FERC has given an unconditional thumbs-up to resource-aggregation rules for PJM that staff conditionally approved last year when the commission lacked a quorum (ER17-367).
The order officially approves rule changes PJM filed in November 2016 to allow seasonal resources to aggregate across locational delivery area borders, along with methodology changes to better account for demand response and wind performance in the winter. The new rules were implemented in time for last year’s Base Residual Auction, the first requiring all resources meet tougher Capacity Performance standards. (See PJM Outlines Aggregation Rules for Upcoming Capacity Auction.)
The commissioners affirmed staff’s decision without any changes, dismissing multiple protests. Throughout the order, the commission acknowledged that other strategies could work but that there were no compelling arguments for why PJM’s plan failed the “just and reasonable” standard.
The RTO argued to relax the rules prohibiting seasonal resources from aggregating across LDAs because they inhibit “what otherwise would be considered logical pairings” of resources that perform much better in one season compared to others, such as solar in the summer and wind in the winter. The rules model the aggregated resource in the lowest common tier of the LDA hierarchy, which could be RTO-wide; the resource would receive the corresponding LMP as compensation.
PJM’s example for how it will aggregate seasonal resources in different LDAs. FERC has unconditionally approved PJM’s plan. | PJM
Opponents argued that the changes would interfere with accounting for a variety of factors, including reliability, resource adequacy and compensation. FERC denied all the protests, agreeing with PJM that the resources will remain responsible for actions in their individual LDAs, such as paying penalties during penalty-assessment intervals. The order approves PJM’s creation of a new mechanism called “RPM aggregation,” along with defining summer- and winter-only resources that submit offers for only half of the year.
Winter CIRs
FERC also approved PJM’s plan for modifying how it calculates winter-period capacity interconnection rights (CIRs) and dismissed multiple protests, allowing wind resources to put substantially more onto the grid. The commission agreed that the previous methodology, which relied on resources’ performance in the summer, grossly understated wind’s potential in the winter production, typically granting them the rights to inject just 13% of their nameplate capacity regardless of actual production.
Opponents argued that the changes will give resources rights to use more infrastructure than they paid for, but the commission agreed with PJM’s guarantee to prevent infringement on other resources’ available system capabilities as well as overwhelming the system’s existing topology.
PJM also sought to eliminate rules that limited how DR resources measured performance in the winter. The approved changes allow curtailment service providers to specify either a seasonal load cap resources are willing to commit if called upon or a firm amount of demand the resources are willing to drop in each season if dispatched by PJM.
“Specifically, PJM states that stakeholders are concerned that customers with winter load that reduce their load prior to PJM dispatch may not be recognized by PJM as having performed consistent with the Capacity Performance rules,” the order explains. “PJM … will ensure that customers with winter load consume electricity at a lower level when dispatched by PJM for an emergency or pre-emergency load management event, and that customers without winter load will not receive credit under the Capacity Performance rules for a load reduction just because they do not have load in the winter.”
WILMINGTON, Del. — Stakeholders remain reticent to cede too much command and control to PJM, voting at last week’s Markets and Reliability Committee meeting to defer a vote on revisions to Manual 14D because they felt the requirements for generation owners to submit ownership-transfer information were too strict.
GT Power Group’s Dave Pratzon said the changes could make it impossible for generators to meet PJM’s deadlines. (See “Owner Transfer Rules Revision,” PJM Operating Committee Briefs: Dec. 12, 2017.)
“The problem the generator owners have when they’re negotiating these deals is primarily timing. The timing set forth by PJM is not necessarily viable,” he said. “Certain information PJM needs may not have been negotiated in time to meet PJM’s deadline.”
Deals often need to be more fluid than PJM’s deadlines allow. “We feel the manual also needs to recognize commercial realities,” he said. He said one of his clients supplied him with a “page-long list” of issues and asked for more time to negotiate language changes before an endorsement vote.
PJM staff said there is a clause that allows staff to waive the requirements for more flexibility, but that the final five-day deadline can’t be adjusted.
“For those five days, we need to be sure that we have our units where they need to be in our system,” PJM’s Rebecca Stadelmeyer said.
However, Pratzon was not alone.
“We have similar concerns about the commercial reality,” EDP Renewables’ John Brodbeck said.
“The way it’s written right now, it looks like if [PJM doesn’t] feel like it, you won’t have to [provide the waiver],” Calpine’s David “Scarp” Scarpignato said.
Members subsequently agreed by acclamation to defer the vote. It will go back to the Operating Committee for reconsideration.
Members also deferred endorsement of a joint plant from PJM and MISO to address overlapping congestion charges for pseudo-tied resources. The decision came after PJM’s Tim Horger confirmed that consideration of the proposed Tariff and Operating Agreement (OA) changes could wait until next month’s meeting and still meet staff’s timeline.
“Ideally, we would file by the end of March,” Horger said.
PJM and MISO have been working to remove repetitive congestion charges and have developed a two-phase plan to eliminate them. These changes encompass the second phase. (See MISO, PJM Pursue Pseudo-Tie Double-Charge Relief.)
Carl Johnson, who represents the PJM Public Power Coalition, asked for clarification on a concern that certain market-to-market payments could simply be canceled under the rule. Horger said the payments are automatically created based on the pseudo-ties in the system and that he wasn’t aware of any concerns on that issue.
Johnson said he would research the topic further, and American Municipal Power’s Steve Lieberman asked if the endorsement vote could be delayed to address the question. To make the requested timeline, stakeholders must vote on the changes at both the MRC and Members Committee meetings next month.
OVEC Integration Set
Staff announced that the Ohio Valley Electric Corp.’s Board of Directors voted to change its date for integration into PJM from March 1 to June 1. (See FERC OKs OVEC Move to PJM.)
Staff also announced later in the day the cancellation of proposed transitional auction revenue rights for OVEC’s two coal-fired power plants. OVEC’s integration adds 705 miles of 345-kV transmission lines and 2,200 MW of capacity to PJM’s footprint.
Staff and transmission owners disagreed with customer representatives on how much change FERC recently ordered to PJM’s process for supplemental transmission projects. (See FERC Orders New Rules for Supplemental Tx Projects in PJM.)
PJM’s Steve Herling said the commission’s instructions call for more detailed delineation of how stakeholders can engage as TOs develop their supplemental projects.
“The bottom line is there’s a very short clock on the compliance filing,” he said, but the orders “seem to be relatively straightforward.”
Greg Poulos, executive director of the Consumer Advocates of the PJM States, said the order’s language “really raised a lot of alarms for me” and appeared to demand much more drastic changes.
“I’m reading this as FERC saying we’re going to tell you what to do because you’re not going in the right direction,” he said. “I was really hoping to see PJM do more than just the minimal amount that FERC orders transmission owners to do going forward.”
“Most of my read of the order was just to be more clear about” details and expanding access by adding more meetings, Herling said. “That’s the part that I think is going to be really straightforward to implement.”
“My reading of that is that the process has failed. And I don’t know that putting some more meetings in there addresses that,” Poulos responded.
Stakeholders agreed to further discuss the order’s implications at next month’s Planning Committee meeting.
Stakeholders Approve Variety of Actions
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Manual 11: Energy & Ancillary Services. Clarifies the energy offer verification process for demand-side bids, including caps on price-sensitive demand bids and eliminating certain restrictions on bids from curtailment service providers for pre-emergency and emergency demand response.
Manual 18: PJM Capacity Market. Revisions developed to adhere to a FERC compliance filing on rules for pseudo-tie requirements and a transition period for existing pseudo-ties.
A draft charter for the Summer-Only Demand Response Senior Task Force. The task force, which was developed to consider ways to take advantage of excess summer-only resources, has met several times. (See Stakeholders Seek Load Discussion in PJM DR Task Force.)
Members agreed to sunset the Underperformance Risk Management Senior Task Force (URMSTF) and the Regulation Market Issues Senior Task Force (RMISTF). The URMSTF developed proposals on underperformance risk management, which failed to receive MRC stakeholder endorsement, and changes to external Capacity Performance requirements, which was endorsed. The RMISTF resulted in implementation of a new regulation signal, along with a package of regulation procedure and requirement changes. (See PJM Regulation Compensation Changes Cleared over Opposition.)
A former California utilities regulator and political insider has been fined after state investigators determined that she failed to register as a lobbyist for ride-sharing company Lyft and San Gabriel Valley Water Co., an investor-owned public water utility.
Kennedy | Linkedin
In a 5-0 decision Feb. 15, the California Fair Political Practices Commission fined former California Public Utilities Commissioner Susan P. Kennedy $32,000 for failing to register as a lobbyist and file quarterly reports from late 2012 to early 2014, when she worked to influence the commission on behalf of the two companies.
Kennedy was chief of staff for former Gov. Arnold Schwarzenegger, deputy chief of staff and cabinet secretary for former Gov. Gray Davis, and previously communications director for U.S. Sen. Dianne Feinstein. She served on the CPUC from 2003 to 2006 and now helms energy storage company Advanced Microgrid Solutions, which was not named in the matter.
At a Feb. 15 meeting in Sacramento, FPPC Chair Joann Remke congratulated her enforcement staff for the investigation, saying lobbying cases are “difficult to prove” and are “few and far between.”
“And I know this was a long investigation and a good outcome,” Remke said.
The state’s Political Reform Act of 1974, the post-Watergate ballot measure that created the FPPC, requires lobbyists and lobbying firms to register with the Office of the Secretary of State and file quarterly reports on their clients, their clients’ interests and how much they were paid.
In the case of San Francisco-based Lyft, Kennedy was able to influence the CPUC beginning in 2012 to open a rulemaking over ride-sharing companies, according to the order. The commission was scrutinizing ride-sharing companies and had previously sent Lyft a cease-and-desist letter in August 2012 because it had not received operating authority.
The decision says Kennedy contacted then-CPUC President Michael Peevey, Executive Director Paul Clanon and other CPUC staff to convince them to work with ride-sharing companies rather than shut them down. The commission opened a rulemaking to address public safety issues and in September 2013 adopted regulations concerning liability insurance, driver licensing and background checks, driver training programs, vehicle inspections and data reporting.
“The efforts of Kennedy and Lyft were successful as the resulting rules and regulations adopted many of the suggestions and positions put forward by Kennedy and Lyft during the rulemaking process,” the decision says.
Kennedy also lobbied Peevey and current CPUC President Michael Picker in the first half of 2014 regarding San Gabriel, the FPPC said. The utility had a general rate case before the commission and was seeking to increase water rates, which were being fought by the city of Fontana and its school district.
“During these meetings, and through emails, Kennedy sought to influence the CPUC’s decision on cost recovery for the Sand Hill treatment plant in the general rate case,” the decision says. The commission sided with Fontana and denied the rate increase and cost recovery for the plant in May 2014 (Decision#15-11-028).
“The CPUC’s decision invalidated much of a settlement San Gabriel had with the CPUC’s Office of Ratepayer Advocate. Subsequently, the CPUC issued a decision on Nov. 24, 2015, that included a modified rate increase agreed upon by all parties,” the FPPC decision says. San Gabriel filed lobbying reports that listed other lobbyists but not Kennedy.
Under terms of the settlement with the FPPC, Kennedy agreed to register Susan P. Kennedy Inc. as a lobbying firm. She also filed reports detailing that she was paid $76,500 by Lyft and $125,000 by San Gabriel.
Kennedy was paid $201,500 by Lyft and San Gabriel Valley Water Company, the CFPPC said | California Fair Political Practices Commission
“While Kennedy maintains she did not intend to qualify as a lobbyist, given her experience and sophistication, she should have been aware at the time that her activity qualified as lobbying,” the decision says.
“Ms. Kennedy moved immediately once the discrepancy was identified to provide the necessary information requested by the FPPC. Integrity and character are hallmark principles in how Ms. Kennedy conducts herself in business, which is why she acted swiftly to resolve the matter,” Kennedy’s attorney James Harrison, of Remcho Johansen & Purcell, said in an email to RTO Insider.
FPPC spokesman Jay Wierenga told RTO Insider that the decision wraps up the commission’s investigation of Kennedy. “There is nothing more on our side regarding any investigation of Kennedy,” he said. “This case is complete.”
The CPUC did not immediately respond to a request for comment on the decision.
The FPPC information request to Kennedy that led to the recent fine also asked for communications between her and other CPUC members regarding the San Bruno gas pipeline explosion and legal, legislative or regulatory actions that might have resulted from them. But the Feb. 15 FPPC decision does not mention anything about the San Bruno communications.
The request had also asked for communications between Lyft and Manal Yamout, a partner with Kennedy in Advanced Microgrid Solutions and Caliber Strategies and a former top adviser to Schwarzenegger and Gov. Jerry Brown. The decision and fine handed down by the FPPC did not mention Yamout.
Attorney General Referral
At the FPPC’s Feb. 15 meeting, Chief of Enforcement Galena West noted that the state’s attorney general had referred the Kennedy investigation to her group. The attorney general’s office did not respond to a request for more information on what spurred the referral.
Pacific Gas and Electric in September disclosed new emails of discussions between Kennedy and former PG&E executive Brian Cherry that described “back-channel” communications between the utility and CPUC members regarding the 2010 San Bruno incident that killed eight people. (See Probe Reveals More CPUC-PG&E Contacts on Pipeline Blast.)
The disclosure of the old Kennedy emails and others came as the CPUC was poised to approve an $86 million settlement with PG&E over previously disclosed improper communications with it regarding the accident. The commission at its November meeting delayed a vote on the settlement until June. (See Besieged CPUC Denies SDG&E Wildfire Recovery.)
The 2010 San Bruno fire.
In delaying the settlement, the CPUC said additional time was needed after parties to the settlement asked for a second phase of the proceeding to explore whether PG&E had engaged in any additional ex parte communications.
“Once a second phase is opened, time will be needed for the parties to address, and for the commission to decide, if PG&E committed any additional ex parte violations,” the CPUC said in the order delaying the vote.
The ex parte case is separate from the $1.6 billion fine, refund orders and gas system improvements the CPUC levied on PG&E for the fatal explosion and fire, record-keeping and safety violations.
FERC last week granted SPP’s request to waive its one-year resettlement window so that the RTO can correctly bill transmission-upgrade customers for a month mistakenly omitted from invoices. The commission said SPP’s request satisfied its waiver criteria, and that the RTO had acted “in good faith” to calculate the corrected transmission revenue credits amounts and “ensure that customers’ bills are accurately resettled” (ER18-381).
FERC rejected Xcel Energy’s contention that SPP had failed to show that there are no undesirable consequences. The commission noted SPP said it alerted stakeholders it needed to correct the settlements. “Therefore, stakeholders have been on notice of and expected the planned corrections,” FERC said.
SPP said the waiver would allow it to include September 2016 billable amounts under Attachment Z2 of its Tariff, which assigns financial credits and obligations for sponsored transmission upgrades. SPP said in November that it had inadvertently omitted resettled amounts from September 2016 in its November 2017 invoices, placing the month outside the Tariff’s resettlement requirements. (See SPP Invoices Lead to Confusion on Z2 Payments.)
The cut in federal corporate income taxes figured prominently in fourth quarter earnings reports by OGE Energy, CenterPoint Energy and Entergy last week. The Tax Cuts and Jobs Act of 2017, signed into law by President Trump in December, reduced corporate income taxes to 21% from 35%.
Tax Savings Result in Positive Earnings for OGE
OGE said last week that the tax legislation was a major factor as the company reported 2017 earnings of $619 million ($3.10/share), almost double the previous year’s performance of $338.2 million ($1.69/share).
For the quarter, OGE reported net income of $294.8 million ($1.48/share), compared to $57.9 million ($0.29/share) for the same period in 2016.
Trauschke | OGE
In a conference call with analysts, OGE CEO Sean Trauschke said $49.3 million in federal tax breaks contributed to much of the increase.
“For us, tax reform is a positive,” Trauschke said during the Feb. 22 call. “Tax reform will be beneficial to our customers and accretive to shareholders of OGE. We worked hard to maintain a strong financial position that gives us this flexibility and helps us weather financial challenges that may come.”
The tax savings will be a factor as OGE’s electric utility, Oklahoma Gas & Electric, works its way through current and planned rate cases before the Oklahoma Corporation Commission. The utility requested a $72 million increase last year to recover the installation of new gas units at its Mustang Energy Center but projects the tax benefits will be used to account for much of that increase.
OG&E also plans to file a rate case later this year to cover the cost of coal scrubbers at its Sooner plant. A third rate case will likely be filed in 2019 for smart grid upgrade costs.
“We delayed our [Sooner] filing from late December to ensure customers benefited from the lower tax rate,” Trauschke said.
OG&E reported a gross margin of $1.36 billion for the year, down $16 million from 2016, because of unfavorable weather that was partially offset by new customer growth. However, the utility’s net income was up $22 million to $306 million because of lower depreciation and amortization expenses and an increase in funds used during construction of the Mustang Energy Center and environmental compliance projects.
OGE stock gained $2.13/share following its Feb. 21 close to finish the week $32.95/share.
CenterPoint Energy Records $1.1B Tax Benefit
The corporate tax cuts resulted in a $1.1 billion benefit to CenterPoint, which reported year-end earnings on Feb. 22 of almost $1.8 billion ($4.13/share), up from $432 million ($1/share) for 2016. Excluding the tax benefit, earnings were $593 million ($1.37/share).
For the quarter, the Houston-based company reported a net income of nearly $1.3 billion ($2.99/share), compared to $101 million ($0.23/share) over the same period last year. Excluding the tax benefit, earnings were $141 million ($0.33/share).
| CenterPoint Energy
The Public Utility Commission of Texas wants to bring CenterPoint in for a comprehensive rate case, which would be its first in eight years. The company recently filed terms of a settlement it reached with PUC staff and other parties, and has agreed to a base rate case that would be filed no later than April 2019.
CenterPoint shares gained $1.50 following the earnings announcement, finishing last week up 5.7% at $27.23/share.
Entergy Beats Expectations, as Losses Narrow
Entergy beat Wall Street expectations by reporting fourth-quarter operating earnings of $137.6 million ($0.76/share) on Feb. 23, almost double the Zacks Investment Research consensus estimate of 42 cents/share.
When adjusted for higher expenses for nuclear operations and the write-down of tax assets not subject to the ratemaking process, Entergy reported a GAAP earnings loss of $479.1 million (-$2.66/share). Still, that was a marked improvement from the loss of $1.77 billion (-$9.88/share) for the same period in 2016.
For the year, the New Orleans corporation reported earnings of $411.6 million ($2.28/share), compared to losses of $583.6 million (-$3.26/share) in 2016.
Entergy also initiated 2018 consolidated operational guidance of $6.25 to $6.85/share, assuming “balanced regulatory treatment for the recently enacted tax reform legislation,” the company said in a statement.
| Entergy
CEO Leo Denault told analysts Friday the impact of the tax changes will be discussed in rate filings the company plans in each of its jurisdictions this year. “On an ongoing basis, the lower tax rate means that customer bills will be lower than they otherwise would have been. That’s important to us as evidenced by the fact that our rates are among the lowest in the country,” Denault said. “We expect [that] point to be addressed in the normal course of those proceedings.”
The Louisiana Public Service Commission on Wednesday ordered its staff to report back by March 21 on a recommendation for flowing the tax savings to ratepayers.
“As we look ahead to the next three years, our success continues to be less dependent on strategic initiatives and more on our own operational execution,” Denault added.
Investors reacted by driving up Entergy’s share price 3.7% to $77.74.
FOLSOM, Calif. — CAISO’s latest transmission plan recommends cutting more than $2.7 billion from current transmission spending estimates across the 2027 planning horizon.
The ISO is preparing its 2017-2018 transmission plan for approval by the Board of Governors next month, launching the procurement phase of a process heavily influenced by expanding behind-the-meter solar generation. Board approval kicks off the processes for procuring transmission and determining eligibility for incentive rate cost recovery from FERC by virtue of being part of a state plan.
Speaking at the Western Planning Region Interregional Transmission Coordination Meeting on Feb. 22, CAISO Executive Director of Infrastructure Development Neil Millar said the plan represents about $160 million in capital spending, but there is currently more of an emphasis on project cancellation.
The plan “really did require hitting the reset button and a major re-planning effort for a number of those previously approved projects,” he said. The planning process is “in a pause waiting for state policy guidance on higher levels of renewable penetration.”
In a discussion later, Millar added that “we are trying to fit a bit of a square peg in a round hole” by using the interregional process as a potential way to bring renewables into California, “which is beyond the scope of what the interregional process was designed for.”
As a supplement to its 2016-2017 transmission planning process, CAISO in January issued a study noting that California faces a “severe shortage” of transmission capacity needed to tap potential New Mexico and Wyoming wind resources that would help the state meet its 50% renewable portfolio standard. (See CAISO: Tx Constraints Hinder Out-of-State Wind.)
The ISO’s 2017-2018 reliability analysis led to recommendations for 12 new transmission projects, but it is also recommending cancellation of 19 projects in the Pacific Gas and Electric service territory and rescoping of 21 others, accounting for the more than $2.7 billion in reductions. Six need further review, and two previously approved projects in San Diego Gas & Electric’s territory are recommended for cancellation. CAISO prioritizes regional and local reliability needs first, then state policy, followed by economic analysis, according to an ISO presentation.
“Reliability issues are largely in hand, especially with load forecasts declining from previous years and behind-the-meter generation forecasts increasing from previous projections,” CAISO said.
CAISO works closely with the California Energy Commission, which provides demand forecasts and resource needs assessments for the transmission planning process while the ISO creates a transmission plan. The California Public Utilities Commission oversees procurement, with input provided by the CEC, the ISO, investor-owned utilities and others. Included in the plan is a reliability analysis for NERC compliance, transmission needs for a 33% RPS and other analyses.
The ISO is conducting sequential technical studies that will result in a draft transmission plan and is targeting March approval by the board to initiate procurement. It posted its draft plan on Feb. 1, with stakeholder comments due this week. The 2017-2018 plan was originally introduced in early 2017.
New Jersey lawmakers on Thursday once again voted to advance legislation out of committee that would provide subsidies to the state’s nuclear fleet.
A previous effort foundered earlier this year when a key lawmaker declined to post a similar bailout bill for a vote before the close of a lame duck session. (See NJ Lawmakers Pass on Nuke Bailout in Lame Duck Session.)
Salem & Hope Creek Nuclear Power Plants | Green Delaware
But this time, the Assembly Telecommunications and Utilities Committee (A2850) and the Senate Budget and Appropriations Committee (S877) approved bills that also contain incentives for renewables and energy efficiency, including a provision in the Senate bill that would sharply increase the state’s renewable portfolio standard to 35% by 2025 and 50% by 2030.
The nuclear portion of the legislation remains identical to previous versions: Nuclear plants that the Board of Public Utilities finds economically unviable would receive funding through a 0.4-cent/kWh charge on ratepayers’ bills.
During a nearly four-hour joint hearing of the committees, opponents of the legislation urged lawmakers to slow down and allow the board and the Division of Rate Counsel to study the disparate nuclear and renewable components of the bills and their impact on ratepayers. They criticized the rush to pass the nuclear subsidies, asserting that the renewable elements of the legislation were included without enough consideration.
“This is complex stuff,” said Sarah Bluhm of the New Jersey Business and Industries Association. “I think we really have to take a step back, because what we’re missing from this is comprehensive planning.”
Dennis Hart, executive director of the Chemistry Council of New Jersey, expressed concern that the group’s member companies that built their own onsite solar facilities and set their own energy-efficiency standards would be paying more under the legislation. Along with several other speakers, he noted that it took Illinois and New York several years to enact their zero-emission credit programs.
“The BPU clearly needs to study the issue to assess the need for a subsidy before the process even starts,” said Scott Ross of the New Jersey Petroleum Council. “In particular, we believe the New Jersey Rate Counsel should have a seat at the table during these meetings.”
Legislators who voted against the bills expressed similar sentiments.
“I support the nuclear power plants, but there’s way too many unknowns,” Assemblyman Harold Wirths said.
“There’s way too much in this bill that it’s impossible for the ratepayers to follow what’s going on,” said Assemblyman Edward Thomson.
A full vote on the Senate bill had already been scheduled for Monday, but senators ended up shelving it until at least next month. “It’s a big bill. It’s a complicated bill. And we’re going to continue to press forward,” Senate President Steve Sweeney (D), the primary sponsor of the bill, told The News & Observer. “Like everything else, we’re adjusting things and look forward to getting it passed.”
The New York Public Service Commission on Thursday ordered the state’s utilities to open participation in their “value stack” programs to distributed energy resource projects up to 5 MW, more than doubling the current 2-MW limit starting April 1.
“Our decision to expand the size of the projects eligible for compensation will further reduce costs and spur the development of solar power, energy storage and other localized forms of electric generation,” PSC Chair John B. Rhodes said.
“I don’t believe there were discussions with the ISO about this specific increase,” DPS Assistant Counsel Ted Kelly said. “Projects of this size already are covered by utility interconnection rules rather than ISO interconnection rules, so that’s not a change, and also would generally be covered by utility compensation policy, currently by the buyback rate, or in some cases, for some small hydro producers, by long-term contract with the utility.”
The commission last month also approved implementation of the fourth tranche in its VDER tariff, continuing the transition of DER away from NEM.
The DPS’ consumer advocate, the Utility Intervention Unit, expressed concerns about expanding eligibility while a rehearing petition challenging those regulations is pending.
However, the commission ruled that because it was not increasing the total capacity allocation for community distributed generation resources, its order “will not increase the total potential customers for DER suppliers, nor is there any reason to believe it will result in longer contracts than would otherwise be employed.”
PSC OKs Con Ed Energy Storage Tariff
The commission last week also approved amendments to Consolidated Edison’s tariff intended to increase the ability of energy storage to export power to the utility’s primary and secondary voltage distribution systems, but it ordered the utility to clarify vague language that “may lead to unnecessary disputes between customers and the company.”
Con Ed’s changes will broaden the definition of energy storage beyond batteries to include flow batteries, flywheels, compressed air systems and other technologies. The utility will also expand the ability for energy storage systems to participate in any non-wires alternative project, instead of a few specific projects such as the Brooklyn-Queens Demand Management program.
Energy storage technologies equipped with inverters will be allowed to export to either the secondary or primary voltage distribution system, whereas non-inverter-based technologies will be limited to exporting to the primary voltage system.
Standalone energy storage systems will be excluded from earning the reliability credit applicable to standby service customers, which is designed to compensate customers for offsetting their native load.
In response to concerns by the New York Battery & Energy Storage Technology Consortium that standalone energy storage systems would be charged retail rates for charging and wholesale rates for discharging, the commission ruled those issues will be considered as part of Phase II of the VDER proceeding.
Gov. Andrew Cuomo last month announced his clean energy jobs and climate agenda, which includes directing NY Green Bank to invest $200 million toward meeting an energy storage target of 1,500 MW by 2025. In November, Cuomo signed legislation requiring the commission to establish targets for energy storage by early 2018.
The New York State Energy Research and Development Authority is also this year investing at least $60 million in storage demonstration projects. (See Cuomo Pushes Clean Energy in Annual Address.)
Padula | NY DPS webcast
Burman reiterated her concerns about the VDER expansion, asking whether DPS staff had done their own analysis or had “reached out to the ISO in terms of the recent cases with FERC as it relates to the wholesale market, energy storage and the DER issues.” She also asked how the Con Ed order would affect the recent state bill on energy storage and its pending amendments.
“We are in continuous discussion with the ISO related to their roadmap in addition to our own development of a storage roadmap, so it’s ongoing,” said Marco Padula, DPS deputy director for market structure. “This is one piece of the puzzle. It’s a very complicated puzzle, but this is one step in a very positive direction of enabling storage to connect to the grid.”
PSC Accepts OSW Environmental Impact Statement
The PSC also resolved that, as lead agency, it has completed and accepted a draft generic environmental impact statement for a state-mandated program (18-E-0071) to procure 2.4 GW of offshore wind energy by 2030. Public comments on the draft will be accepted by the commission until April 9.
NYSERDA in January issued a master plan for offshore wind and filed a policy paper with the commission proposing two initial offshore wind procurement rounds of 400 MW, one each in 2018 and 2019.
The master plan projects that the full deployment of offshore turbines by 2030 would reduce greenhouse gas emissions by more than 5 million short tons, or approximately one-third the expected reductions from new renewable energy projects developed to meet the 50% renewable electricity target under the state’s Clean Energy Standard. (See NY Offshore Wind Plan Faces Tx Challenge.)
Rienzo | NY DPS webcast
Thomas Rienzo, DPS chief of clean energy programs, said that NYSERDA’s policy paper does not propose development of a particular offshore wind generation facility or site. However, he said the paper does include various program and financing options intended to broadly apply to the development of multiple projects over time in different locations, which will result in installation of 2.4 GW of offshore wind able to deliver electricity by 2030.
“Since these options are strictly financial, the environmental impacts are not expected to vary among the options presented,” Rienzo said.
Rhodes said, “Moving forward to enable offshore wind that is appropriately sited and in careful consideration of environmental impacts is critical to achieving the state’s vital clean energy goals.”
PSC Orders Revision to ZEC Calculation for LSEs
The PSC on Thursday ordered NYSERDA to suspend 64.4% of energy service company Astral Energy’s zero-emission credit (ZEC) obligation for the April 1, 2017, to March 31, 2018, compliance period. It also directed NYSERDA and DPS staff to modify the way in which load-serving entities remit ZEC payments.
The commission’s Feb. 22 order directed that ZEC obligations no longer be based on a fixed-fee payment structure calculated from each LSE’s historic share of the statewide load, but rather on a flexible, “pay-as-you-go” model based on each LSE’s actual load.
Astral twice petitioned the PSC for relief, saying in January 2018 that its load had dropped a total of 64.4% since the 12-month period used to calculate each LSE’s percentage of total load, in turn reducing its ZEC obligation. The company argued that, as a result, the number of ZECs it was required to purchase for the current compliance year created a financial burden without reasonable compensation.
Although the overpayment would ultimately be refunded through the true-up process, Astral said that it nonetheless represented a substantial burden, as it was being required to bear an interest expense not borne by other LSEs.
In approving the order, Rhodes said, “This item is an important example of our approach to managing our policy-driven programs, particularly the aspect where we adjust the mechanics of their implementation as circumstances change, and … in a manner that’s consistent, predictable and pragmatic.”
In August 2016, the commission adopted the Clean Energy Standard, which requires LSEs, including ESCOs, to purchase ZECs from NYSERDA in order to preserve existing zero-emission nuclear generation resources.
The commission’s Nov. 17, 2016, order approving cost recovery in the same proceeding required all LSEs to enter into contracts with NYSERDA for the purchase of renewable energy credits (RECs) and ZECs monthly, beginning Jan. 1, 2017, for RECs and April 1, 2017, for ZECs.
Public Service Enterprise Group CEO Ralph Izzo expressed confidence Friday that his company’s five nuclear units will receive the price supports he contends they need to keep them running.
Speaking during PSEG’s fourth-quarter earnings call, Izzo said he was pleased with the progress of New Jersey legislation to support the three reactors the company operates in the Garden State (A2850, S877), but he cautioned that the bills’ fate isn’t guaranteed. (See related story, NJ Lawmakers Advance Latest Nuke Subsidy Bills.)
Izzo also said he expects PJM’s response in FERC’s resilience proceeding to include a proposal to allow large, inflexible generation like nuclear units to set LMPs rather than seek out-of-market “uplift” cost recovery (AD18-7). “There have been very public conversations and statements by PJM that they believe, in particular, [that] their inflexible unit challenges are things that need to be corrected in the market,” he said.
Fourth-Quarter Rebound
PSEG reported net income of $956 million ($1.88/share) in the fourth quarter of 2017, compared to a loss of $98 million (-$0.19/share) in the same quarter a year prior. Its non-GAAP operating earnings were $289 million ($0.57/share), which beat the Zacks Investment Research consensus estimate by a penny and were up from $279 million ($0.54/share) the year before. PSEG’s revenue in the fourth quarter of 2017 was $2.1 billion, less than the Zacks consensus estimate of $2.36 billion, but slightly more than the $2.09 billion the company posted in the fourth quarter of 2016.
“We ended 2017 on a strong note with operating earnings for the year above the midpoint of our guidance,” Izzo said in PSEG’s earnings release. “The recent action by the board of directors to increase the common dividend by 4.7% to the indicative annual rate of $1.80/share is recognition of our financial strength and commitment to growth.”
PSEG enters 2018 “from a position of financial strength aided by a strong balance sheet, continued execution of our strategic growth objectives and tax reform,” Izzo said. “This is possible, despite the challenges we continue to face in wholesale power markets, especially at our nuclear plants.”
Public Service Electric and Gas, the company’s regulated electric and gas utility, was responsible for two thirds of PSEG’s non-GAAP operating earnings. “Despite the challenges we continue to face in the wholesale markets, especially at our nuclear units, the continued successful investment in regulated programs have provided reliability and quality service to our customers,” Izzo said.
Warnings on Nuclear Plants
Izzo’s rosy words about the company’s financial state were tempered by his warnings about the state of its nuclear operations: three generation units at Hope Creek Generation Station and Salem Nuclear Generation Station in New Jersey and two units at Peach Bottom Atomic Power station in Delta, Pa. PSEG shares ownership of Peach Bottom and Salem with Exelon.
PSEG CEO Ralph Izzo is confident his company’s nuclear plants will get support. The Salem Nuclear Generating Station is one of three nuclear power plants PSEG has stakes in.
The fleet had a capacity factor of 93.9% in 2017 and produced a record electric output of 31.8 TWh, up almost 8% from 29.6 GWh in 2016. But PSEG says its New Jersey nuclear units are profitable now only because of sales hedges that expire within two years.
The bills being considered by the New Jersey Legislature would make Salem and Hope Creek eligible for subsidies from a 0.4-cent/kWh charge to the state’s electric ratepayers if the Board of Public Utilities finds the units economically unviable.
Critics of previous versions of the bills have complained that PSEG hasn’t demonstrated that its nuclear plants are unprofitable.
Izzo insisted the legislation is needed and that the company will pull the plug on its nuclear plants if it isn’t passed.
“The loss of the approximately 32 TWh of clean electric energy produced by [PSEG’s] Power [unit’s] nuclear generation in 2017 would represent a severe setback to [New Jersey’s] ability to meet its clean-energy goals and result in crushing economic impacts due to resulting increases in electricity prices and major job losses,” Izzo said.
“But the risk of closure remains without a change in the financial condition of nuclear. To that end, Power recorded a $276 million increase in its asset retirement obligation liabilities at the end of 2017 to take into account a higher assumed probability of early retirement of its nuclear units.”
Izzo also was optimistic about other efforts that could increase the nuclear plants’ revenue.
“There’s multiple things going on at FERC that matter [to] PJM,” Izzo said in response to a question from an analyst. “There’s capacity market reform, there’s fast-start pricing, there’s price formation. So there’s multiple issues. … I think we’re all visiting with the commissioners and telling them how important it is. And I think we’re all seeing the same comments come out of PJM.”
PJM Stakeholders Debate Resilience Filing
At a special session of PJM’s Markets and Reliability Committee on Friday, stakeholders battled over what PJM’s response should be to FERC’s questions on resilience. Nuclear and coal proponents argued for rule changes on price formation and payments for “fuel diversity,” which would benefit aging coal and nuclear plants. Customers argued that fuel diversity should not be considered synonymous with resilience. PJM has until March 9 to file its comments.
FERC’s five commissioners all recently voiced their commitment to scrutinize any proposals purporting to address resilience. “It seems to me … that some RTOs are suggesting things that don’t necessarily [relate] to resilience,” Commissioner Richard Glick said at the National Association of Regulatory Utility Commissioners’ winter meetings on Feb. 13. (See Overheard at NARUC Winter Policy Meetings.)
FERC last week approved PJM’s proposal to reduce by almost 90% the number of bidding locations for increment offers (INCs), decrement bids (DECs) and up-to-congestion transactions (UTCs) (ER18-88).
Known as virtual transactions, these trades can be used to arbitrage price differences between the day-ahead and real-time markets and hedge financial exposure to physical positions. PJM contends that while the trading can mitigate supply-side and demand-side market power by allowing those without physical assets to compete with asset owners and load-serving entities, too many of the trades provide no benefit to the market and can increase market solution times and skew transmission flows.
PJM says more than 95% of UTCs offered into the market between 2012/13 and 2014/15 were at a price between +/- $10/MWh and more than half of the trades fell between +/- $1/MWh. The RTO said this trading pattern is “indicative of the low-risk positions that can be extremely lucrative without adding commensurate value to the market.” | PJM
Following a white paper published in 2015, the RTO won Members Committee approval for the changes in June. (See “Stakeholders Endorse Third Phase of PJM’s Uplift Solution Despite Opposition,” PJM MRC/MC Briefs: June 22, 2017.)
PJM’s proposal, filed last October, asked FERC to limit INCs and DECs to nodes where either generation, load or interchange transactions are settled, or at trading hubs where forward positions can be taken. The RTO said this would ensure the day-ahead market produces a resource commitment close to the set of resources required for real-time operations.
The changes reduced the number of INC/DEC trading nodes from 11,727 to 1,563, retaining all hub and interface nodes but eliminating some aggregate and generator nodes. Also retained were residual metered nodes — locations at which load settles the remaining portion of a zone that is not settled at a more granular aggregate location.
The new rules also eliminate zone, Extra High Voltage (EHV) and individual load nodes as trading points for both UTCs and INCs/DECs. Also barred from UTC trades are some interface nodes, while the number of eligible residual metered and hub nodes was increased. In total, the number of UTC trading points was reduced to 49 from 418.
Under the former rules, PJM said, some traders took very small, low-risk positions in the day-ahead market over weeks waiting for a single path to bind in real time. Others bid at locations with systematic price differences between the day-ahead and real-time markets because of a modeling difference between the two markets, according to the RTO.
“The extremely broad set of eligible nodes for virtual transactions that exist today also expose PJM market participants to increased financial exposure due to discrepancies between the day-ahead energy market and real-time energy market network models,” PJM said in its filing. “Something as simple as an inconsistent breaker status (open or closed) from the day-ahead energy market to the real-time energy market can create a systematic difference between day-ahead and real-time prices that provide a revenue opportunity for virtual transactions without the ability to provide any convergence between the day-ahead energy market and real-time energy market. Because individual nodes are more highly impacted by modeling discrepancies than aggregated locations due to averaging, they are often locations where virtual transactions can profit. Profits collected by virtual transactions in these cases lead to additional costs for PJM members without any benefits.”
The changes were backed by the Independent Market Monitor and some generators and LSEs, but they were opposed by financial traders, who said it would lead to less efficient, less granular markets.
“With 80% of INC/DEC activity occurring at pricing nodes of type hub, zone and interface, according to PJM’s own empirical analysis, eliminating zone for INC and DEC virtual transactions can be disruptive to the market,” said Macquarie Energy.
Some opponents contended PJM had not made its case because it did not perform any quantitative analysis to compare the potential benefits with potential harms at individual load buses.
FERC sided with PJM, saying the RTO had provided sufficient evidence to support its proposal without such an analysis.
The commission said PJM’s proposal to remove zone nodes from INC/DEC trading will not significantly hinder market participants’ ability to manage exposure at the zones. “Given that market participants may bid at residual metered nodes and aggregate nodes where load is settled, they maintain a reasonable ability to manage their risk, including the risk of their day-ahead positions,” FERC said. “We note that market participants will continue to be able to hedge exposure at the zones on [Intercontinental Exchange] and Nodal Exchange and that PJM will continue to post LMPs at the locations where these futures contracts will settle.”
UTCs
Most of the commissioners also backed PJM’s reasoning for reducing UTC trading points. The RTO said UTCs create a divergence in either the source or sink location in 90% of occurrences. The transactions cannot reliably drive convergence in commitment, dispatch and pricing between the day-ahead and real-time markets because UTCs have no real-time equivalent, PJM said.
The Monitor said some traders had pursued a “penny bid strategy” — high volumes of low-risk, low-cost bids that can win large profits during low-probability events causing significant real-time price spreads. (See chart.)
Opponents of the changes insisted UTCs do have real-time equivalents in ISO-NE and ERCOT and noted that MISO and NYISO are considering adding UTC trading to improve price convergence.
The commission said it agreed with the Monitor that limiting UTC bidding to interfaces, zones and hubs “will minimize false arbitrage opportunities for UTCs currently being pursued through penny bids, as the effect of modeling differences between the day-ahead and real-time markets are minimized at these aggregates.”
FERC also agreed with PJM that reducing the biddable UTC locations should reduce the time to solve the day-ahead market, although it acknowledged the “reductions may be modest under most circumstances.”
“We acknowledge that the instant proposal may greatly reduce the opportunity to utilize UTCs in general, as well as the level of granularity at which UTCs can be utilized. We also acknowledge that the biddable points PJM proposes to delete may provide some value to the market,” FERC said. “We are not persuaded by protestors that forgoing some of the theoretical benefits associated with retaining the bidding points for UTCs at zone, EHV or aggregate nodes necessarily renders PJM’s proposal unjust and unreasonable.”
Commissioner Cheryl LaFleur dissented, saying PJM and the Monitor had “not demonstrated that eliminating certain types of biddable points is a targeted solution to address the problematic usage of UTC transactions.”
“UTCs can provide value by converging the congestion and losses component of LMPs and allowing market participants to hedge potential congestion,” she continued. “Given these potential benefits, I feel that moving in the direction of reduced granularity for the use of these products is a move in the wrong direction. However, I would be open to other solutions more targeted to the specific problems that PJM has identified.”
At the Markets and Reliability Committee meeting last week, PJM’s Adam Keech announced that staff had revised the list of biddable points to reflect the Feb. 20 order, but they planned to ask FERC how to address results since the order’s effective date of Jan. 16.
UTC trading has surged since 2011, in part because — unlike INCs and DECs — they have not been assessed uplift charges. | PJM
UTCs have seen explosive growth since 2011, in part because — unlike INCs and DECs — they were not assessed uplift costs. Last month, FERC denied PJM’s plan to allocate uplift to the transactions, another part of its three-phase solution to address uplift. The commissioners said it’s unfair to apply uplift to UTCs in the same way it’s applied to INCs and DECs (ER18-86).
PJM said last month that it believes FERC erred in its logic and might ask the commission to suspend UTCs until an approved solution can be worked out. (See “PJM Not Done on UTCs,” PJM MRC/MC Briefs: Jan. 25, 2018.)
