Page 1169 – RTO Insider

April 26, 2018

PJM to Consider Revisions to Demand Curve Design

By Rory D. Sweeney

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.

PJM demand 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.

“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.

April 26, 2018

NextEra Beats Wall Street’s Expectations

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 Energy Earnings Q1 2018 — 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.

— Tom Kleckner

April 26, 2018

MISO: Summer Reserves Adequate, but Emergency Likely

By Amanda Durish Cook

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 DER Demand Response summer peak — 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.

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 C lears 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 Availab i lity.)

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.

April 26, 2018

Eckelberger, Skilton Step Down from SPP Board

By Tom Kleckner

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.

SPP Board — CEO Nick Brown (left) and SPP members listen to Jim Eckelberger’s final comments as board chair.| © *RTO Insider*

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.

April 26, 2018

MISO Ops Easily Handle Quiet March

By Amanda Durish Cook

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.

MISO Queue Cycles — Benbow | © *RTO Insider*

“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 Rene w able Gens Face Off with RTOs at Seams Tech Conference.)

MISO Queue Cycles Natural Gas — MISO Informational Forum on April 24 | © *RTO Insider*

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.

April 26, 2018

Avangrid Posts Steady Q1 Income, Highlights Renewables

By Michael Kuser

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 ca l l 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.”

offshore wind avangrid earnings q1 2018 — | *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. P i cks 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. Receive s 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 FER C 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 Owner s ’ 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.

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., N Y 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.”

Quotes courtesy of Seeking A lpha

April 26, 2018

NY Looks at Social Cost of Carbon, Modeling

By Michael Kuser

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.)

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.

social cost of carbon scc — 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.

April 26, 2018

NY Sets 40% Hike in EE Goal

By Rich Heidorn Jr.

The New York State Energy Research and Development Authority (NYSERDA) published a white paper Thursday outlining plans to accelerate the state’s energy efficiency (EE) goal by 40%.

The paper calls for 185 trillion British thermal units (TBtu) of cumulative annual site energy savings relative to forecasted 2025 consumption. The agency said that would deliver almost one-third of the emissions reductions needed to meet the state’s goal of reducing greenhouse gas emissions 40% from 1990 levels by 2030.

NYSERDA said this would include a 30,000-GWh reduction from forecasted 2025 electricity sales — a 3% reduction in investor-owned utility sales in 2025 and average savings exceeding 2% of IOU sales between 2019 and 2025.

The new target is based on savings in buildings and the industrial sector across all fuel sources (electricity, natural gas, heating oil and propane).

“This paper proposes a portfolio of accelerated actions to drive an additional 41 TBtu of aggregate efficiency savings statewide by 2025 or a 40% increase above the state’s current commitments for the 2019–2025 period,” NYSERDA said.

NYSERDA said it will spend an additional $36.5 million to train more than 19,500 people for energy efficiency and other “clean energy” jobs.

“The path to delivering on New York’s 2025 energy efficiency target recognizes that a mix of strategies will be necessary, focusing on the approaches best suited for specific markets and their needs and on the mix best suited for long-term cost-effectiveness,” the report said. “The portfolio will include a good measure of innovation, testing those approaches with the best promise, then scaling those that take hold.”

NYSERDA said it will seek to meet the 2025 target by:

“Accelerating and shifting” utility energy efficiency programs by increasing market-based EE, more leverage of public funds and more effective programs. “This includes the proposed development of a shared savings approach that provides greater opportunity and reward for utilities to advance energy efficiency as a business and as a resource.” (See NY Fine-tuning CES; Phasing out EE Program.)
Dedicating at least 20% of any additional public investment in EE to low- to moderate-income consumers.
Strengthening laws on building codes and appliance standards by increasing EE requirements.
“Driving deep energy savings” through building retrofits and construction and cost-effective heat pump adoption. “If New York is to achieve the 40 by 30 … climate goals, it will be essential to retrofit the state’s existing building stock to dramatically reduce energy consumption, so that most buildings are able to reach passive house or net zero energy performance levels. This presents an imperative to develop deep (i.e., 30-40-50% energy savings) and replicable retrofit strategies … In the absence of government mandates, [efficient construction practices] will only reach true scale when market players view them as sound financial investments.” (See Lovins: We’re Only Scratching the Surface on Energy Efficiency.)
Leading by example with EE in state facilities.

The agency noted the state’s 2015 energy plan identified lighting as one of the biggest EE opportunities.

“Since then, utilities’ efficiency programs have focused heavily on lighting. At the same time, costs of high-efficiency lighting products have come down and natural adoption [has] increased, resulting in a greater portion of the lighting savings potential being achieved in the years since this study was published as compared to other end uses.

“However, this data shows several other high-potential, end-use opportunities in addition to lighting — specifically, cooling and water heating. This highlights a need to broaden the scope of utility programs to address other cost-effective efficiency measures and to encourage approaches that pair lower-cost opportunities like lighting with other efficiency improvements to achieve deeper savings.”

Utility EE programs have had success in reducing energy use in lighting but major savings remain in cooling, and water heating, NYSERDA says.| *NYSERDA*

The state Public Service Commission will take steps to implement the white paper, beginning with a technical conference.

“Following the initial technical conference, DPS Staff will initiate and define a process and schedule supporting further development of the jurisdictional aspects of the white paper,” NYSERDA said. “This is expected to include additional technical conferences, as well as topical working groups and a formal written stakeholder comment process with the goal of developing an adequate record for commission action, including benefit, cost, and practical implementation information.”

April 26, 2018June 17, 2024

NYISO Board Rejects Appeals on Capacity Votes

By Rich Heidorn Jr.

The NYISO Board of Directors has rejected two appeals of Management Committee votes on capacity zones and locational capacity requirements.

The board decli n ed to override the committee’s Feb. 28 vote that fell short of the threshold for authorizing a Tariff change to create rules for establishing and eliminating capacity zones. The committee had voted 54.1% in favor, short of the 58% required. (See “MC Rejects On Ramp/Off Ramp Changes” in NYISO Management Co m mittee Briefs: Feb. 28, 2018.)

The issue arose from Tariff revisions approved by FERC in 2012, setting rules for creating new capacity zones in the New York Control Area. The changes led the ISO to create a new capacity zone for the G, H, I and J load zones in the Lower Hudson Valley and New York City.

In denying an appeal by Central Hudson Gas & Electric and the New York Power Authority, the board said although some stakeholders called for developing rules for eliminating zones, FERC has not required them. The Independent Power Producers of New York (IPPNY), Cricket Valley Energy Center, Castleton Commodities Merchant Trading, Roseton Generating and the Long Island Power Authority (LIPA) opposed the appeal.

In 2017, ISO staff launched the “On Ramps and Off Ramps” project to consider rules for eliminating zones and concluded the deliverability-based approach used for creating zones was inappropriate for cancelling them. Staff said a reliability-based transmission security approach would be better for both creating and eliminating zones.

IPPNY said the change would distort market price signals and create uncertainty. Although it opposed the appeal, LIPA said it favors changes to the capacity zone rules.

“While we acknowledge the considerable time and effort NYISO staff and stakeholders spent developing the proposal, we deny appellants’ request that the NYISO take the extraordinary measure of filing the proposal pursuant to [Federal Power Act] Section 206,” the board said, calling “unpersuasive” the appellants’ contention that current rules are unjust and unreasonable.

“The NYISO has filed Tariff amendments pursuant to Section 206 only a few times in its history. The facts and circumstances presented here do not warrant that approach. Even if the board were so inclined, we do not believe the NYISO could satisfy the significant burden of proof required to implement the proposal pursuant to a Section 206 filing.”

The appellants’ arguments regarding price impacts on customers were not persuasive, the board said.

“Appellants assert that retaining a locality longer than needed causes undue price separation and would result in ‘excess costs’ for Zone J and Zones G-I customers. However, they calculate potential excess costs to consumers based on current system conditions in which there exists a continued reliability need for the G-J Locality to remain in place. Under system conditions that might support elimination of the zone, the cost impact of retaining the zone — if any — would be much lower,” the board continued. “We note that NYISO staff performed an analysis that illustrated, among other scenarios, the potential for adverse consumer impacts of prematurely eliminating a capacity zone. Appellants’ papers are silent on the NYISO’s consumer impact analysis, offering instead a conclusory economic assessment that is based upon incorrect assumptions.”

The board declined to remand the issue for further work but said stakeholders could consider it during the annual issue prioritization process.

Locational Capacity Requirements

In a related matter, the board also reje c ted an appeal from LIPA, NRG Energy and Helix Ravenswood, which asked the board to override the Management Committee’s Feb. 28 vote approving a change in how the ISO calculates locational capacity requirements (LCRs). The measure passed with a 77.55% vote. (See “Alternative Methods for Determining LCRs” in NYI S O Management Committee Briefs: Feb. 28, 2018.)

NYISO calculates the LCRs to maintain the statewide installed reserve margin (IRM) set by the New York State Reliability Council (NYSRC) based on the one-day-in-10 years loss-of-load expectation (LOLE).

The LCR rule change replaces the “TAN 45” methodology adopted for the 2006/07 capacity year, before the creation of zones G-J. Loads in the Lower Hudson Valley complained that TAN 45 increases their local requirement while reducing requirements for New York City and Long Island.

The new rules, originating from an economic approach recommended by Independent Market Monitor David Patton, are based on the lowest cost-to-supply capacity.

Opponents of the change called for more study of the issue. LIPA contends that the new method underestimates the capacity costs for a new unit in its zone and that it is being forced it to subsidize New York City, noting that its LCR is expected to increase to more than 100% of peak load, while the city is expected at less than 80%.

New York City and 60 large industrial, commercial and institutional energy consumers opposed the appeal of the rule change.

In rejecting the appeal, the board said the rule change was a “significant improvement” that had been “carefully developed, thoroughly vetted and received widespread support from market participants.”

“Contrary to appellants’ assertions that the new approach would introduce volatility, analysis indicates that the alternative LCR methodology will provide results that are more stable than the current approach,” the board said.

The board also turned aside arguments that the new methodology is flawed because it does not optimize the IRM calculation along with the LCR calculations, saying it “ignores the fact that the IRM is set by the NYSRC — not the NYISO.” The board said the ISO will work with the Reliability Council to explore a co-optimized approach but the new rules should not be delayed by that effort.

The board said, “Concerns over ‘rate shock’ are unpersuasive.”

“The NYISO is open to further discussion on [subsidization concerns and] … alternative approaches to cost allocation,” it said. “Such discussion is outside the scope of the instant proposal, however, and should not delay [its] implementation.”

April 26, 2018

AEP: ‘Halfway There’ to Wind Catcher Approval

Buoyed by recent positive developments, American Electric Power (AEP) CEO Nick Akins had several reasons Thursday to proclaim the company “in better shape than in the first quarter of last year.”

Not even falling pennies short of the Zacks Consensus Estimate for first-quarter earnings could dampen his mood. AEP posted earnings of $473.2 million and $0.96/share, similar to 2017’s first quarter ($474.3 million, $0.96/share) but missing the Zacks estimate of $1.00/share.

Paraphrasing Jon Bon Jovi, one of the Rock and Roll Hall of Fame’s newest inductees, Akins, who sits on the Hall’s board of directors, told analysts during a conference call, “This phrase will stick with you the rest of the day: We’re halfway there, living on a prayer, take our hand and we’ll make it, we swear.

“So, enjoy the ride with American Electric Power.”

Just this week alone, AEP saw FERC approve a settlement reducing the base return on equity for its PJM transmission companies to 9.85% (See “AEP ROE Reduced to 9.85% in Settlement” in Com p any Briefs.) and its Public Service Company of Oklahoma (PSO) subsidiary reach a se t tlement with several consumer groups over its Wind Catcher pr o ject.

“Wind Catcher is finally feeling some tail winds,” Akins said, referring to the massive 2-GW, $4.5 billion wind farm in the Oklahoma Panhandle. “We have accomplished settlements in Arkansas, Louisiana and now Oklahoma … that provides the framework for the various commissions to bless this significant project and its benefits for our customers.”

Akins said AEP is working to add other parties in Oklahoma to the settlement, including Oklahoma Corporation Commission staff. The state’s attorney general, Michael Hunter, opposes the project, saying PSO did not follow a competitive bidding process and doesn’t need the generation.

Akins admitted AEP is not likely to get Hunter “on board” but said the outreach will continue. He said the company is also continuing efforts to reach a settlement in Texas and hopes to have regulatory approvals in May and June.

“I think [the project] is framed up pretty well because a lot of work’s been done in the background,” Akins said. “As far as I’m concerned, we’re in a very good place.”

During AEP’s annual stockholder meeting Tuesday, Akins sa i d the Columbus, Ohio-based company plans to invest $17.7 billion in capital ($12.8 billion in wires infrastructure, $1.7 billion in renewable energy) over the next three years. That capex does not include Wind Catcher.

AEP’s share price closed at $69.77/share Thursday, up 1.1% from its open.

Xcel Expects Approval of Texas Wind Farm

Xcel Energy CEO Ben Fowke said Thursday he expects the Texas Public Utility Commission to approve its Southwestern Public Service (SPS) subsidiary’s request to build a 478-MW wind farm in West Texas.

The commissioners appeared to be grappling with approving the company’s request during their April 13 open meeting. They questioned SPS and parties to a unanimous settlement on the proposal about the legal justification for a project when there is no apparent need for the capacity and asked for more information. (See Texas Regulators Seek More Details on SPS Wind Project.)

The commissioners asked for more information before Friday’s open meeting.

Asked by an analyst during Xcel’s quarterly earnings call what he expects from the PUC, Fowke said, “We’re expecting approval.

“We think the project’s driving tremendous benefits for consumers,” he said. “There were some questions asked [by the PUC], and they’ve been answered. You can always have more discussion, but our thought is it will be approved.”

The company’s proposal has been endorsed by PUC staff, who are also part of the settlement between the utility and various consumer groups.

SPS announced last year it intends to build 1.23 GW of wind generation through a pair of wind farms in Texas and New Mexico and a long-term contract from another facility as part of parent Xcel’s multistate inve s tment in wind. Xcel said the projects will save the region’s customers about $2.8 billion over a 30-year period.

New Mexico’s Public Regulation Commission has already approved the facility.

Minneapolis-based Xcel repor t ed first-quarter earnings of $291 million, or $0.57/share, up from $239 million and $0.47/share a year ago. That beat analysts’ projections of $0.51/share.

Fowke borrowed lyrics from Minnesota rockers Prince (“s ometimes i t snows in A p ril”) and Bob Dylan (“ … trees, be n t over backwards in a hurricane breeze”) to illustrate recent severe weather that drove up profits.

Xcel’s share price gained 71 cents Thursday, finishing at $46.53/share after opening at $45.67/share.

— Tom Kleckner