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.)
Edison International on Thursday joined other California utilities in protesting difficulties in recovering costs related to devastating wildfires, saying it will pursue “legal, regulatory and legislative” avenues on the issue.
During a fourth-quarter earnings call, Edison CEO Pedro Pizarro said the company faced “significant challenges in December and into January of this year due to wildfires and the related legal and regulatory framework in California.” He said the wildfires have increased in severity because of climate change, long-term drought and forest management policies that have led to a buildup of vegetation and dead trees. Eight of the state’s 20 worst wildfires having occurred in the last three years, Pizarro said.
The statements echo recent vows by Pacific Gas and Electric to fight for wildfire cost recovery. Both PG&E and Southern California Edison have asked state regulators to rehear a November decision denying cost recovery to San Diego Gas & Electric for about $380 million in damages costs above its insurance coverage from wildfires in 2007. (See PG&E Vows Fight over Wildfire Cost Recovery.)
Fires raged across California much of the fall, leading the California Public Utilities Commission to take on a larger response role and lawsuits against PG&E and SCE over the possible role of utility infrastructure in causing the fires. (See Wildfires Color California PUC Utility Decisions.)
SCE says recovery of wildfire costs for utilities is a top priority
Edison, the parent of Southern California Edison, said the CPUC has not indicated whether it will allow recovery of premiums SCE spent on incremental wildfire insurance at the end of the year, which cost 29 cents/share. About a quarter of SCE’s 50,000-square-mile service territory is in high-fire-risk areas, Pizarro said.
California’s courts have held investor-owned utilities liable when their utility equipment was found to be a substantial cause of a wildfire.
“This is a statewide crisis that needs a statewide solution,” Pizarro said. In addition to ensuring sufficient fire suppression resources and improved vegetation management and zoning regulations, Pizarro said the state’s infrastructure must be hardened.
“We should evaluate the safety impacts, along with the reliability and cost tradeoffs, of steps like undergrounding more of the distribution network in selected areas, installing steel or composite poles instead of wood ones in specific locations, and using further preventive public safety shutoffs of power under high-risk conditions such as red flag warnings, which we have done selectively in the past,” Pizarro said. “When a catastrophic event occurs in spite of all these efforts, we need thoughtful policies around how financial risks are allocated, including fire suppression costs and damages.”
Fourth-Quarter Loss
Edison reported a net loss of $545 million ($1.67/share) in the fourth quarter, compared with net income of $329 million ($1.01/share) in fourth quarter 2016. On an adjusted basis, fourth-quarter core earnings were $357 million, up from $316 million a year earlier.
SCE’s fourth-quarter earnings decreased by $437 million ($1.34/share) from the fourth quarter of 2016, with a $44 million increase in core earnings offset by $448 million in charges from the revised settlement agreement on the retirement of the San Onofre nuclear plant. SCE reported operating revenue of $6.6 billion in 2017 and net income of $1.1 billion, compared with revenue of $6.5 billion and net income of $1.5 billion in 2016.
The utility filed a general rate case with the CPUC in September 2016 for 2018-2020. It is seeking a $5.5 billion revenue requirement for 2018, down $106 million from the 2017 requirement. It has requested increases of $431 million in 2019 and $503 million in 2020.
The requested increases would result in a 9.7% compound annual growth rate through 2020. However, the company noted that the CPUC has approved 81%, 89% and 92% of its previous three general rate requests.
Storage Filing
Edison’s future will include a focus on electric vehicle integration and energy storage.
SCE intends to file an energy storage procurement and investment plan application March 1 to meet its 166-MW share of distribution-level energy storage under Assembly Bill 2868.
Summary of SCE large transmission projects | SCE
Last October, SCE released a white paper that estimated that California will need more than 7 million EVs, the electrification of one-third of space and water heaters and more energy-efficient buildings to meet the state’s 2030 greenhouse gas reduction target.
In January, the CPUC approved five of the six “fast track” projects, totaling $10 million, that SCE proposed as part of a $574 million transportation electrification initiative in January 2017. Pizarro said the company expects a decision in the second quarter on the long-term projects in the plan.
SPP’s Strategic Planning Committee and other stakeholders on Friday reviewed a draft of a staff-written response to FERC’s grid resiliency docket (AD18-7), agreeing that the commission should consider “the roles and relationships of all participants in the electric industry, not just RTOs and ISOs.”
In a conference call, staff invited comment on the draft and said they are considering raising other issues that affect resiliency but aren’t addressed in FERC’s questions.
Among the issues SPP said it intends to raise is whether FERC should involve others in the proceeding. The commission opened the docket in January, after terminating the Department of Energy’s proposed rulemaking that called for cost-of-service payments to coal and nuclear generators to strengthen grid resilience. (See FERC Rejects DOE Rule, Opens RTO ‘Resilience’ Inquiry.)
Staff’s draft response thanks FERC for being able to share its practices and perspective on resilience, but it also urges the commission to widen industry involvement.
“If [grid resilience] is so important to the nation, why are RTOs the only ones looking at it?” SPP General Counsel Paul Suskie asked.
SPP Chairman Jim Eckelberger agreed, suggesting FERC should be looking at the broader picture of how RTOs and ISOs interact with each other.
“If I were FERC, it wouldn’t be just the reliability of each RTO, but how can neighbors help neighbors?” he said. “If the point is efficiency in the national system, it ought to be highlighted.”
SPP is also suggesting that FERC consider cost-allocation and jurisdictional issues and determine who would pay for supplies necessary to protect resilience. SPP is asking for stakeholder feedback by March 2 so it can meet its March 9 filing deadline.
American Electric Power is among those that have already responded with input. AEP’s Jim Jacoby reminded those on the call that the resilience issue began with DOE’s call to protect coal and nuclear plants.
“All of this needs to be based on engineering studies and judgment,” Jacoby said. “We’re not for across-the-board subsidies by fuel type. We think solid fuel, or stored fuel, provides a lot of benefits, but you need to look at where that plant is needed and when it’s needed.”
SPP drafted its initial response using five teams of staff members, each addressing one topic: planning, operations, cybersecurity, compliance/NERC standards and legal/regulatory. The teams focused their work on how RTOs and ISOs should assess threats to resilience, and how SPP mitigates those threats. The teams held a conference call on Feb. 14 with FERC staff to discuss the issues.
“Clearly, we could build a grid where the lights would absolutely not go out,” Suskie said. “But I don’t think the public would want to pay for that.”
AUSTIN, Texas — ERCOT CEO Bill Magness found himself playing catch up during his Feb. 20 report to the ISO’s Board of Directors, revising a slide on the fly with the latest record for wind production.
“As is often true with wind records in ERCOT,” Magness said, pointing to Jan. 11’s 17,376 MW of wind generation, “that record has already been broken.”
At 10:05 p.m. the night before, the ERCOT system set its latest record by generating 17,541 MW of wind energy.
Looking ahead, Magness said tightening reserve margins following the retirement of more than 4.3 GW of generation make the upcoming summer “all about performance.” Including delayed projects and more than 3.8 GW of new resources, the ISO has seen its reserve margin shrink from 18.9% to 9.3%, leaving it with 77.2 GW of capacity on hand to meet a projected summer peak of almost 73 GW.
“We at ERCOT are doing everything we can think of with people and processes to prepare for what’s coming,” he said. “But I think everybody in the market is doing that as well. We all understand it’s about good performance.”
Additional resources, much of it solar and other renewables, are on the way. ERCOT received 196 interconnection requests last year, more than any year going back to 2007. Utility-scale solar projects accounted for 56% of those requests.
Magness reported a preliminary $10.8 million favorable variance in net revenues, driven by colder weather and under-budget project and hardware expenses.
He also shared what he called a “more tasteful” Super Bowl-related factoid than water usage during the game: the frequency increase in all three interconnections following a 20-second NBC Sports equipment failure that caused television screens to go black late in the first half. Magness said data from the Texas Synchrophasor Network showed that the loss of load was roughly the same as a large generator tripping, but with frequency up rather than down.
ERCOT staff also reported that it is addressing a delayed $2.4 million congestion revenue rights system upgrade with additional vendor resources and increased defect resolution.
“There is an urgency behind this,” said Mandy Bauld, director of ERCOT’s project management office. “We need the system to function because we need certainty around the auctions.”
Directors Grant ‘Critical’ Status to West Texas Project
The board accepted staff’s recommendation that it designate part of a West Texas transmission project as being “critical” to system reliability. The designation means a 345-kV line’s certificate of convenience and necessity application at the Public Utility Commission of Texas will be expedited — and its construction likely completed sooner.
Jeff Billo, ERCOT’s senior manager of transmission planning, told directors that load projections in the Permian Basin’s Delaware Basin — “The hot spot of hot spots,” he said — have grown from a peak of 22 MW in 2010 to a projected 964 MW in 2021. The project’s original study last year had a committed load of 533 MW in 2021.
“To say that this is load growth that we have never really experienced before is an understatement,” Billo said.
The board approved the transmission line as part of the Far West Texas Project last year. The $336 million project consists of two 345-kV lines necessary to support continued oil and gas development southwest of Odessa. (See ERCOT Board Approves West Texas Transmission Project.)
Oncor, one of three companies involved in the project, has submitted two additional projects to ERCOT’s Regional Planning Group, and is also pondering load-shed schemes to maintain reliability before the two upgrades are in place. Billo said Oncor was confident it could have the 345-kV line in service by 2020, if it was designated as “critical” to reliability.
The board also approved a resettlement of the Greens Bayou Unit 5 reliability-must-run agreement with NRG Texas Power, resulting in a $25,949.96 refund to ERCOT. The RMR contract was terminated in May 2017, but costs to NRG were allocated over 31 days that month, instead of the 29 days during which the agreement was in place. (See ERCOT Ending Greens Bayou RMR May 29.)
Board Re-elects Chairs, Confirms TAC Chairs
The board wasted no time in re-electing Craven Crowell and former PUC Commissioner Judy Walsh as its chair and vice chair, respectively. Crowell, an industry veteran and eight-year chairman of the Tennessee Valley Authority, and Walsh have served in their positions since January 2012.
The complete board then re-elected Magness as ERCOT’s CEO and ratified the ISO’s officers. The directors also confirmed the elections of Dynegy’s Bob Helton and the Texas Office of Public Utility Counsel’s Diana Coleman as the Technical Advisory Committee’s chair and vice chair, respectively.
Seven NPRRs Gain Unanimous Approval
Representing the Consumer Market segment, Director Nick Fehrenbach with the city of Dallas pulled a nodal protocol revision request (NPRR841) from the consent agenda over concerns it might result in unintended consequences for bid strategies in the day-ahead market.
The NPRR would correct an oversight in a previous change request (NPRR782) by revising the calculations used to determine the make-whole payment for incorporating the ancillary services infeasibility charge. Those charges are clawed back from generators that are unable to provide ancillary services because of a transmission constraint or through some fault not their own.
Fehrenbach said he wanted to avoid changes in market bid strategies “when there’s no longer the threat of that infeasibility charge” and requested staff monitor participants’ behavior.
“I want to make sure we don’t have a big upswing [in make-whole payments], and if there is, see if it has an impact on behavior or strategy,” he said.
Fehrenbach ended up making the motion to pass NPRR841, which carried unanimously.
The board approved six other NPRRs, including one designed to maintain ERCOT’s independence from FERC oversight, and a system change request (SCR) on its consent agenda:
NPRR819: Removes language referencing “data errors” for resettlement of the day-ahead and real-time markets; gives the ERCOT board authority to direct a day-ahead resettlement parallel to its authority to direct a real-time resettlement; removes references to undefined “declarations” of resettlements; changes the thresholds that determine a resettlement; and fixes a semantics error.
NPRR842: Defines a “study area” as an ERCOT-designated “geographic region,” separate from a weather zone or load zone.
NPRR844: Corrects the current process of including capacity that is modeled but not yet commercially operational in the outage scheduler, which is then reflected in the outage report.
NPRR852: Creates a more efficient approval process when updating the CRR activity calendar; removes unnecessary “advisory approval” language; and moves the calendar’s approval from the TAC to the Wholesale Market Subcommittee.
NPRR855: Clarifies the criteria for including new and retiring resources in the seasonal peak average capacity estimation calculations used for ERCOT’s Capacity, Demand and Reserves report. The revisions apply to wind, solar, DC ties, hydro and all-inclusive generation resources within private-use networks.
NPRR861: Clarifies ERCOT can and will take all actions necessary to preserve its jurisdictional status quo and its market participants with respect to FERC. Possible actions include but are not limited to ordering the disconnection of transmission facilities and denial or curtailment of an electronic tag.
SCR794: Updates how the security-constrained economic dispatch limit is calculated by ERCOT’s Transmission Constraint Manager to consider how the megavolt-ampere flows compare to actual limits.
PUC Chair DeAnn Walker thanked the board for passing NPRR861, saying it was very important to her.
“Chairman Walker, as long as you’re happy, we’re happy,” Crowell said.
