KANSAS CITY, Mo. — SPP’s Regional State Committee (RSC) last week approved the scope for a study of cost allocation in wind-rich areas, a problem that grows along with the RTO’s wind generation.
The study will work with SPP staff to review correlations between generation and load flows on systems below 300 kV and identify potential rate approaches, selecting up to three for further review. Final recommendations are due back to the RSC in April 2019.
“We’re not throwing the highway/byway out,” said Cost Allocation Working Group (CAWG) Chair John Krajewski, who represents the Nebraska Power Review Board, during the RSC’s Apr. 23 meeting, referring to the methodology by which SPP allocates transmission costs according to project size.
Under highway/byway, facilities of 300 kV or more are considered highway facilities and their costs allocated on a regionwide, postage stamp basis; facilities between 100 kV and 300 kV are categorized as byway facilities, with two-thirds of the costs assigned to the host zone and one-third allocated regionwide. Projects under 100 kV are allocated entirely to the host zone.
The RSC in January directed the CAWG to study the issue, following a presentation by Sunflower Electric Power on cost allocation issues in wind-rich areas. (See “Committee Takes on Cost Allocation Issues” in Mountain West, Cost Allocation Top SPP RSC Concerns.)
Sunflower’s Al Tamimi told the RSC in January transmission projects used to be based on changes in load or in designated resources in the same geographical area where the facilities are built. Today’s renewable generation is built at great distances from load centers, with many wind projects in small load zones exported elsewhere, he said.
While the local zones don’t necessarily benefit from the reduced energy costs from the additional wind, they are saddled with the byway costs in the highway/byway methodology, Tamimi said.
CAWG to Get Liaison with HITT
The RSC determined the CAWG should have a liaison on the Holistic Integrated Tariff Team (HITT), given that the group’s work overlaps with the HITT’s proposed scope. “HITT’s work touches on everything the RSC does,” said Oklahoma Corporation Commissioner Dana Murphy.
The committee left the recommendation on a CAWG liaison to HITT Chair Tom Kent.
The RSC also voted unanimously to suspend “until further notice” the CAWG’s work on the new member cost allocation review process.
The committee had asked the group in January to draft a report on the effect of new members on existing cost allocations, a reaction to the Mountain West Transmission Group’s pending integration into SPP. Xcel Energy’s sudden departure from the group has temporarily rendered the report moot.
Committee Approves Triggers to Baseline Cost Escalation
The committee approved a Tariff change that memorializes as a business practice the current practice of using triggers to stop the annual escalation of transmission projects’ undefined baseline costs.
The Markets and Operations Policy Committee approved the Project Cost Work Group’s (PCWG) revision request on Apr. 10. PCWG-RR255 adds triggers when a designated transmission owner provides 1) SPP a letter of commercial operation; 2) notification that an upgrade is in-service; and 3) notification that an upgrade is complete.
Western Energy Imbalance Market (EIM) leaders on Tuesday approved rule changes that would allow EIM balancing areas to manually adjust load forecasts during market operations to ensure the grid can support system conditions.
The five-member EIM Governing Body at a meeting in Vancouver, Canada, approved the ISO’s proposed “Imbalance Conformance” rule changes, which allow operators to manually update the load forecast to account for changing grid conditions. Conformance is used to account for errors in the load forecast, CAISO Market Design Manager Brad Cooper told the body.
“A lot of times it is [used] because of supply deviations, whether it is generators deviating from their dispatch or renewable energy forecast error,” Cooper said during a presentation. The body’s decision conforms with CAISO’s finalproposal issued in mid-March, which clarifies that ISO and EIM balancing area operators can make imbalance adjustments, a clarification CAISO said it was making in the interest of transparency.
The proposal also includes alterations to the “Imbalance Conformance Limiter,” an ISO software tool designed to prevent price spikes caused by imbalance conformance adjustments. The adjustments can be imprecise, CAISO said, and the limiter keeps the market from trying to dispatch more supply than is available in a particular dispatch interval.
The Governing Body unanimously approved the tariff clarifications under its primary authority, while the Imbalance Conformance Limiter changes fall under the body’s advisory role. CAISO plans to seek approval from its Board of Governors on May 16 and then submit them to FERC.
Average ISO conformance data from third quarter 2016 & 2017 | CAISO
The ISO said the changes were approved by all stakeholders, including Arizona Public Service, the Department of Market Monitoring, Pacific Gas and Electric, Public Generating Pool, Powerex, Southern California Edison and the Six Cities group of Southern California utilities.
CAISO initially announced the rule changes last November. Also called “load bias,” the practice has drawn comment from some market participants that note CAISO is increasingly relying on it, particularly in early morning and evening hours when solar generation comes online and offline. (See ‘Load Bias,’ Prices Rise in CAISO Q3.)
In its proposal, the ISO noted that imbalance conformance is imprecise because it uses an aggregated value since manually updating all the supply deviations every five minutes with 100% accuracy is not possible. Using the load forecast allows the conformance adjustments to be spread evenly across the system.
Two Spots to Open
EIM Governing Body Chairman Doug Howe is due to step down from the panel at the end of June, when his first term ends. (See ‘Hesitancy’ Around Western RTO, EIM Chair Says.) Body member Carl Linvill’s term also ends on June 30, and it is not known whether he will seek re-nomination. Other members include Vice Chairs Valarie Fong and John Prescott, whose terms end in 2019, as well as Kristine Schmidt, whose term runs out in 2020. All five are original members of the panel overseeing the regional market, which is expected to incorporate CAISO’s day-ahead market functions, a major change. (See CAISO Says Changes Will Better Match Forecasting, Demand.)
CAISO Regional Affairs Manager Peter Colussy told the board that an eight-member nominating committee and a third-party executive search firm are looking nationwide to fill two positions on the board. In-person interviews for new EIM Governing Body candidates are set for May 10-11 in Phoenix, Ariz. Relevant expertise is needed, as well as a familiarity with the Western Interconnection, and candidates must be independent of participants in the ISO and EIM markets or those who advocate for certain positions in the ISO stakeholder process, Colussy said in a presentation.
The approved slate of candidates is due for approval by the Governing Body on June 20. Terms are three years, beginning July 1 of each year and ending on June 30.
In January, the EIM Governing Body rejected a proposal that would have changed how the board nominates members. (See EIM Body Tables Nominating Process Changes.) The rejected proposal would have eliminated the EIM Nominating Committee’s obligation to use an executive search firm to help fill Governing Body vacancies, instead encouraging committee members to rely more on their own contacts.
Public Service Enterprise Group’s energy trading arm has agreed to pay $39.4 million to settle an investigation into violations of PJM’s energy market bidding rules over 9 years (IN18-4).
The commission’s April 25 order approving a consent agreement with PSEG Energy Resources & Trade, which markets the output of PSEG Power’s generation fleet, both praised and criticized the company’s actions in the matter.
The non-public investigation was disclosed earlier this month, when FERC’s Office of Enforcement issued a Notice of Alleged Violations charging PSEG with violating PJM’s Tariff and FERC regulations by submitting incorrect cost-based bids into PJM’s daily energy market between 2005 and 2014, when the company self-reported the violations to the commission. (See FERC Investigation Shows PSEG Violated PJM Bidding Rules.)
PSEG agreed to a civil penalty of $8 million and to pay PJM disgorgement of $26.9 million and $4.5 million interest. It also will submit annual reports to ensure future compliance. The company did not admit any wrongdoing.
In April 2014, PSEG told FERC of inaccuracies in the cost-based offers for some of its fossil units due to the inclusion of incorrect environmental adders for the prior two years. The company later provided the commission self-reports that identified incorrect cost-based offers dating to 2005.
Map showing location of PSEG’s fossil fuel generators | PSEG
Among PSEG’s “errors,” as FERC described them in its order approving the consent agreement, were: including CO2 adders in its cost-based offers after New Jersey withdrew from the Regional Greenhouse Gas Initiative; including seasonal NOx adders in offers outside the NOx compliance season; incorrectly stating the amounts of fuel required for minimum operations at Unit 2 of its 1229-MW natural gas and kerosene Bergen Generating Station; and providing inaccurate heat rate data for some units.
The commission said it decided on the $8 million penalty considering “that PSEG self-reported the violations, cooperated fully and comprehensively throughout the investigation and has no prior history of violations. The remedy also reflects that although PSEG had a compliance program in place, it was not sufficiently robust to detect or prevent the violations.”
“In addition to responding to Enforcement’s data requests, PSEG provided extensive data, conducted extensive data analyses regarding the cost-based offers and demonstrated exemplary cooperation during the investigation,” the commission added.
But the order also noted, “PSEG’s compliance program and existing compliance procedures did not detect the errors in the cost-based components of the offers, in some cases, for multiple years.”
After the self-report, FERC said PSEG adopted new procedures requiring that daily offers be double-checked for accuracy and revised its fuel policy “to more clearly articulate the calculation of cost-based offers in accordance with PJM’s rules.”
The company also added staff to its internal audit department and hired an independent audit company to help develop additional compliance procedures.
It also made unspecified personnel changes in the trading and asset optimization groups “to impose additional accountability and focus attention on compliance issues,” FERC said.
FERC directed PJM to disburse the disgorgement and interest pro rata to affected market participants.
When stakeholders begin considering potential changes to PJM’s demand curve next month, one of the main debates will likely center on whether combustion turbines (CTs) should remain the reference technology for estimating the cost of new entry (CONE) or be replaced by combined-cycle gas turbines (CCGTs).
PJM will take up the issue of revising its variable resource requirement (VRR) curve at its Market Implementation Committee meeting on May 2.
The review, which occurs every four years, must be completed by Aug. 31 to be filed for FERC approval by Oct. 1 and put in place for use in the 2019 Base Residual Auction (BRA). PJM has until May 15 to recommend proposed Tariff revisions, which are based on an analysis by the Brattle Group, who provided recommendations of its own, some of which differ from PJM’s.
Brattle’s Analysis
PJM hired the Brattle Group to analyze the shape of the VRR curve, the CONE for areas used in the VRR Curve and the methodology for determining the net energy and ancillary services (E&AS) revenue offset for the region PJM serves and for each zone. Brattle representatives presented their findings to stakeholders on Wednesday.
Brattle’s analysis found the Capacity Performance (CP) rules PJM implemented in 2016 would not significantly impact the curve it recommended in its 2014 report, but the net CONE has decreased “substantially” compared with the parameters that will be used this May in the 2021/22 BRA. CP flattens lower-priced offers in the supply curve but doesn’t affect the higher-priced side of the curve.
Capacity Performance rules have flattened out the lower-priced portion of the supply curve but left the higher-priced portion largely untouched. | the Brattle Group
“This reduces instances of very low prices and volatility but does not change results under high-priced, low-reserve-margin conditions that drive reliability performance,” the report said.
However, reducing net CONE would shift the VRR curve substantially down, such that the cost to procure PJM’s installed reserve margin (IRM) would be potentially cheaper by hundreds of dollars per MW-day.
Removing CT Base
Brattle recommended using the net CONE for CCGTs as the reference technology in conjunction with localized adjustments. PJM currently uses the net CONE for CTs, but Brattle’s analysis showed the construction cost for a CCGT has dropped as much as 40% so that it is just slightly higher than that of a CT. Net CONE for CTs also dropped in the updated calculations but not as much as net CONE for CCGTs, which Brattle estimates is between 44% and 76% lower than PJM’s 2021/22 parameters and between 25% and 63% lower than its updated CT Net CONE estimates, depending on location.
Brattle’s analysis shows that its updated calculations for cost of new entry (CONE) has shifted the curve substantially down. Using Brattle’s recommendation to use a combined cycle as the reference technology would also move the curve to the left. | the Brattle Group
“CCs are more economic because their much higher net E&AS revenues more than offset slightly higher plant costs on a per-kW basis,” the report found.
“In reality, net CONE has declined substantially, especially for CCs, and this has major implications for the VRR curve,” Brattle continued. “… If in spite of that reality, PJM maintained a CT as the reference technology for anchoring the VRR curve, [but] continued low-priced entry of CCs would maintain average reserve margins substantially above target.”
Brattle estimated that using a CC as the reference technology, along with adjustments to compensate for triggering an alternative price cap provision, would achieve average reserve margins 1.4% above the IRM target and decrease annual average procurement costs by $212 million compared with the current CT-based curve and $138 million compared with adjusting the current curve 1% to the left to account for the expected over-procurement.
Brattle also determined that if its analysis underestimated the CONE by 20%, the average loss of load expectation (LOLE) would rise to 1.6 events every 10 years rather than its target of 1 event every 10 years.
That said, Brattle didn’t reject using the CT basis.
“We also see an argument for a CT-based curve if PJM and stakeholders are highly risk-averse about ever procuring less than the target reserve margin, since the incremental cost is modest in context,” the report said. “Even a $140-million difference in cost is less than 0.5% of PJM’s total annual wholesale costs.”
Additional Recommendations
Brattle also recommended changes to PJM’s methodology for calculating net E&AS revenues:
Update gas-pricing points for six locational deliverability areas (LDAs).
Update unit operating characteristics, such as heat rates.
Include net CP payments.
Move maintenance costs from variable operations and maintenance (O&M) costs into the fixed O&M cost component of CONE in the current cost development guidelines.
Implement forward-looking estimates of E&AS revenues rather than the current three-year historical calculations.
Calculate E&AS margins for RTO and other multi-zone LDAs based on median across zones.
PJM’s Recommendations
In a letter to stakeholders, PJM recommended updating the CT used as the reference technology to a GE Frame Model 7HA, which Brattle used in its analysis based on project development trends, improved efficiency and lower costs. Stu Bresler, PJM’s senior vice president of operations and markets, noted in the letter that NYISO, ISO-NE and the Alberta Electric System Operator all use CTs as their reference technology.
“The combustion turbine continues to provide the lowest CONE, shortest time to market, and derives the most significant portion of its revenue from the capacity market as compared to other resources. The fact that the CT receives the smallest amount of its revenue from the energy market means that its Net CONE value is the least likely to be significantly perturbed by potential changes in energy market prices,” Bresler wrote. “PJM’s certainty is provided through the use of a peaking unit as a reference resource because it minimizes the exposure to short-term energy revenue offset volatility.”
Maintaining the CT-based VRR curve with updated values for net CONE “will continue to provide long-term reliability at reasonable cost,” Bresler argued.
PJM agreed with Brattle’s CT estimates for all CONE areas except for the “rest of RTO,” which it felt was too low. PJM recommended $282/MW-day in that that zone, Cone Area 3, rather than Brattle’s recommendation of $269/MW-day.
PJM also agreed with several of Brattle’s recommendations on E&AS, including the update to unit operating characteristics and gas pricing hubs and using the median to determine net E&AS offset. It also recommended a 10% adder “to account [for] potential uncertainties in measurement” and to maintain dispatch flexibility.
But it differed on the methodology for calculating generator revenues, recommending use of the sum of the median monthly revenues from the last three calendar years rather than annual revenue averages.
“This approach provides a less volatile year-over-year determination of an annual net E&AS value than that provided by a three-year average by dampening distortion caused by a single anomalous month of unusual weather or fuel market conditions,” Bresler wrote.
PJM has scheduled additional meetings on the VRR curve updates, starting with an afternoon session on May 25. Subsequent meetings are planned for June 22, July 6 and July 27.
NextEra Energy beat analysts’ expectations and shattered last year’s first-quarter performance, reporting earnings Tuesday of $4.4 billion and $9.32/share, up from $1.6 billion and $3.37/share, respectively.
The Florida-based company’s adjusted earnings were $1.94/share, beating the Zacks Consensus Estimate of $1.78/share. The GAAP results reflect the deconsolidation of NextEra Energy Partners from NextEra’s financial statements and the impacts of tax reform, the company said.
“NextEra Energy delivered strong first-quarter results and is off to a solid start toward achieving our overall objectives for the year,” said CEO Jim Robo.
NextEra CFO John Ketchum told analysts the company now expects its Florida Power & Light (FPL) subsidiary to achieve its target regulatory return on equity of 11.6% “either late in the second or early in the third quarter.” He said NextEra may begin “partially restoring” FPL’s reserve amortization balance through tax savings later this year, and it continues to expect the utility will end 2020 “with a sufficient amount of surplus to potentially avoid a base rate increase for up to two additional years.”
The Florida Public Service Commission has opened separate dockets to address tax reform for FPL and each of the other Florida investor-owned utilities, Ketchum said.
“We look forward to working with the [commission] and other interested parties to further explain how FPL’s prompt actions within the terms of the settlement agreement benefit customers,” Ketchum said.
NextEra said the eight solar energy centers it has brought on line this year will generate more than $100 million in total savings for FPL customers during their operating lifetime. The utility has also announced the creation of the largest combined solar-plus-storage project in operation in the U.S., a 10-MW battery project with 40 MWh of storage capacity at Babcock Ranch in southwest Florida.
NextEra-TVA’s River Bend Solar Energy Center | TVA
The company’s share price gained $2.50 after Tuesday’s open but finished Wednesday at $160.31, down 77 cents from Monday’s close.
Entergy Earnings Up, But Fall Short
Entergy posted first-quarter earnings Wednesday of $211 million, or $1.16/share, up from $178 million, or $0.99/share, over the same period last year. Zacks had projected earnings of $1.31/share.
The New Orleans-based company credited the performance to the lower federal income tax rate, favorable weather and a new financial reporting guidance that requires the mark-to-market of equity investments in the nuclear decommissioning trust funds at Entergy Wholesale Commodities (EWC).
EWC has shut down its Vermont Yankee nuclear unit and is planning to retire Pilgrim in 2019, Indian Point in 2021 and Palisades in 2022.
CARMEL, Ind. — While MISO says it’s ready for a warmer-than-normal summer, RTO officials cautioned Tuesday that operators will likely lean on demand response resources to manage loads at some point during the season.
During an April 24 summer readiness workshop, MISO officials stressed that summer capacity levels will exceed the forecasted 2018 summer peak demand and reserve margin requirement.
However, the RTO foresees a 79% probability it will call up load-modifying resources, a 17% probability of using operating reserves and a 9% chance it will be forced to shed load.
MISO summer probability of emergency | MISO
MISO predicts a 124.7-GW summer coincident peak with 148.6 GW in available supply and 11.4 GW in anticipated reserves after accounting for typical outages. Last summer, MISO predicted 148.5 GW worth of supply to meet a 125-GW peak demand, 4 GW shy of MISO’s 121-GW actual peak load set in July.
“We have adequate supply to meet our expectations for this summer,” MISO Senior Director of Systemwide Operations Rob Benbow told stakeholders.
Likewise, Kojo Sefah, a MISO resource adequacy engineer, said the RTO’s transmission assessment showed no major constraints this summer.
However, MISO is predicting negative load growth combined with an increased use of behind-the-meter generation and demand response to meet the reserve margin.
“Negative load growth combined with an increase in behind-the-meter generation and demand response have increased our base reserve margin. What’s that mean? We’re going to use more [load-modifying resources] if we have to,” said MISO shift operator Trevor Hines. “ … That’s what they’re for.”
In a high-load, high-outage scenario, MISO expects to “rely heavily” on demand response, said Eric Rodriguez, of MISO’s resource adequacy division.
Hines said in a high-load, high-outage scenario, MISO is “3.3 GW of demand response away from having to use operating reserves to serve load.”
Beginning in June, MISO will have a 17.1% planning reserve margin, based on limiting the likelihood of shedding load to no more than one day in 10 years. Last year’s margin was 15.8%. The RTO said the shrinking load growth and increasing DR and BTM generation use helped boost the planning reserve margin.
MISO said while negative demand growth has helped increase reserves, the percentage of reserves available beyond the minimum requirement has decreased. During the 2016/17 and 2017/18 planning years, MISO had an additional 3% of reserves on hand. This summer, the RTO predicts 2% in additional reserves.
Summer outage trends | MISO
MISO said its summer predictions were predicated on the megawatts available in this month’s Planning Resource Auction. Additional non-firm generation support may be available but cannot be definitively counted, the RTO said. (See MISO Clears at $10/MW-day in 2018/19 Capacity Auction.)
Rodriguez said the number of planned, maintenance and forced outages this summer are expected to be consistent with outage levels over the past five years. Last year, MISO experienced roughly 15-17.5 GW in outages during summer peak times.
Customized Energy Solutions’ David Sapper said he didn’t understand why MISO was putting such a “spotlight” on mitigating outages in other stakeholder discussions when it did not expect outages to increase this summer. MISO officials have said outages have played a role in most of the RTO’s maximum generation events since late 2016, and they are looking into forecasting the effects of planned and maintenance outages on peak in its loss-of-load expectation study by the 2019/20 planning year. (See MISO Looks to Address Changing Resource Availability.)
MISO officials nevertheless said they stood by their summer outage prediction for this year.
Summer 2018 Weather
Using forecasts from the National Oceanic and Atmospheric Administration, MISO is expecting a warmer-than-normal summer for the footprint ― especially in MISO South, with normal precipitation levels in MISO Midwest but lower-than-normal precipitation in the South region.
“Sustained high temperatures can have an impact” on day-to-day operations, Rodriguez said.
Hurricane Prep
MISO is preparing for at least one major storm to hit the Gulf Coast portions of MISO South.
Colorado State University’s Tropical Meteorology Project predicts 14 hurricanes for this summer, with seven of those developing into Category 3 or higher storms.
MISO South operations adviser Gerald Rusin said MISO will continue to use its hurricane action plan, which includes conducting a 31-hour, Category 4 storm simulation depicting multiple islanding events within the electric system.
Rusin said the university group sees a 38% chance of “at least one major hurricane making landfall along the Gulf Coast from the Florida Panhandle to Brownsville, Texas.”
“There were four tropical weather events that took aim at MISO South last year,” Rusin pointed out.
Rusin said last year MISO maintained reliability through Hurricane Harvey’s “unimaginable flooding” in the Lake Charles, La. area. Harvey submerged some substations and caused months-long generation outages in the Entergy footprint, he said.
MISO will hold a second hurricane preparedness drill with six MISO South market members May 16-17. A previous drill took place in mid-April.
KANSAS CITY, Mo. — For 18 years, Jim Eckelberger and Harry Skilton have been a steady presence on SPP’s Board of Directors, providing strategic direction and financial guidance.
The men joined the board in 2000 as two of its first seven independent members, helping to oversee SPP’s classification as an RTO in 2004. Until Tuesday, they were the only two original directors still active on the board.
No more. SPP CEO Nick Brown began the board’s April 24 meeting by telling the Members Committee that Eckelberger and Skilton would be moving to emeritus status, although they will continue to remain under contract with the board.
“They will continue to bring the tremendous amount of experience and institutional knowledge they’ve gained over 18 years of service to this organization,” Brown said.
Vice Chair Larry Altenbaumer replaces Eckelberger as chair, while Graham Edwards takes over as vice chair. The moves became effective following the board meeting’s conclusion.
Eckelberger, who was first elected board chair in 2004, took his final moments in the role to reflect on his time with SPP and to thank everyone around him. He said he was only following the Jesuit philosophy of serving others.
“Instead of being in a leadership role, I will be in a resource role. I love that,” Eckelberger told the board and members. “I think that’s a wonderful opportunity for me to be a benefit to others. Thank you for allowing me to go beyond age 80 into this resource position.
“Bottom line, if you look at the last few months, October onward, the [prices] in our footprint have been phenomenal, lower than they’ve ever been,” he said. Referring to his audience, Eckelberger said, “We’ve done a wonderful job for the organization’s members and the consumers in the footprint. It’s been a win-win situation all around.”
Eckelberger heaped praise on staff, his fellow board members, and the Regional State Committee and Markets and Operations Policy Committee. “The success is all about you,” he said.
“I’ve watched over the years as people with very disparate ideas have found a way, without going to Washington, to make progress we can all agree to. Everyone has to represent their organization, but it’s been a phenomenal ability of everyone to bring about evolutionary change and a relationship-driven and member-driven organization. I appreciate the Members Committee for finding a way to do that.
“To SPP, you said you’ve wanted an independent board. I can say I’ve pissed off every member of the staff in one way or another,” Eckelberger said, drawing a laugh.
“Then I look at the board and the Members Committee. I’m surrounded by peers for whom I have great respect,” he said, as his eyes filled with tears. “I want to say to you, the members who have made all this possible … Thank you, thank you, thank you.”
SPP’s directors, members and staff rewarded Eckelberger with a standing ovation.
Now composed, he turned to Altenbaumer, shook his hand and said, “And to my successor, whom I have great respect for … Good luck!”
With that, Eckelberger’s tenure as board chair was over.
Brown said Eckelberger and Skilton will be honored with “much more fanfare” during SPP’s Annual Meeting of Members in October.
A 30-year veteran of the U.S. Navy, Eckelberger rose to the rank of rear admiral before entering the corporate world and joining SPP. He served in the first Gulf War during his last year of active duty.
Skilton spent 25 years in senior executive and general management positions, including CEO of American Meter Company and treasurer for Celanese Corporation.
Altenbaumer was elected to the SPP board in 2005 and recently succeeded Skilton as chair of the Finance Committee. He served as president of Illinois Power, a regulated electric and natural gas delivery company, and was executive vice president of regulated energy delivery for Dynegy.
SPP hopes to select replacements for Eckelberger and Skilton before the annual members meeting in October.
CARMEL, Ind. — MISO easily managed what turned out to be a “near-normal” March, the RTO said Tuesday.
The RTO’s load averaged 71.1 GW for the month, in line with the 70.8 GW average a year earlier. But the 85.3 GW monthly peak set on March 14 came up 2.5 GW short of last March’s peak.
During an April 24 Informational Forum, MISO reported relatively mild weather in most of the footprint during March, although cold conditions persisted in parts of MISO Midwest.
“I would say winter just won’t go away this year,” observed MISO Senior Director of Systemwide Operations Rob Benbow, who added that lower temperatures kept demand relatively low during the month.
“We did see a lot of diversity in our weather footprint,” Benbow said, noting that one day in March saw snowstorms up north while parts of MISO South were under tornado warnings.
“When you span that far across the United States, you expect that,” he added.
Real-time prices in March were about 14% lower than they were last year, averaging $25.40/MWh, while day-ahead averaged $25.55/MWh.
Benbow said the price drop was due to lower congestion and natural gas prices compared with last year. Gas prices in March averaged $2.48/MMBtu at Chicago Citygate and $2.66/MMBtu at Henry Hub, down from $2.84/MMBtu and $2.83/MMBtu, respectively.
Benbow said the month brought the usual onset of generation maintenance outages, with planned outages doubling to about 25 GW as February transitioned into March.
MISO also set a new, 15.6-GW record peak for wind generation on March 31, toppling its previous 15-GW wind record set in January.
Queue Progress
MISO also provided an update on its interconnection queue, with Benbow saying completion of affected systems studies continue to slow queue progress, a topic debated in early April at a FERC technical conference. (See Renewable Gens Face Off with RTOs at Seams Tech Conference.)
MISO’s generator interconnection queue currently includes 561 projects, totaling 93.1 GW, and the April 2018 definitive planning phase queue cycle added 244 projects, representing 41.2 GW.
MISO said it is managing 14 ongoing queue cycles with five more queue cycles set to begin in the coming months. The lion’s share of the queue is renewable generation, with 42.7 GW of wind, 37.4 GW of solar and 12.3 GW of natural gas generation.
Avangrid on Monday said its first quarter earnings rose slightly on new rate plans and increasing output from its wind fleet, and the company highlighted its growing opportunities in renewable energy — particularly offshore wind.
The company posted net income of $244 million for the quarter ($0.79/share), up 2% from the same period a year ago.
CEO James P. Torgerson said in an analyst call that “earnings improved primarily due to the implementation of our multiyear rate plans [and] increased wind production, mainly from the 534 MW of capacity that came on line in 2017.”
| Vinyard Wind
Torgerson noted Avangrid subsidiary Central Maine Power (CMP) is set to sign a contract with Massachusetts by the end of this month for the state’s 9.45-TWh clean energy solicitation, which was awarded to CMP’s New England Clean Energy Connect (NECEC) transmission project after the original winner was rejected by siting officials in New Hampshire. (See Mass. Picks Avangrid Project as Northern Pass Backup.)
CMP partnered on the project with Hydro-Québec, which will deliver up to 1,200 MW of Canadian hydropower to the New England grid via a 145-mile transmission line. The partners estimate the project will cost $950 million and will soon file with the Massachusetts Department of Public Utilities, said Torgerson.
Avangrid also completed the sale of its gas trading business last quarter and expects to sell off its gas storage business in May.
The company said it has 497 MW of onshore wind and solar under construction, to be operational by the end of 2019. Avangrid’s Vineyard Wind partnership with Copenhagen Infrastructure Partners bid 400-MW and 800-MW projects into Massachusetts’ offshore wind solicitation, the winners of which will be announced in May. (See Mass. Receives Three OSW Proposals, Including Storage, Tx.)
Vineyard Wind in the first quarter also submitted a bid for 190 MW of offshore wind in Connecticut, with selection scheduled for June.
Regulatory Update
Torgerson expressed muted optimism about a FERC administrative law judge’s March ruling that municipal utilities and commission staff failed to prove the New England Transmission Owners’ base return on equity of 10.57% (11.74% with incentives) is unjust and unreasonable, rebuffing requests to reduce it. (See ALJ Rules New England Tx Owners’ ROEs not Unjust.)
“We feel that’s positive, but the commission will still ultimately need to decide, and there’s really no time frame at this point to make that decision,” said Torgerson.
The corporate tax cuts passed by the Trump administration in December created benefits for the company, and Avangrid is working with state regulators in New York and New England to offset major storm recovery and advanced metering infrastructure (AMI) costs through the windfall before passing benefits to customers.
The AMI discussions are ongoing in New York and the company anticipates approval later in 2018. “The earnings adjustment mechanism discussions have been impacted by the ongoing storm activity and the AMI discussions and other things, so that’s been delayed somewhat,” said Torgerson.
Offshore Potential
After establishing its offshore wind business last year, Avangrid quickly won a Bureau of Ocean Energy Management (BOEM) lease auction off Kitty Hawk, N.C., an area that could produce up to 2.5 GW of energy. The company also last year acquired its 50% partnership in Vineyard Wind.
| Vinyard Wind
Torgerson also highlighted upcoming opportunities in offshore wind.
“In New York, they are looking for 800 MW in the fall and 2,400 MW by 2030,” he said. “Rhode Island is evaluating or looking to evaluate the implications from the Massachusetts RFP and want information on that, how it could impact Rhode Island. So, there is an expectation that Rhode Island may be looking for some offshore wind as well.”
Offshore wind got a boost on two fronts earlier this month when U.S. Interior Secretary Ryan Zinke announced two new proposed offshore wind leases for Massachusetts, while the Interior Department’s BOEM issued a call for commercial interest in four wind energy areas in the New York Bight. (See Interior Plans Would Boost Mass., NY Offshore Wind.)
“We will be looking at those very closely,” said Torgerson. “And Governor Phil Murphy in New Jersey is said to be looking for about 3,500 MW offshore of New Jersey.”
To model the impacts of carbon pricing on dispatch, resource costs and emissions in its wholesale electricity market, New York would do well to start by estimating a social cost of carbon (SCC), experts told a state task force Monday.
The Integrating Public Policy Task Force (IPPTF) heard three presentations on SCC and related topics as the group drilled further into technical details in its mission to reconcile the wholesale electricity market with state environmental goals.
The IPPTF is jointly run by NYISO and the state’s Department of Public Service (DPS). The April 23 discussions were part of issue “Track 3” and “Track 5” in the group’s five-track effort to price carbon emissions.
“Each and every ton [of CO2] that’s emitted contributes to harms that you and I face from climate change,” Bethany Davis Noll, litigation director at the Institute for Policy Integrity at the NYU School of Law, said in explaining how the SCC attempts to put a monetary value on the damages associated with the incremental rise in carbon emissions each year. “What economists tell us is that if we can figure out a way to put a dollar value on those harms, it’s easier for us to face or figure out what to do in response in order to stop them.”
Davis Noll presented a report on the SCC determined by the Obama administration’s Interagency Working Group (IWG) on Social Cost of Greenhouse Gases, which in 2016 estimated the SCC at $50 per ton of CO2.
Numbers Game
President Trump in March 2017 signed an executive order disbanding the IWG and withdrawing its technical support documents, but federal agencies are still required to monetize climate harms, said Davis Noll.
Some agencies are still using the IWG’s number, while EPA and the Bureau of Land Management have proposed to use an “interim” social cost of carbon.
“Basically, the interim estimate brings the $40 to $50 number down to $1,” Davis Noll said.
The methodology used to get the $1 value obscures the global harm of emissions “and was rejected by the IWG as inappropriate for this type of analysis,” Davis Noll said. “Agencies are not allowed to do lopsided analysis, putting a dollar value on the one side and not using a well-recognized tool on the other side.”
David Clarke, director of wholesale market policy for Power Supply Long Island, contended the state has two approaches to consider: either a federally approved tariff or state regulation.
“What’s your view on FERC and what kind of things they would consider when deciding whether a social cost of carbon is just and reasonable?” Clarke asked.
Davis Noll’s position is as follows: Based on the “extensive research” already done on the SCC, the widespread support for the IWG number suggests it clearly is “just and reasonable” according to FERC standards.
“I think FERC is actually receptive to using it themselves in their decisions … here all we have to do is figure out whether the ISO’s proposal’s going to be judged just and reasonable,” Davis Noll said.
She added, “The executive order doesn’t do anything, it really just disbands the working group … and so far, there are so many states relying on this number — that’s also supportive.” States incorporating the IWG value into their environmental policies include California, Colorado, Illinois, Maine, Minnesota, New Jersey, New York and Washington.
New York Way
Warren Myers, DPS director of market and regulatory economics, presented a report recommending the task force use in its analysis the CO2 value already adopted by the New York Public Service Commission (PSC).
The commission in its January 2016 Benefit Cost Analysis Framework Order (14-M-0101) relied on the IWG’s “central value” SCC minus the Regional Greenhouse Gas Initiative (RGGI) allowance price, until Tier 1 renewable energy credit (REC) procurements were established later that year under the state’s Clean Energy Standard (CES).
The PSC’s March 2017 Value of Distributed Energy Resources (VDER) Order (15-E-0751) set compensation value at the higher of Tier 1 REC or SCC minus RGGI. Converted by DPS to dollar per ton, the latter figure would gradually increase over the coming decade from $40.74/ton in 2020 to $56.77/ton in 2030. (See NYPSC Adopts ‘Value Stack’ Rate Structure for DER.)
| NY Dept. of Public Service
Myers said the precise dollars and cents values for each year could be a little misleading, since it is the order of magnitude that really matters. So, while those precise calculations do reflect the IWG numbers adopted by the PSC, we should not conclude they are necessarily any more accurate than Davis Noll’s $50/ton estimate, he said.
A portion of the SCC has already been internalized in the ISO’s locational-based marginal pricing, Myers said, “and so what we would like is the externality, which we say is the SCC minus the relevant RGGI number.”
One reason developers and environmentalists in the VDER proceeding “opposed using the Tier 1 RECs price only was that it just really doesn’t triangulate at all; it isn’t tied at all specifically to carbon; it’s just a compliance cost of a program with certain program parameters,” Myers said.
Howard Fromer, director of market policy for PSEG Power New York, said he appreciated the DPS’s effort to send a consistent price signal to the market that clarifies “here is the value of avoiding carbon.”
However, he said state subsidies for large amounts of preferred technologies, such as the $180/MWh cost for the first 90 MW of offshore wind on Long Island, has the potential to undermine the price signal consistency.
“I would hope that we would not blindly lock ourselves into the [IWG] number, given that I have very little confidence in what today’s interagency task force, if reconstituted, might produce, and I would much prefer to speak to the New York [Public Service] commission, frankly, with consistency with their policy,” he said.
Modeling Resource Shift
Tim Duffy, NYISO manager of economic planning, presented a report addressing customer impacts via a proposed methodology for modeling and analysis. The ISO proposed starting from a base case using its Congestion Assessment and Resource Integration Study (CARIS) data, updated and extended, and carrying through to both a simple change case and a dynamic change case, which would add assumed changes to fleet and load.
“For the purpose of developing the system resource shift scenario or case, we assume achievement of CES in 2026,” said Duffy. The CES mandates that New York get 50% of its electricity from renewable resources by 2030.
The ISO study aimed to define enough market scenarios to span the range of plausible impacts of a carbon charge throughout the state, as well as the key factors affecting marginal emission rates in various parts of the state, such as whether a new renewable resource is located upstate or closer to the load centers around New York City, he said.
Estimates for 2020 | IWG/U.S. Gov.
“We’re proposing to run multiple years here, 2020, 2025 and 2030, and all the data associated with each of those three years would be provided,” said Duffy.
IPPTF co-chair Nicole Bouchez, NYISO principal economist, referred to the Brattle Group carbon pricing report from last August.
“We’re looking at something in the same conceptual way that Brattle looked at this, which is first you look at what are going to be the direct price impacts, and then you look at these dynamic changes, how does investment change, how do the numbers change,” said Bouchez.
Marc Montalvo of Daymark Energy Advisors, representing the state’s Utility Intervention Unit, said, “The state is going to seek to meet its CES policy objectives with or without this carbon charge policy. So, if we add the carbon charge, will that be a successful thing to do? Analytically, how do we measure success?”
The task force will next meet May 7 at NYISO headquarters to further cover issue “Track 5,” which it will discuss again June 4 to complete the assumptions and scenarios. The study results are scheduled to be presented in September.
In a related move, the ISO has scheduled a public forum May 1 on analysis of transmission congestion on the New York state bulk power system and the potential costs and benefits of relieving transmission congestion through its CARIS process.
