclude the EEPS program and award 11 investor-owned utilities $56.5 million in shareholder incentives for meeting the electric savings targets and $12.4 million for meeting gas targets (Case 07-M-0548).
| NY DPS
Sayre | NY DPS Webcast
“EEPS was a good program and a successful program and we’ve learned from it,” Commissioner Gregg Sayre said. “I believe our replacement programs are better.” The commission’s Reforming the Energy Vision order of 2016 requires each utility to submit an annual Distributed System Implementation Plan and Energy Efficiency Transition Implementation Plan showing how they propose to meet the energy efficiency budgets and targets set by the PSC.
The program paid most utilities $38.85/MWh for reduced consumption. Consolidated Edison was paid $100,000/MW, capped at $5 million (50 MW) annually. All but Orange and Rockland Utilities (98%) exceeded their electric targets for the program.
Burman dissented, saying the commission had to learn from EEPS “the need to be more prudent and measured in making our demands, the need to be more realistic and thoughtful ahead of time about how quickly goals can be accomplished, and the need to truly understand what the financial implications may be to run the programs, and to prepare in case programs are more in demand than anticipated.” [Editor’s Note: An earlier version of this article failed to note that Burman had voted no and improperly prefaced her quote by saying “the commission had learned” from EEPS.]
The order directs utilities to file an EEPS financial reconciliation report no later than June 30, 2018, documenting program expenditures, unspent funds and accrued interest.
RG&E, NYSEG Face Penalties over Wind Storm Response
The commission also completed its investigation into the March 8 wind storm that left 123,000 Rochester Gas and Electric customers and 48,000 New York State Electric and Gas customers without power, finding the companies are liable for millions in penalties for violating their emergency response plans (Case 17-E-0594).
wind storm damage | Avangrid
The commission said both companies failed to fully secure downed wires reported by municipal officials within the required 36-hour period; to keep the public informed about restoration times; and to coordinate communications with customers on life-support equipment.
In addition, the commission said RG&E: began its damage assessment too late; failed to create a list of critical facilities such as fire and police stations to be prioritized in restoration efforts; did not update its automated voice messaging services to reflect storm conditions; and did not staff its call center adequately.
The commission directed the companies to respond within 30 days to show why penalties should not be initiated and show how they will improve their response.
The commission said National Grid was not subject to penalties because it restored more than 90% of its 113,000 outages within 36 hours.
Other Rulings
The PSC also approved:
ORU’s plan to spend $98.5 million to install smart meters for all its electric and gas customers. The new meters are expected to produce a net benefit of nearly $16 million. The utility will replace approximately 230,000 electric and 135,000 gas meters (Case 17-M-0178).
NYSEG’s and RG&E’s plans to offer light-emitting diodes (LED) street lighting to municipal customers. Replacing all of the utilities’ combined 93,000 old-style street lights could save municipalities as much as $5.8 million a year based on reduced costs of $63 per light. Street lights may account for up to 40% of total electricity use for a local government, but prior rules required municipalities to take ownership of the lights to switch to LED. The order allows municipalities to switch to the cheaper LEDs while NYSEG and RG&E retain the responsibility for maintaining them (Cases 16-E-0710, 16-E-0711).
It seems little connected to SPP’s Z2 process goes off without a hitch these days.
A mismatch between posted Z2 reports and invoices sent this month forced the RTO to email members Nov. 17 to “dispel any confusion that may have resulted.”
The invoices included Z2 billing amounts for the historical period (March 2008-August 2016) and September 2017. However, they did not include the interim months (September 2016-August 2017) “due to administrative issues,” SPP said. The RTO did not explain the problem.
SPP said it would ask FERC to waive its one-year resettlement window to permit including the September 2016 Z2 amounts on a future invoice. Z2 amounts for October 2016 and resettlements for November 2016-July 2017 will be included on the invoice sent in December.
Attachment Z2 of SPP’s Tariff assigns financial credits and obligations for sponsored transmission upgrades.
SPP this September completed a resettlement of the revenue crediting amounts under Attachment Z2 for the March 2008-August 2016 historical period, a move made necessary because of corrections and true-ups to the data that were identified before the first settlement of the charges. (See “More Z2 Woes; SPP to Resettle 9 Years of Data,” SPP Markets and Operations Policy Committee Briefs: July 11-12, 2017.)
In September 2016, the RTO identified about $200 million in revenue credits to be collected for transmission upgrades under Z2. The bills covered eight years of credits and obligations for 2008-2016 when staff failed to apply credits, complicating the task of trying to accurately compensate project sponsors and claw back money from members with debts for the upgrades. (See Preliminary Z2 Bills Released; Task Force Develops Options for Waiver Requests.)
Dynegy’s most recent bid to develop a specialized capacity market for downstate Illinois has failed to gain traction in the state’s legislature, but the conversation around the region’s resource adequacy is far from over.
The legislation (SB 2250/HB 4141), which would have created a separate competitive capacity auction for central and southern Illinois administered by the Illinois Power Agency, failed to advance after hearings this month.
Dynegy last month characterized the competitive auction as “subsidy-free” and “fuel-neutral.” It was expected to translate into higher clearing prices.
“It didn’t move but that doesn’t necessarily mean it’s dead. I think they will try again in the legislature in 2018,” said Jessica Collingsworth, an energy analyst with the Union of Concerned Scientists. “Coal is on its way out, and Dynegy is holding on for as long as it can. … I think it may be the same exact bill [in the future]. They seem to have stuck with that on the legislative angle.”
Dynegy did not respond to a request for comment on its next steps. The company has said the “lack of a functioning capacity market” in MISO’s Zone 4 is to blame for power plant closures and, in turn, increased electricity bills as shortage pricing is imposed in the absence of sufficient baseload generation.
The Houston-based company said the legislative proposal was meant to address electric reliability and price stability in Zone 4. Last year, FERC rejected MISO’s separate three-year forward capacity market design for deregulated portions of its footprint.
No Support for NOPR
Although coal-fired generation represents more than one-third of Dynegy’s capacity, the company does not support the cost recovery for coal and nuclear facilities proposed by Energy Secretary Rick Perry (RM18-1). (See FERC Flooded with Comments on DOE NOPR.)
“Even from the perspective of a coal generator, the proposed rule should not be adopted because it would substantially, and potentially irreversibly, harm the nation’s competitive electricity markets,” Dynegy wrote. While acknowledging the NOPR would solve its price problems in MISO, the company nevertheless said it amounts to a “reregulation of coal and nuclear facilities that would severely harm, and potentially represent a death blow to the competitive markets that [FERC] has worked hard to develop.”
Dynegy CEO Robert Flexon said the separate auction would safeguard against distorted prices from regulated utilities.
“Under the status quo, the viability of existing plants that are fully environmentally compliant is threatened, as are thousands of local jobs and support functions. This legislative proposal would help safeguard our downstate plants without the use of subsidies, while encouraging investment in all sources of power supply — including conventional generation, demand response and renewables.”
Collingsworth noted the legislation did not require Dynegy to keep any of its coal plants operating.
“Even if a bill were to pass, there’s no guarantee from Dynegy that these coal plants will stay open,” she said. “So what happens if we give them a bailout, and they only keep two plants open and run them harder? That’s still closing plants in communities.”
Collingsworth believes increased renewables and storage can be profitable even considering Zone 4’s deregulated market.
“I think people want solar on their roof. And I think that if they can’t have that, they want to buy into a community solar program. I think there is a lot of opportunity with the Future Energy Jobs Act. We have not even touched the surface of our solar potential in central and southern Illinois,” she said.
Dynegy has warned that another 30% of total downstate resources could retire over the next three years “due to an inability to cover operating costs.”
Dynegy has at least partial ownership in eight Zone 4 power plants totaling 6,500 MW, making it responsible for nearly 50% of electricity production in the local resource zone. Zone 4 currently has 57 utility-scale generating stations with a combined 16 GW of nameplate capacity.
Edwards Station | Iron Hustler Excavating
The largest recent capacity declines in Zone 4 can be attributed to the retirement of Dynegy coal-fired generation. In the last two years, the company has shut down a combined 1.25 GW of coal-fired generation: the 500-MW Wood River power station in Alton, 617 MW at the Newton power plant and 136 MW at the Edwards plant in Bartonville.
Whitepaper, Workshops
MISO this year maintained there is no reliability issue Zone 4, predicting a 0.7-GW capacity surplus in the region in 2018, up from the 1.6-GW shortfall the grid operator predicted for 2018 in its 2016 resource adequacy survey produced in cooperation with the Organization of MISO States. (See Capacity Survey Shows MISO in the Black.)
“MISO’s recent 2017 OMS-MISO survey results suggest that Zone 4 capacity requirements will continue to be met through 2022. Planned transmission and generation provide additional reason for optimism in this regard,” the Illinois Commerce Commission wrote earlier this month in a white paper requested by Gov. Bruce Rauner as a response to MISO’s appeal for a resource adequacy plan.
The commission’s report said the state has four options to address resource adequacy in central and southern Illinois: continue to rely on existing competitive forces and market structures; impose additional capacity requirements on load-serving entities; create a reliability portfolio standard; or encourage or require utilities to switch RTOs. Dynegy last year proposed legislation that would transition the entire state into PJM’s markets. (See Dynegy Introduces Bill to Move All of Ill. Into PJM.)
MISO officials will participate in a pair of workshops on Zone 4 resource adequacy beginning Dec. 7 at the ICC’s offices. Stakeholder comments on the challenges of Zone 4 are due to the commission on Nov. 30.
Illinois EPA Rule Change Still in the Works
Meanwhile, Dynegy continues to work with the Illinois Environmental Protection Agency to revise the state’s Multi-Pollutant Standard, a 2006 clean air standard for coal plants. The company is advocating that an annual cap on sulfur dioxide and nitrogen oxide emissions be imposed on the state’s coal fleet as a whole, rather than on individual power plants. If approved, the new sulfur dioxide limit would be almost double what Dynegy emitted last year, while the nitrogen oxide cap would be 79% higher. The caps would not be decreased should Dynegy retire or mothball any plants.
The new rule was initially expected to be adopted this month, but the Illinois Pollution Control Board now plans to hold hearings on the change on Jan. 17 in Peoria and March 6 in Edwardsville. Peoria is near the shuttered Edwards plant, while Edwardsville is close to the vacated Wood River plant.
“This is going to give these communities a chance to speak out,” Collingsworth said. “It was so fast. I think the environmental community played a role in saying, ‘Whoa, pump the brakes’ and delayed this. You do need to have public input in this.”
The Illinois Clean Jobs Coalition said the revision would result in “massive new air pollution for the state of Illinois and beyond.”
VALLEY FORGE, Pa. — The results are in, but will they make a difference?
At its final scheduled meeting, PJM’s Capacity Construct/Public Policy Senior Task Force (CCPPSTF) last week reviewed the results of a vote on proposals to re-envision the RTO’s capacity market structure. With 63% in favor, the Independent Market Monitor’s extended minimum offer price rule (MOPR) was the only proposal to receive a simple majority. The closest contender was PJM’s two-stage repricing proposal, which received 26.1% approval. (See PJM Drops MOPR in Capacity Talks; Dayton Withdraws.)
Because the vote was binding, the Monitor’s package will have a first read at the Dec. 7 meeting of the Markets and Reliability Committee with an endorsement vote planned for the next MRC on Dec. 21. No other proposal can be considered until the Monitor’s package is voted down. PJM is holding two MRC meetings in December because the November meeting was pushed into next month to account for the Thanksgiving holiday.
The popularity of the Monitor’s proposal is somewhat deceiving. As part of the vote, stakeholders also responded to a nonbinding poll on whether making a change was preferable to maintaining the status quo. That poll found 64% in favor of maintaining the status quo.
The results suggest that after more than a year of debate on the issue, stakeholders feel they haven’t found anything better than the current situation, but they continue to fear their preference won’t prevent PJM from filing something for approval from FERC. PJM’s Stu Bresler balked when asked whether the RTO would commit to the status quo.
“Out-of-market subsidies present a threat to the ability for the wholesale market to perform its intended function,” Bresler said. “We have a strong desire to protect the market. … If I’m asked to interpret the results of the poll … I don’t think necessarily it would keep PJM from taking action that needs to be taken at FERC to defend the market from these kinds of actions.”
He said it “remains to be seen … whether we’ll be able to indicate prior to the vote what PJM’s recommendation” to the Board of Managers will be.
PJM’s Dave Anders, who coordinates the CCPPSTF, suggested stakeholders voice their preferences directly to board members at the MRC or by writing letters to the board.
Although the Monitor’s proposal had shown strength in an earlier poll, some stakeholders seemed surprised at its continued support in the final vote. (See PJM Pressed on Plans to File Capacity Changes.) Calpine’s David “Scarp” Scarpignato asked if there is any remaining opportunity to revise the MOPR proposal before seeking MRC endorsement. Anders said the plan would follow the usual path of proposals, meaning that any proposed changes would need to occur at the MRC.
Duquesne Light’s Tonja Wicks confirmed that her company maintained its support for the status quo, a position she had previously enunciated.
“We voted down every single proposal because we wanted to vote our conscience,” she said.
Adrien Ford of Old Dominion Electric Cooperative said the results indicate support for “a more pure approach” to securing the market than a two-stage repricing mechanism that “de-links” the offer price from the probability of clearing the auction.
Susan Bruce, who represents the PJM Industrial Customer Coalition, noted “a lot of discomfort” with the two-stage proposals because “once that gets imbedded into the market, there’s no going back.”
Gabel Associates’ Mike Borgatti said the extended MOPR creates a “pathway” that doesn’t currently exist for states to ensure their competitive renewable portfolio standard policies meet the Monitor’s standards without “running afoul” of the MOPR.
“There certainly [could be] programs that would not qualify under that pathway,” so MOPR rules may eventually need to be revised, but “I think this is an incremental first step,” he said. “It’s important to recognize that this gives state policymakers, PJM and market [participants] a level of regulatory clarity that does not exist today.”
Jason Barker of Exelon, which proposed a repricing variant, cautioned that the MOPR is “really stepping on a slippery slope … because all cost or revenue advantages conveyed by any level of government affect the market outcomes in exactly the same way” and would be “unduly discriminatory” if it allows “some subsidized competitors to participate unimpeded while mitigating others.
“One thing that needs to be balanced here is whether or not the mitigation that is being applied is being done so in an impartial fashion,” he said.
CAISO and Pacific Gas and Electric are opposing the terms of a reliability-must-run agreement for two California natural gas-fired plants that Calpine submitted with federal regulators early this month, complicating an arrangement set to take effect at the beginning of next year.
The ISO and PG&E filed separate protests with FERC over the terms of the RMR agreement for the Yuba City and Feather River plants, filed with the commission Nov. 2 by Calpine subsidiary Gilroy Energy Center. CAISO designated the units as RMR in March, but the ISO told FERC that Gilroy had not supported provisions related to scheduling coordinator charges, greenhouse gas emissions and gas prices.
Yuba City power plant | Calpine
CAISO is increasing its use of out-of-market RMR payments to keep units online, raising concerns that its market is not producing the price signals sufficient to support units needed to provide reliable electric service. The ISO’s Board of Governors early this month approved the third RMR of this year, for Calpine’s Metcalf Energy Center. (See Board Decisions Highlight CAISO Market Problems.) Costs are borne by utility ratepayers such as those of PG&E.
Map identifying the need for Yuba City and Feather River plants | CAISO
CAISO in its protest did not ask FERC to reject the application but to set it for settlement before the effective date of Jan. 1.
“There are also technical issues with the inputs to the other rate schedules as well, which the CAISO anticipates can be addressed through the exchange of information during settlement discussions and through further informal exchanges between the parties,” the ISO said.
PG&E said FERC should approve the RMR rates for Jan. 1, subject to refund, and launch a separate proceeding “under Section 206 of the Federal Power Act to examine whether the RMR program in the CAISO tariff is unjust and unreasonable.” The utility said “the RMR designations were premature” and will increase costs.
PG&E also noted the increased use of RMR units in recent years.
“After years of decreasing use, such that a minimal number of facilities were designated as RMR units, the CAISO has designated three new RMR units in PG&E’s service territory for 2018 alone,” PG&E said.
California ethics officials have obtained new evidence of apparent back-channel communications between Pacific Gas and Electric and the state Public Utilities Commission in the wake of the fatal San Bruno gas pipeline explosion.
The disclosure comes as the CPUC is poised to consider a proposed $86.5 million settlement agreement over previously disclosed improper communications between commissioners and PG&E, the pipeline operator blamed for the 2010 accident that killed eight people.
The CPUC is poised to approve an $86 million settlement between PG&E, its enforcement staff and other parties
Kennedy | Linkedin
Jay Wierenga, spokesman for the California Fair Political Practices Commission (FPPC), confirmed to RTO Insider that the agency is seeking communications since 2012 between the CPUC and Susan P. Kennedy, a former commissioner and aide to former Gov. Arnold Schwarzenegger. He provided no further details on the probe, which was first reported by The San Diego Union-Tribune.
But in late September, KNTV, the San Francisco Bay Area’s NBC affiliate, quoted a 2013 email in which one commissioner urged PG&E to take a tough stand during secret settlement talks over the San Bruno explosion, which killed eight people. In April 2015, the CPUC ordered the company to pay $1.6 billion in fines and penalties for safety violations.
CPUC spokesperson Terrie Prosper confirmed the agency is responding to an Aug. 21 data request from the FPCC. PG&E said it had no comment on the investigation.
New Violations?
A spokesperson for The Utility Reform Network (TURN) told RTO Insider last week that the newly disclosed emails should be considered separately from the settlement proposed by a CPUC administrative law judge on Sept. 1, which is awaiting action from the commission. TURN is a party to the settlement, negotiated over the past two years between PG&E, CPUC enforcement staff, the cities of San Bruno and San Carlos, and the Office of Ratepayer Advocates.
“The commission needs to take a look at these new ones that appear to show more violations,” TURN spokesperson Mindy Spatt said. “PG&E may well think ‘you’ve seen one email, you’ve seen them all,’ but each of these emails involve separate violations.”
ALJ Robert Mason approved most of the settlement, which includes $63.5 million in foregone revenue requirements for 2018 and 2019; a $10 million penalty to be amortized in the company’s next general rate case cycle; and $6 million each to San Bruno and San Carlos. But the judge said the commission rejects a $1 million fine to the state general fund as too low.
“Given the flagrant and pervasive nature of PG&E’s actions that were not only illegal, but tainted the commission’s regulatory process and undermined public confidence in the integrity of the commissioners and their staff, the commission has determined that a larger fine should be imposed,” Mason wrote.
“This proceeding shall remain open pending the resolution of whether PG&E shall agree to pay the increased fine of $12 million to the state of California General Fund,” Mason wrote.
Kennedy, a longtime member of the California political elite, is a partner in San Francisco-based Caliber Strategies, a public affairs consulting team, and founder of Advanced Microgrid Solutions (AMS), an energy storage company whose investors include Schwarzenegger.
Aside from a broad request for all communications from 2012 to present, the FPPC data request specifically seeks correspondence between the PUC and Kennedy and others at Caliber Strategies that mention PG&E, the pipeline explosion “or any related legal, legislative or regulatory actions that resulted from said explosion.”
The FPCC also requested communications between Kennedy and former Commissioner Catherine Sandoval; former CPUC Executive Director Paul Clanon; current CPUC Communications Advisor Lester Wong; current CPUC Director of Planning Marzia Zafar; former CPUC President Michael Peevey; Carol A. Brown, Peevey’s former chief of staff; and Brigadier General Emory “Jack” Hagan, former director of the CPUC’s Consumer Protection and Safety Division.
The document seeks “any and all verification applications, including all supporting documents, submitted to or through The Supplier Clearinghouse,” a company that certifies minority- and women-owned businesses under a CPUC diversity program.
The FPPC was created by the state’s Political Reform Act of 1974, and its enforcement division has power to take civil actions, not criminal prosecutions, which are under authority of local district attorneys or state attorneys general.
A veteran of the California political scene, Kennedy has worked as chief of staff for Schwarzenegger, cabinet secretary to former Gov. Gray Davis, communications director for U.S. Sen. Dianne Feinstein and executive director of the California Democratic Party.
Kennedy’s spokesman James C. Harrison told RTO Insider in a statement last week: “Ms. Kennedy is aware of the information request and is providing the Fair Political Practices Commission with all of the necessary information regarding the inquiry.”
Kennedy Discusses Peevey with PG&E
The newly disclosed emails reveal Kennedy, then a PG&E consultant, discussing the San Bruno case with PG&E Vice President of Regulatory Relations Brian Cherry in 2013. PG&E said in January 2015 that it had provided 65,000 emails to the CPUC, fired executives including Cherry and implemented new compliance programs to address the improper ex parte contacts.
The site of the 2010 PG&E gas pipeline explosion in San Bruno, California
KNTV reported in September that PG&E had made a regulatory filing stating that it discovered additional emails in response to a search requested by an “unspecified government agency.”
In a Jan. 9, 2013, email, Kennedy discusses meeting with Peevey and recounts his criticism of the CPUC’s “mishandling” of the San Bruno case.
“He hopes [Hagan] can bring something home — but that the crazies are so far out there it may not be possible. Blamed most of the craziness on the locals in [San Bruno] and his personal prosecutor, Jerry Hill. Sounds like a settlement was highly unlikely but not completely off the table.”
Kennedy discusses a “second date” with Hagan in Los Angeles to see a Schwarzenegger movie and that “if I can bring it up without it pushing him the wrong way, I will.”
Hill, now a state senator representing San Bruno, last December questioned why an investigation launched in 2014 by then-Attorney General Kamala Harris into Peevey’s private communications with PG&E was never resolved.
Peevey, appointed president of the CPUC in 2002 by Davis, and reappointed by Schwarzenegger in 2008, stepped down from the CPUC on Jan. 1, 2015.
The FPPC data request also sought communications of Manal Yamout, a partner with Kennedy in Caliber Strategies who is also senior vice president of policy and markets for AMS. The request seeks Yamout’s communications with the San Francisco-based ride-sharing company Lyft.
Yamout is a former top adviser to Schwarzenegger and Gov. Jerry Brown. She also has served as California’s assistant secretary for international Trade, and special assistant to former First Lady Maria Shriver.
Yamout was the topic of a November 2014 report by the U.S. Department of the Interior’s inspector general regarding her romantic relationship with former DOI Senior Counselor Steven Black when she was a lobbyist for Florida-based NextEra Energy. The U.S. Attorney’s Office for the District of Columbia declined to prosecute the case. Black recused himself from matters involving NextEra and resigned from the department in May 2013.
Both Black and Yamout were members of the Renewable Energy Policy Group, created in 2009 by Schwarzenegger and Interior Secretary Ken Salazar, under whom Black served. The group was formed to improve federal-state coordination in siting renewable energy projects.
Yamout did not respond to a request for comment regarding the investigation.
Strong Growth for Advanced Microgrid Solutions
AMS has grown into a major player in California’s burgeoning energy storage market since its founding in 2013. Kennedy started the company with the late Jackalyne Pfannenstiel, a former PG&E executive who also served on the CPUC and the California Energy Commission.
AMS is not mentioned in the FPCC information request.
The company and Macquarie Capital have teamed up to deploy a 50-MW fleet of energy storage batteries in the service territory of Southern California Edison.
Last year, Macquarie announced a $200 million investment to fund AMS projects in California. The company is also funded by Southern Co.; DBL Partners; GE Ventures; AGL Energy, Schwarzenegger; and an investment firm named Energy Impact Partners.
Energy Impact Partners’ Advisory Board counts among its members Steven Chu, secretary of energy under President Barack Obama; Spencer Abraham, secretary of energy under President George W. Bush; and Rodney Slater, secretary of transportation under President Bill Clinton.
The RTO Insider Top 30 saw improved profits in the third quarter over 2016, but revenues fell, and more than half of the companies saw their top and bottom lines shrink.
| company filings
Net income grew $563.7 million (5.3%) to $11.1 billion as all 30 companies turned a profit, indicating that their problems weren’t strong enough to overcome the seasonal strength of the quarter that includes the year’s two hottest months. Still, 17 companies saw their income fall.
Revenue fell $1.36 billion (1.6%) to $85.4 billion, with 18 companies posting revenue declines, in some cases because of unfavorable weather.
Company
Market Cap ($ billions)
Revenue Q3 2017 ($ billions)
% change vs. 2016
Net Income Q3 2017 ($ millions)
% change vs. 2016
AEP
$37.67
$4.10
-11.77%
$544.7
-171.1%
Alliant
$10.22
$0.91
-1.91%
$168.8
31.5%
Ameren
$15.27
$1.72
-7.32%
$288.0
-22.0%
Avangrid
$15.79
$1.34
-5.43%
$99.0
-9.2%
Berkshire Hathaway Energy
NA
$5.28
3.75%
$1,068.0
3.1%
Calpine
$5.42
$2.59
9.81%
$225.0
-23.7%
CenterPoint Energy
$12.56
$2.10
11.06%
$169.0
-5.6%
CMS Energy
$13.93
$1.53
-3.78%
$172.0
-7.5%
Consolidated Edison
$26.87
$3.21
-6.03%
$457.0
-8.0%
Dominion Energy
$52.87
$3.18
1.50%
$665.0
-3.6%
DTE Energy
$20.20
$3.25
10.83%
$270.0
-20.1%
Duke Energy
$62.04
$6.48
-1.43%
$954.0
-18.9%
Edison International
$26.11
$3.67
-2.52%
$470.0
11.6%
Entergy
$15.41
$3.24
3.81%
$398.2
2.6%
Eversource Energy
$20.22
$1.99
-2.51%
$260.4
-1.9%
Exelon
$40.13
$8.77
-2.59%
$824.0
68.2%
FirstEnergy
$15.23
$3.71
-5.18%
$396.0
4.2%
Great Plains Energy
$7.39
$0.86
0.05%
$3.4
-97.4%
NextEra Energy
$73.00
$4.81
0.06%
$847.0
12.5%
NiSource
$9.11
$0.92
6.47%
$14.0
-48.5%
NRG Energy
$9.25
$3.05
-10.87%
$171.0
-57.5%
OGE Energy
$6.97
$0.72
-3.64%
$183.4
-0.1%
PG&E
$27.72
$4.52
-6.09%
$550.0
41.8%
Pinnacle West Capital
$9.98
$1.18
1.41%
$276.1
5.0%
PPL
$24.83
$1.85
-2.33%
$355.0
-24.9%
PSEG
$26.03
$2.26
-7.63%
$395.0
20.8%
Sempra Energy
$29.82
$2.68
5.44%
$57.0
-90.8%
WEC Energy Group
$21.54
$1.66
-3.21%
$215.4
-0.7%
Westar Energy
$7.96
$0.79
3.88%
$158.3
2.3%
Xcel Energy
$25.66
$3.02
-0.76%
$492.1
7.5%
Totals
$669.2
$85.4
-1.57%
$11,146.8
5.3%
American Electric Power posted by far the largest increase in net income — $1.31 billion — but that was largely due to its 2016 performance, when it lost $765.8 million because of a $2.3 billion write-down on the value of its competitive wind farms, coal generators and coal-related properties. (See AEP Turns Away from Generation to Transmission, PPAs.) AEP earned $544.7 million in the just-ended quarter, but its adjusted earnings per share of $1.10 missed the Zacks consensus estimate of $1.19 and were down from $1.30/share — excluding the impairment — a year ago.
After releasing its earnings, AEP said it plans to invest $18.2 billion from 2018 through 2020, 72% of which will be focused on its transmission and distribution operations. That includes $1.8 billion in new renewable generation, but excludes the $4.5 billion Wind Catcher project in Oklahoma, which is dependent on regulatory approvals in 2018. (See AEP to Spend $4.5B on Largest Wind Farm in US.)
Exelon had the largest percentage increase in net income, 68.2% ($824 million), primarily due to increased profits at Commonwealth Edison ($152 million) and its generation unit ($69 million). Company executives also said its utilities were performing better than planned.
| company filings
Exelon’s bottom-line success hasn’t stopped it from pushing for subsidies for its nuclear generation fleet, which is the largest in the nation. In its third-quarter earnings call, CEO Chris Crane said the company was encouraged by Energy Secretary Rick Perry’s Notice of Proposed Rulemaking, which, if adopted by FERC, would give a financial boost to Exelon’s nuclear plants (RM18-1). (See CEOs See Dollar Signs in ZECs, PJM Price Formation.)
After Exelon released its earnings, its Texas merchant generation business, ExGen Texas Power, filed for bankruptcy protection to offload most of a $675 million loan due in September 2021. The company plans to relinquish four Texas natural gas plants to lenders and pay $60 million to keep a fifth plant in response to what the company called “historically low power prices” in Texas. (See Exelon Gives up 4 of 5 Plants to Lenders in Chapter 11 Filing.)
Sempra Energy had the largest decrease in net income, dropping $565 million to $57 million, because of a California Public Utilities Commission administrative law judge’s decision denying subsidiary San Diego Gas & Electric’s request to recoup losses stemming from wildfires a decade ago. (See SDG&E’s Wildfire Costs Undercut Sempra Profits.) Although the PUC hasn’t decided whether to accept its ALJ’s ruling, accounting rules require Sempra to reflect the decision in its results. The PUC is slated to decide on the matter at its Nov. 30 meeting. Sempra has said it will appeal the decision if it’s not allowed to recover the costs.
Great Plains Energy had the largest percentage decrease in net income, falling 97.4% to $3.4 million, because of the $162.9 million it spent in its attempted acquisition of Westar Energy. Great Plains recast the deal as a “merger of equals” in August after the Kansas Corporation Commission blocked an earlier version of the deal in April. (See Great Plains, Westar File Revised Merger Plan.) Shareholders for both companies approved the revised deal on Nov. 21.
DTE Energy had the largest revenue gain, jumping $317 million to $3.25 billion, largely because of a $392 million increase in operating revenue from the non-utility operations of its energy trading unit. In percentage terms, however, DTE’s 10.8% revenue increase, was second to the 11.1% increase by CenterPoint Energy, which saw its revenue grow to $2.1 billion because of a $257 million revenue increase at its energy services segment.
AEP posted the largest revenue decrease in dollars and percentage terms, falling $547 million (11.8%) to $4.1 billion, because of what it called the mildest weather conditions in 25 years.
In a Nov. 16 memo to Commissioners Brandy Marty Marquez and Arthur D’Andrea, Public Utility Commission Chair DeAnn Walker said a pair of recent developments could place the electrical separation between ERCOT and the rest of the country “in jeopardy” by allowing energy to flow between Texas and other states through Mexico’s national grid. ERCOT has several synchronous (alternating current) and asynchronous (direct current) ties with the Mexican grid.
Walker pointed to Nogales Transmission’s application for a presidential permit to build an HVDC interconnection between Arizona and Mexico (OE PP-420). The project would consist of a 150-MW substation in Tucson Electric Power’s service territory, capable of being expanded to 300 MW; a 138-kV transmission line on the Arizona side near the city of Nogales; and a 230-kV line across the border that would connect to the Mexican grid. Nogales Transmission is a subsidiary of Dallas-based Hunt Power.
| Mexico Ministry of Energy
Walker also is concerned about an HVDC line linking the Mexican state of Baja California with the country’s central grid. That project, in the advanced planning stage, would provide a major tie between Mexico and California, which already has two connections with Baja California with a total capacity of 800 MW. In addition, California’s Imperial Irrigation District (IID) signed an agreement with CENACE, Mexico’s grid operator earlier this year, to study the exchange of up to 600 MW of energy with Baja California. IID has said the two have plans for a pair of interties to be completed in 2019 and 2020.
The Baja California system is part of the Western Electricity Coordinating Council (WECC) and not interconnected with the rest of Mexico. Sempra Energy also has a presidential permit that allows it to import renewable energy from Baja California, helping make up for the loss of the San Onofre Nuclear Generating Station.
“Those are issues that will occur outside of the United States for which the [Texas] commission will likely have no notice or participation opportunities,” Walker told Marquez and D’Andrea.
The chairwoman said FERC staff contacted the PUC “to convey concern” that the Nogales interconnection could affect FERC’s jurisdiction over ERCOT. A FERC order in 2007 noted that electricity generated within ERCOT and transmitted across a Sharyland Utilities DC tie to Mexico could not flow into WECC territory “because the Baja California system is not interconnected with the national Mexico grid,” she said.
“I’m very, very concerned about it,” Walker said. “Even if they take care of the issues in Arizona, I still have concerns about the impacts in California. We need a solution. This isn’t something we’re going to sit back and wait for it to happen.”
Nogales Transmission has asked the Department of Energy to delay processing its presidential permit until it can obtain “the necessary FERC disclaimer” of jurisdiction, Walker said.
Walker noted in her memo that FERC could exert its jurisdiction over ERCOT through the Commerce Clause of the U.S. Constitution “if the commingling of power between ERCOT and the rest of the United States occurs.”
Because ERCOT administers the Texas Interconnection — located solely within the state and not synchronously interconnected with the rest of the U.S. — FERC generally does not have jurisdiction over the ISO. There are several DC lines between Texas and other U.S. states; developers of these lines must seek a declaratory order from FERC saying they will not affect ERCOT’s independent status.
Under the Federal Power Act, FERC has no jurisdiction over transmission lines that cross international boundaries if they don’t also cross U.S. state lines.
Walker has already met with the leadership of AEP Texas, CenterPoint Energy, Oncor and Sharyland to discuss the situation. AEP and Sharyland own the state’s three DC ties with Mexico.
Walker noted the Nogales project would transmit from Arizona to the Mexican transmission system, to which Sharyland is already connected. “The change of circumstances suggests that Sharyland, ERCOT and other market participants should seek an order from FERC that they will retain their nonpublic utility status” under the FPA, Walker said.
ERCOT’s independence “is not only a source of pride, but it makes our market work so well,” Marquez said during the commission’s Nov. 17 open meeting. “We have to explore every opportunity to preserve and protect our jurisdiction.” She said she would be working with ERCOT staff to see “what types of mechanisms we can use” to protect the ISO’s independence.
State regulators and transmission customers of Southern California Edison last week urged FERC to reject the utility’s requested rate hike for 2018, saying it is excessive and unwarranted.
The California Public Utilities Commission on Nov. 17 filed a protest after SCE last month asked FERC to approve a $1.2 billion revenue requirement, including an increased return on equity, enhanced depreciation rate and an adder for its membership in CAISO.
“The CPUC opposes SCE’s proposed formula rate, which eliminates the minimal ratepayer protections contained [in] its current rate and only benefits the company’s shareholders,” the PUC said. “This proposed formula will result in unjust and unreasonable rates in 2018 and beyond and should be rejected.”
Southern California Edison asked FERC to approve an increased return on equity for its transmission facilities.
SCE requested a return on equity of 11.57%, calculated from a base ROE of 10.3%, compared with its current base ROE of 9.3%. The PUC said the utility did not provide evidence that the hike is needed and argued that its return should actually be reduced.
The state commission also disputed SCE’s claim that California is a risky investment environment, and said the 0.5% adder for participating in CAISO is a “windfall” for investors. The utility is required to be in the ISO by state law, the PUC noted.
In its application to FERC, the utility cited the growth of distributed energy resources as a challenge, and said growth in renewables — particularly at the distribution level — has driven the need for new transmission service. It also proposed an increase in its depreciation rate from about 2.54% currently to 2.73%.
“Integrating distributed generation with SCE’s transmission system is capital intensive and complicated, but it is necessary to achieve operational flexibility,” the utility said. “This energy revolution provides great opportunities but also presents a significant amount of uncertainty.”
Also asking FERC to reject the rate hike was a group representing 27 public agencies that hold contracts with the California Department of Water Resources to supply water for drinking, commercial, industrial and agricultural purposes. The group challenged SCE’s “proxy group” — a collection of similarly positioned electric companies — used to determine fair rates, as well as the base ROE.
California water agencies are protesting Southern California Edison’s proposed transmission rate hike.
The state water contractors said that a large number of the capital investments for which SCE wants to recover costs “have been unilaterally approved by SCE management in contravention of the requirements of [FERC] Order No. 890 to develop local transmission plans in an open and transparent planning processes.”
The group asked FERC to establish hearing and settlement procedures over SCE’s request.
The Los Angeles Department of Water and Power filed a separate protest saying the ROE is “dramatically overstated.” The ROE should be no larger than 8%, the agency argued in its protest. The department also protested that the utility’s proposal allows for executive bonuses to derive from transmission rates.
Other parties opposing the rate hike include the DWR; the City of Santa Clara and MSR Public Power Agency; and the cities of Anaheim, Azusa, Banning, Colton, Pasadena and Riverside.
