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November 13, 2024

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New York Looks to Expand Energy Programs in 2019

By Michael Kuser

After winning a third term in November, Gov. Andrew M. Cuomo last month announced 2019 plans that include tackling climate change with a program reminiscent of Franklin D. Roosevelt’s first 100 days as president during the Great Depression.

“New York must be the most progressive state in the nation moving to renewables,” Cuomo said Dec. 17. “There is new economic growth potential, and New York will launch the Green New Deal to make New York’s electricity 100% carbon neutral by 2040 and ultimately eliminate the state’s entire carbon footprint.”

Con Edison CEO John McAvoy (right) leads New York Gov. Andrew M. Cuomo on a tour of a substation in Astoria Queens where an electrical fault on 138,000-volt equipment caused a sustained electrical arc flash visible across a wide area of the city on Dec. 27. Cuomo asked state regulators to investigate the incident, which disrupted operations at LaGuardia Airport and a nearby subway line. |  Gov. Cuomo

Cuomo’s effort will build on the state’s energy-related progress over the past year, which included a draft carbon pricing proposal, energy storage programs and new targets for offshore wind and energy efficiency.

The same day Cuomo spoke, the state’s Integrating Public Policy Task Force (IPPTF) met for the last time before handing over its final carbon pricing proposal to IPPTF Hands off Carbon Pricing Proposal to NYISO.)

NYISO and the New York Public Service Commission created the task force in 2017 to explore ways to price carbon into the wholesale electricity markets to align them with state decarbonization policies, including the zero-emission credit program for uneconomic nuclear plants.

NYISO published the IPPTF Carbon Pricing Proposal on Dec. 7 after recommending it no longer require emissions-free resources with existing renewable energy credit contracts pay the carbon component of locational-based marginal prices (LBMPc). The requirement would create “a distortion in the market … that places the ISO in the position of picking winners and losers,” an ISO official said. (See IPPTF Updates Carbon Charge Analysis, Treatment of RECs.)

Emissions reductions from a carbon charge in New York | Brattle Group

Offshore Wind is Coming

2018 should prove to be a watershed year for the development of offshore wind, now poised to become a significant source of New York’s energy over the next decade. Early last year, Gov. Cuomo released the comprehensive New York State Offshore Wind Master Plan, which calls for 2.4 GW of offshore resources by 2030.

In July, the New York Public Service Commission authorized state agencies to procure 800 MW by this year. (See NYPSC: Offshore Wind ‘Ready for Prime Time’.) In consultation with the New York Power Authority and the Long Island Power Authority, the New York State Energy Research and Development Authority on Nov. 8 followed up with a request for proposals for 800 MW of offshore wind energy (ORECRFP18-1).

NYSERDA expects to announce the first offshore wind contract award in the second quarter of 2019 and, if needed, issue a second solicitation this year to meet the 800-MW goal of the first tranche.

The U.S. Department of Energy last year awarded a NYSERDA $20.5 million grant to lead a nationwide research and development consortium for the offshore wind industry, with the state matching the federal funds. The consortium in November issued its R&D Roadmap, and in December published its first report, an examination of several technical challenges facing the industry.

The consortium will issue a series of RFPs throughout the four years of federal funding, with the first R&D solicitation planned for next month. Initial project awards are expected to be selected by the end of March.

Energy Storage

New York regulators last month approved measures that will sharply increase the state’s energy storage and efficiency targets. The state’s Department of Public Service and NYSERDA in June issued New York’s Energy Storage Roadmap, and the PSC adopted many of its recommendations.

Rulings by the PSC last year doubled New York’s existing 2025 storage goal to 3,000 MW by 2030 and require the state’s utilities to reduce building energy use by an additional 31 trillion British thermal units (TBtu) to meet an energy efficiency target of 185 TBtu by 2025. (See NYPSC Expands Storage, Energy Efficiency Programs.)

The commission’s Dec. 13 storage order (Case 18-E-0130) said that the targeted deployment of energy storage “will result in reductions in system peak load demand during critical periods, increases in the overall efficiency and resiliency of the electric grid, and displacement of fossil fuel-based generation.”

Deployment scenario resulting in 1,500 MW of energy storage by 2025 | NYSERDA

Resulting public benefits include more than $3 billion in gross lifetime benefits to New York’s utility customers, creation of approximately 30,000 jobs, about 2 million metric tons of avoided greenhouse gas emissions and improved public health by avoiding air-pollutant emissions such as nitrogen oxides, sulfur oxides and particulates.

The order also authorized $310 million in market incentives to be administered by NYSERDA for pairing storage with solar projects, in addition to the $40 million announced the previous month. It also directed the utilities to hold competitive procurements for 350 MW of bulk-sited storage systems.

NYSERDA and the DPS also developed the state-mandated energy efficiency targets (Case 18-M-0084), which now include a 3% annual reduction in electricity sales by 2025 and 5 TBtu of savings from the installation of heat pumps, which help reduce emissions from the heating and cooling of buildings.

CEO Transition

NYISO CEO Brad Jones left the organization abruptly in mid-October and was replaced — at least temporarily — by General Counsel Robert Fernandez. The ISO declined to elaborate on the reason for the departure, except to say it was “a personal decision by Brad.” (See Brad Jones out at NYISO.)

Stakeholders told RTO Insider that senior ISO officials at the time told them the news was a surprise to them. “It’s a really big mystery … it came out of nowhere,” said one stakeholder who asked not to be identified.

The ISO’s Board of Directors has yet to say whether it will initiate a search for another chief executive. Fernandez was named the ISO’s general counsel and chief compliance officer in 2000 after stints at Long Island Lighting Co. and independent power producer Sithe Energies.

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RC Transition, California Wildfires Will Occupy 2019

By Hudson Sangree

CAISO will tackle its new role as reliability coordinator for much of the West in 2019, and California lawmakers will struggle with preventing wildfires sparked by power lines.

Major events in 2018 prompted both efforts.

CAISO will oversee reliability coordination in much of the West from its headquarters in Folsom, Calif. | CAISO

In July, Peak Reliability stunned the West by announcing it would end its RC operations across the Western Interconnection by the end of 2019. That set off a competition between CAISO and SPP to sign up clients for their own RC services.

Then in November the deadliest wildfire in state history leveled the town of Paradise, Calif., killing 85 residents in the Sierra Nevada foothills. Suspicion quickly fell on PG&E for the Camp Fire, prompting talk of state action to reform or break up the utility.

Other challenges that faced California and the West in 2018, and will continue in 2019, include making CAISO’s congestion revenue rights more equitable to ratepayers and continuing efforts to establish a Western RTO led by CAISO.

Keeping Reliability Coordination Reliable

Peak Reliability stunned the electricity sector in July when it announced it would wind down its role as reliability coordinator for the West and withdraw from its effort to develop a regional electricity market competing with CAISO. The Vancouver, Wash.-based company said it would shut its doors as early as Dec. 31, 2019, after transitioning its customers to other RCs. (See Peak Reliability to Wind Down Operations.)

Several months before the announcement, CAISO, a Peak RC customer, said it would “reluctantly” leave Peak, develop its own RC services and offer them to others at reduced costs. Most of the Western Interconnection signed nonbinding letters of intent to take advantage of CAISO’s RC services.

CAISO’s move was seen as a reaction to Peak entering a partnership with PJM to form a Western RTO to compete with the ISO’s expansion.

FERC approved a set of Tariff revisions covering CAISO’s new RC services in November, clearing the way for about 72% of the region’s load to sign on with CAISO, compared with 12% for SPP. BC Hydro is proceeding with plans to provide RC services for its own territory in British Columbia, representing about 7% of load in the region overseen by the Western Electricity Coordinating Council. (See CAISO RC Effort Gets FERC Go-ahead.)

CAISO, SPP and BC Hydro are scheduled to take over Peak’s duties in four handoffs through 2019. CAISO will assume the RC role for its existing territory on July 1. BC Hydro will become the RC for a large swath of southwestern Canada on Sept. 2. CAISO will then take over RC services for many areas outside of California on Nov. 1, while SPP will take responsibility for other regions of the West on Dec. 3, although NERC is encouraging the RTO to accelerate its timeline to match CAISO’s.

The process provides ample opportunities for errors and shortcomings, including staff attrition at Peak, those involved say. Some employees have already left Peak, and others could follow. The company is hoping that severance packages will encourage most others to stay until they’re no longer needed.

CAISO and SPP will become the reliability coordinators for the Western Interconnection in 2019. | WECC

Jim Shetler, general manager of the Balancing Authority of Northern California and chair of Peak’s Member Advisory Committee, briefed WECC board members on the transition process in December, saying he had concerns about whether Peak would remain in business until the transitions are completed at the end of 2019.

“What keeps me up nights [is worry over] whether Peak is a going concern in the next 12 months,” Shetler said during the board meeting at WECC headquarters in Salt Lake City. (See RC Transition is Fraught with Pitfalls, WECC Hears.)

Others have said they’re confident the transition will go as planned, but all agree it will be important keep a close eye on the RC switchovers in 2019 to avoid lapses in critical services.

“This is a risky year, and I think everyone’s posture is really focused on this,” Linda Jacobson-Quinn, regulatory compliance manager for the Farmington Electric Utility System in New Mexico, told WECC in December. “At the end of the day, it’s the customers that must have an RC.”

Wildfire Policy Could Target IOUs

When the California State Legislature reconvenes Jan. 7, one of its first orders of business will be dealing with the problem of catastrophic wildfires, particularly those sparked by electrical equipment operated by investor-owned utilities.

Lawmakers thought they’d made significant progress in 2018 when they passed SB 901, a 71-page bill of wildfire prevention measures that included new vegetation management and reporting requirements for the IOUs. The measure, signed into law by Gov. Jerry Brown in September, also provided a means for IOUs to issue long-term bonds to cover wildfire liability costs. (See California Wildfire Bill Goes to Governor.)

PG&E’s costs have been estimated in the billions of dollars for a series of devastating fires in Northern California wine country during the 2017 fall fire season. State fire officials have declared the utility at fault for at least 16 of the fires, though the Tubbs Fire, which wiped out part of the city of Santa Rosa, remains under investigation.

Brown and other policymakers worried about PG&E’s solvency following the 2017 blazes and enacted the bond provision, but that measure didn’t cover fires in 2018, and the Camp Fire’s estimated costs could equal or exceed all the wine country fires combined. PG&E’s stock price took a pounding in the days after the Camp Fire and remains less than half of what it was before the blaze.

The Camp Fire started at 6:33 a.m. on Nov. 8 near Tower :27/222 on PG&E’s Caribou-Palermo 115 kV transmission line, the California Department of Forestry and Fire Protection (CalFire) and PG&E reported in December. PG&E told the California Public Utilities Commission it had experienced a fault and fire near Tower :27/222 shortly before the Camp Fire ignited. (See PG&E Grapples with Line Safety After Camp Fire.)

If CalFire investigators eventually find PG&E equipment caused the fire, the utility could be held liable for all resulting damage, even without a showing of negligence, under the controversial legal doctrine known as “inverse condemnation,” the strict liability standard California applies to utilities for fires sparked by power lines.

During their 2019/20 session, state lawmakers likely will consider clean-up legislation that allows utilities to issue bonds to pay for 2018 fires. With public anger high, however, elected officials may fear a backlash for any bill deemed a bailout for PG&E or other IOUs.

Another possibility being discussed is state action to break up PG&E and hand over control of some of its parts to cities such as San Francisco. (See Camp Fire Prompts Talk of PG&E Bailout or Breakup.)

Changing PG&E’s corporate governance also is on the table.

National Guard soliders searched through rubble in November after the Camp Fire tore through Paradise, Calif., killing 85 and casting suspicion on PG&E. | California National Guard

Sen. Bill Dodd, one of the authors of SB 901, has called for a management shakeup at PG&E in the wake of the fatal 2010 San Bruno gas line explosion and the massive fires of 2017/18.

“PG&E has demonstrated a pattern of poor management and illegal conduct that has shattered lives across California,” Dodd said in a Dec. 20 news release. He called for “systematic change, which must include change on the board of directors and in the executive suite.” The utility currently has a “bunker mentality” that prevents improvement in its safety practices, Dodd said.

PUC President Michael Picker said in early December that state regulators would expand their investigation of PG&E’s safety practices after the Camp Fire. (See CPUC Expands Probe Into PG&E Practices After Deadly Fire.)

“This is the kind of thing that keeps me awake at night,” Picker said at the time.

On Dec. 21 the commission released a ruling regarding the investigation that asked whether the company’s management should be replaced, whether members of its board of directors should resign, and whether the company should be broken up into separate gas and electric divisions.

In the meantime, PG&E has vowed to do better. “We are acting decisively now to address these real and growing [wildfire] threats, and we are committed to working together with our regulators, state leaders and customers to consider what additional wildfire safety efforts we can all take to make our communities safer,” company CEO Geisha Williams said in a December news release.

CRR Shortfalls and Regionalization

CAISO’s other priorities in 2019 will include its continuing efforts to rein in congestion revenue rights insufficiencies that have left ratepayers footing a bill of about $100 million per year, according to the ISO’s Department of Market Monitoring.

The chronic shortfall in CRR revenues, which are allocated based on power consumption, has been an ongoing problem for CAISO. This year the ISO sought FERC’s approval for changes it hoped would help in 2019, but the commission only gave CAISO part of what it wanted.

In November, FERC accepted an ISO revised proposal, providing for CRR holders to be paid for their entitlements “only to the extent the CAISO collects sufficient revenue through day-ahead market congestion revenues and other sources to fund those entitlements.” (See FERC OKs CAISO Plan to Deal with CRR Shortfalls.)

CAISO may also continue to pursue its efforts to form a Western RTO, despite the failure of several proposals in recent years to begin the process. The latest, AB 813, failed to make it out of a legislative committee in 2018. The bill would have started the process of turning CAISO into an RTO by initiating changes in its governance structure to allow for out-of-state members.

California lawmakers have been opposed to relinquishing state control. CAISO’s governors are now appointed by the California governor and confirmed by the Senate. At the same time, industry leaders from other Western states don’t want to cede authority to a CAISO board controlled from Sacramento.

Proponents of a Western RTO have said they’ll probably take another run at regionalization in 2019. (See Western RTO Proponents Vow to Keep Trying.)

As Ralph Cavanagh, co-director of the energy program at the Natural Resources Defense Council, put it to a Northwest industry group in October: “We need a big bipartisan win, and I don’t think we’ll get it on carbon tax in the short term, but I’ll tell you a place where we can get it … enhanced regional grid integration.”

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ISO-NE Pulls off Fuel Security, CASPR Measures

By Michael Kuser

ISO-NE closed out 2018 like a trucker wheeling a wide load down a twisting service road on the flanks of Mount Washington. Despite a few bumps, scrapes and scares along the way, it delivered on time — in this case dispatching key market initiatives.

The RTO’s most important issues are winter fuel security and addressing the states’ desire to bring in more carbon-free resources, but it also must plan to operate a grid that is already experiencing a surge in renewable energy resources — with massive amounts of offshore wind energy now visible on the horizon. (See Mass. Offshore Lease Auction Nets Record $405 Million.)

The bumps and scrapes last year came in a contentious stakeholder process over both issues and in FERC approvals accompanied by criticisms, dissents and partial dissents by various commissioners.

FERC last month approved the ISO-NE’s interim proposal to use an out-of-market mechanism to address concerns about fuel security in a region heavily reliant on natural gas and in March approved its two-stage capacity auction to accommodate state renewable energy procurements. (See Split FERC Approves ISO-NE CASPR Plan.)

Controversy in the Details

Soon after a severe cold snap last January, ISO-NE published an operational fuel security analysis that found the New England grid is vulnerable to a season-long outage at any of the region’s major energy facilities. (See Report: Fuel Security Key Risk for New England Grid.)

In a related issue, Exelon in March said it would retire its 2,274-MW Mystic Generating Station in Massachusetts after the facility’s capacity obligations expire in May 2022.

FERC in July denied an ISO-NE a Tariff waiver to enter a cost-of-service agreement to keep Mystic Units 8 and 9 running after the expiration, instead directing the RTO to revise its rules to allow such agreements to address fuel security.

The commission last month finally approved a Mystic agreement, including payments to the Exelon-owned Distrigas LNG facility that supplies the plant with fuel, while also ordering a paper hearing on the issue of return on equity for the units. (See FERC Approves Mystic Cost-of-Service Agreement.)

Winter LNG deliveries to New England interstate pipelines | ISO-NE

Reserve Energy Bank

In a concurring opinion in last month’s fuel security order, FERC Commissioner Richard Glick said “ISO-NE’s apparent need to retain units for fuel security is the result of a market failure” (ER18-2364).

“Winter energy security is a good problem for markets,” said a report on fuel security prepared by Brattle Group on behalf of NextEra Energy Resources. “New England’s energy security challenge can be converted into demand for clearly defined products that many, diverse resources can compete to provide at least cost … [but it’s] essential that any chosen solution will provide planners/operators with the certainty that winter reliability will be maintained, thus avoiding any need for out‐of‐market intervention.”

In a related effort to address fuel security issues holistically, ISO-NE Vice President for Market Development Mark Karl said in November that the RTO is proposing to incorporate into the real-time market an additional constraint that looks at the ability to provide energy storage — or an energy bank.

“I want to be careful here because it’s easy to think about this from the standpoint of conventional generator fuel, but this will apply to any sort of resource that has the ability to maintain essentially a reserve bank of energy that can be converted into electricity when needed,” Karl said.

The idea is to optimize the use of limited energy over more extended periods compared with how markets are currently designed to optimize energy over the course of an operating day, he said. (See New England Talks Energy Security, Public Policy.)

New Renewables

ISO-NE proposed the Competitive Auctions with Sponsored Policy Resources (CASPR) construct last January to address state regulators’ concerns about ratepayer costs for policy-driven resources and generators’ fears that out-of-market procurements would suppress capacity prices.

In the commission’s March ruling on CASPR (ER18-619), Commissioner Robert Powelson dissented, while commissioners Cheryl LaFleur and Richard Glick criticized the minimum offer price rule (MOPR) included in the measure.

Under CASPR, ISO-NE will clear the Forward Capacity Auction as it does today, applying the MOPR to new capacity offers to prevent price suppression. In the second Substitution Auction generators with retirement bids that cleared in the primary auction will transfer their obligations to subsidized new resources that did not clear because of the MOPR. The RTO will phase out the renewable technology resource exemption, which has allowed it to clear 200 MW of renewable generation in its capacity auction annually (to a maximum of 600 MW) without regard for the MOPR.

Integration of new renewable resources is not a problem for the RTO and likely won’t be for the next decade, ISO-NE Vice President of Market Operations Robert Ethier told industry stakeholders in November. It’s a two-fold economic challenge involving the energy and capacity markets.

“Bring in these zero-marginal-cost resources and insert them into our real-time supply stack, and it lowers energy prices for everyone … [and] when the states contract for these resources, they don’t just affect the energy market, they also affect our capacity market,” Ethier said.

Having new state-sponsored resources buy out old resources in the market will help manage and ration the entry of these resources into the market and prevent price suppression, he said. (See Canada, New England Talk Trade, Politics and Clean Energy.)

The CASPR filings include proposed Tariff revisions to allow a renewable technology resource to be located out of state — such as in federal waters offshore — and still qualify for a MOPR exemption.

Renewable energy advocates RENEW Northeast supported the RTR revision, as did Vineyard Wind, a partnership between Avangrid Renewables and Copenhagen Infrastructure Partners that last May won the contract to supply Massachusetts with 800 MW of offshore wind energy. (See Mass., R.I. Pick 1,200 MW in Offshore Wind Bids.)

Progress on Emissions

The RTO last month issued its draft 2017 ISO New England Electric Generator Air Emissions Report, which showed that since 2001 sulfur-dioxide emissions have declined 98%, nitrogen oxide by 74% and carbon dioxide by 34%.

Regional emissions of SO2, NOX and CO2 declined in 2017 compared to the previous year, according to preliminary data, with lower emissions due largely to a decline in electricity generation by power plants that use fossil fuels, said the report. The year-over-year declines continued long-term reductions in the emissions produced by New England power plants.

ISO-NE Total System Emissions: 2016 and 2017 New England system emissions (ktons) and emission rates (lb/MWh) (all figures are preliminary). | ISO-NE

NEPOOL Press Ban Proceeding

In August, the New England Power Pool asked FERC to approve amendments to its Agreement to codify an unwritten policy of banning news reporters and the public from attending the group’s stakeholder meetings (ER18-2208). The group drafted the revisions after RTO Insider reporter Michael Kuser applied for membership in NEPOOL’s Participants Committee as an End User customer in March.

RTO Insider responded to NEPOOL’s filing with a Section 206 complaint asking the commission to overturn the organization’s ban or terminate the group’s role and direct ISO-NE to adopt an open stakeholder process like those used by other RTOs (EL18-196). New England is the only one of seven U.S. regions served by RTOs or ISOs where the press and public are prohibited from attending stakeholder meetings.

In a motion to dismiss RTO Insider’s protest, NEPOOL said FERC lacks jurisdiction to force changes and that the publication lacks standing to challenge the rules. (See NEPOOL: FERC Can’t Change Press, Public Ban.)

RTO Insider’s filed response included letters submitted by six U.S. senators and 12 members of the House of Representatives calling on FERC to open the meetings. (See New England Senators Urge FERC to End Press Ban.)

It also included a copy of a Sept. 6 RTO Insider article quoting former FERC Commissioners Pat Wood and Nora Brownell as saying they were unaware of NEPOOL’s closed-door policy when they approved it as ISO-NE’s stakeholder body. (See Wood, Brownell: Unaware of Press Ban When OK’d NEPOOL.)

Public Citizen filed comments challenging NEPOOL’s claim that its members “voted overwhelmingly against having press reporters as NEPOOL members” at the June 26 Participants Committee meeting. Only 115 of NEPOOL’s more than 500 members were present or had proxies at the meeting.

While 32 votes were cast in favor of the press ban, 24 members were opposed and 59 abstained. In addition, NEPOOL records show that six officers or their associates represented companies that provided 21 of the 32 votes for the ban.

The six have conflicts of interest in voting for the ban because they earn income selling “intelligence” about NEPOOL proceedings, said Tyson Slocum, director of Public Citizen’s Energy Program.

The matter is pending before the commission.

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MISO to Address Growing Supply Shortage in New Year

By Amanda Durish Cook

MISO will spend much of 2019 working on how it can prevent the increasingly frequent emergency conditions it experienced in 2018.

In spring, CEO John Bear said 2018 marked “13 years in standing up what is one of the world’s largest energy markets.” But that undertaking didn’t come without challenges, and the RTO zeroed in on efforts exploring how it can temper them in 2019.

Last year roared in with an extreme cold snap and multiple generation outages in MISO South that forced the RTO to call a maximum generation event, later prompting MISO: Sept. Emergency Response Improved by Jan. Event.)

MISO Board of Directors in December | © RTO Insider

Stopgap Filings

By then, MISO had decided to file expected Tariff changes earlier than planned, hoping to free up an additional 5 to 10 GW of capacity in time for the spring 2019 outage season. (See MISO, Stakeholders at Odds over Resource Availability Filings.)

“There’s some discomfort with where we are, so some were asking what we could do before … the spring outage season,” Director of Resource Adequacy Coordination Laura Rauch said during a Nov. 7 Resource Adequacy Subcommittee meeting.

MISO made two FERC filings Dec. 21 that will require load-modifying resources (LMRs) to produce seasonal availability documentation and subject demand response to annual capability testing (ER19-650, ER19-651). A filing for a new 120-day notice time for planned outages will follow in January.

“The MISO region is transitioning from a generation portfolio dominated by coal and nuclear generation resources to a portfolio that relies on an increasing quantity of intermittent and emergency-only resources — even to meet MISO’s planning reserve requirements,” the RTO explained in both filings. “Baseload generation retirements have increased the pace of this transition and have caused MISO to operate with actual capacity margins that have consistently been decreasing towards minimum resource requirements. … Operating at or near minimum reserve margin requirements exposes the MISO region to greater impacts from correlated risks (e.g., extreme weather events and natural gas availability).”

Almost 12 GW (about 9%) of MISO resources are classified as LMRs, accessible only as part of emergency load management. The RTO had not called on LMRs for a decade after a localized Wisconsin emergency in February 2007 but has relied on them three times since 2017.

Independent Market Monitor David Patton has suggested “deep-sixing” the RTO’s current forced outage calculations in favor of a four-season capacity auction that will use generators’ averaged economic maximums during a season. That way, he argued, outages will be better anticipated, and MISO can dispense with members’ questionable outage reporting.

“Outage reporting is just not that reliable,” Patton said during an Oct. 11 Market Subcommittee meeting.

In addition to the three smaller FERC filings, MISO will this year focus on developing long-term fixes to keep its fleet more available during peak demand times. The RTO aims to implement the longer-term solutions throughout the first half of 2021.

MISO will also dedicate time in 2019 to devising a new load forecasting process. The RTO hopes to implement an approach that would have both Purdue University’s State Utility Forecasting Group and consulting firm Applied Energy Group working with 20-year forecasts provided by load-serving entities. (See MISO Presents Load Forecasting Compromise.)

Low Capacity Prices

In his 2017 State of the Market report issued last June, Patton said the “fundamental problem” with diminishing capacity can be traced to “the relatively low net revenues generated in MISO’s markets.” (See MISO Clears at $10/MW-day in 2018/19 Capacity Auction.)

By Patton’s count, MISO lost 3.8 GW of resources in 2017, mainly comprising gas-fired resources in MISO South and coal-fired resources in the Midwest. In contrast, the RTO added just 1.2 GW of new resources.

Patton continues to call for a more “functional” capacity market in MISO and has also blamed FERC for not issuing a rule set on RTO capacity markets.

“I think we may have to wait for this to play out in court,” Patton said during a June meeting of the MISO Board of Directors’ Markets Committee, predicting that competitive asset owners would soon sue. They have just as much right to recover costs as regulated utilities, he contended.

“I don’t think it’s right to ignore the competitive suppliers and think their issues are immaterial,” Patton added.

Some stakeholders have said MISO’s recent auction clearing prices do not reflect the tighter operating conditions that it claims, with many pointing out that for the past three years, clearing prices never come close to the RTO’s $25/MW-day conduct threshold. The 2019/20 capacity auction will be the first to use external capacity zones. (See FERC OKs MISO External Capacity Zones, Dispute Deadlines.)

Packed Queue and Storage Beginnings

MISO fuel mix under MTEP 18 futures | MISO

MISO might find some future capacity relief in its brimming interconnection queue and new rules that will open its markets to storage resources.

But the interconnection queue poses its own complications, as most of the proposed assets are intermittent resources.

Clair Moeller | © RTO Insider

During the June board meeting, MISO President Clair Moeller said that bringing on all the 90 GW then in the queue would lead to 40% renewables in the RTO’s resource mix. According to an ongoing MISO study on renewable penetration, such a mix would result in an “inflection point” where it becomes more difficult to manage the system.

“We’re going to need some pretty significant transfer capability or we’re going to be curtailing,” Moeller said.

Since then, the queue has shrunk to about 82 GW because of drop-outs.

MISO also filed to comply with FERC Order 841 in early December, outlining a participation model requiring storage resources commit to the market through four main modes: discharging, charging, continuous and outage status (ER19-465).

The first three modes carry must-run designations and will be cleared between a resource’s minimum and maximum discharge limits. The plan also allows for emergency commitments. For metering purposes, withdrawals will be treated as negative generation and categorized as wholesale. (See MISO Offers Storage Proposal, Promises to Exceed Order 841.) MISO is requesting its plan become effective Dec. 3, 2019.

“Allowing electric storage resources to participate fully in MISO’s markets will enhance competition, promote greater market efficiency and help support the resilience of the bulk power system,” Executive Vice President Richard Doying said in a release.

Meanwhile, MISO is accelerating storage-as-transmission rules. So far, the RTO is only considering pared down rules that would allow storage to function simply as transmission into the MTEP 19 cycle, buying it time to consider broader rules for resources that serve both market and transmission functions. To include storage projects in its 2019 Transmission Expansion Plan, MISO will make a limited Tariff filing in February — if it is “aggressive” enough to meet the timeline, Director of Planning Jeff Webb said during a Nov. 14 Planning Advisory Committee meeting.

“If we have storage projects in the MTEP, but no rules for them, then we won’t accept them because there is no policy,” Webb said.

MISO interconnection queue as of December 2018 | MISO

Hartburg-Sabine in the Books

MISO this year bid out its second-ever competitive transmission project, awarding construction of the proposed Hartburg-Sabine line in East Texas to NextEra Energy.

NextEra proposes to spend $115 million on a new 23-mile 500-kV line, four short 230-kV lines and a new Stonewood 500-kV substation, crossing Orange, Newton and Jasper counties in East Texas. The company estimates the project will have a 2.2:1 benefit-cost ratio and will be in service by June 2023. It said NextEra’s proposal had the third-lowest cost per mile of 500-kV line at $3.2 million. (See NextEra Wins Bid to Build MISO’s 2nd Competitive Project.)

“NextEra thoroughly identified, considered and discussed environmental risks and mitigation and was among the most thorough in completion of supporting design studies for the project,” MISO said in a selection report. The company took into account the high-water mark during Hurricane Harvey and ensured the substation site will not be within a 100-year or 500-year floodplain, according to the RTO.

So Long, and Thanks for the Metairie

By the end of 2019, MISO will have shuttered one of its four office spaces, closing its Metairie, La., office late in the year at a cost of about $900,000, saving the RTO about $500,000 every year thereafter. (See MISO to Turn out Lights on Louisiana Office.)

The RTO is also one year closer to overseeing market operations on a new modular market platform. By the end of 2019, it will announce its chosen vendor to construct the platform, which will be pieced in gradually from 2020 to 2024. (See “Market Platform Replacement Enters Year 3,” MISO Board of Directors Briefs: Dec. 6, 2018.)

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NYISO Board Partially Reverses AC Tx Project Selection

By Michael Kuser

The NYISO Board of Directors on Thursday issued a mixed decision on the ISO Management Committee’s selections for the AC Public Policy Transmission Project.

While the board accepted the committee’s recommendation for one segment, it switched the other to a competing proposal by National Grid and New York Transco.

AC Public Policy Transmission Need in NY | NYISO

The Management Committee — along with ISO staff — had backed two joint proposals by North America Transmission and the New York Power Authority to build two 345-kV transmission projects to address persistent transmission congestion at the Central East (Segment A) electrical interface and Upstate New York/Southeast New York (UPNY/SENY, or Segment B) interface. (See NYISO MC Supports AC Transmission Projects.) Cost estimates for both projects ranged from $900 million to $1.1 billion.

Advised by consultant Substation Engineering Co., ISO staff recommended Project T027, a double-circuit 345-kV line from Edic to New Scotland for Segment A. For Segment B, it endorsed Project T029, a standard 345-kV line from Knickerbocker to Pleasant Valley, despite claims from one bidder that there was a “virtual” tie in benefits among competing projects.

But the board concluded that “the most efficient or cost-effective solution” for Segment B is Project T019, proposed by National Grid’s Niagara Mohawk Power and NY Transco.

“In evaluating Segment B projects, the Board concludes that Project T019’s additional transfer capability drives superior performance across a number of important selection metrics,” the board wrote in its decision.

The board directed ISO staff to modify the draft report for the project accordingly.

Listening to Stakeholders

NYISO staff had analyzed seven proposals for Segment A and six for Segment B before making their choices. However, when the Business Issues Committee recommended the projects last June, several losing bidders protested the ISO’s selection process. (See NYISO BIC Backs AC Tx Projects; Losing Bidders Protest.)

At the June BIC meeting, New York Transco general counsel Kathleen Carrigan read comments the company submitted jointly with National Grid, arguing NYISO’s own metrics showed the National Grid/NY Transco proposal paired with T029 would produce consistently better performance than the ISO’s favored project.

Based on updated transfer limits, project T019 has the lowest cost/MW ratio of all the Segment B projects ($/MW). | NYISO

Project T019 includes “a basic controllable series compensation element to preserve the proposed 345-kV transmission line physical designs that the commission deemed the most environmentally and siting friendly in the underlying AC transmission proceedings,” the comments noted.

When combined, T027 and T019 increase voltage transfer across Central East by 875 MW and UPNY/SENY by 2,100 MW, the companies contended.

“This is a far greater increase than the combination of T027 and T029, which only increases transfer capability along Central East by 825 MW and UPNY/SENY by 1,325 MW,” Carrigan told RTO Insider after the June meeting.

“Projects T027 and T019 have the highest Central East N-1-1 voltage transfer capability of any studied project combination and far surpass combination T027 and T029 with respect to the incremental UPNY/SENY N-1-1 thermal transfer capability. The baseline 20-year incremental energy produced by projects T027 and T019 nearly doubles that of projects T027 and T029. And finally, T027 and T019 produce the highest production cost savings than any other Segment B combination,” Carrigan said.

Additional analysis ordered by the board supported Carrigan’s assertions, finding that when paired, T027 and T019 produced the lowest cost per MW, at $228k/MW.

The ISO estimated T027 will cost $577 million to $750 million, the higher figure including a 30% contingency, while T019 is estimated at $479 million.

The board’s conclusions are summarized in an Addendum to the Draft AC Transmission Public Policy Transmission Planning Report, which goes back to the MC for further review and comment before board members can make their final determination on project selection.

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SPP FERC Briefs: FCAs, NPPD Complaint, Refunds

By Tom Kleckner

FERC Approves SPP’s Streamlined FCA Process

FERC last week approved SPP’s plan to streamline the process by which it designates frequently constrained areas (FCAs), effective Dec. 22 (ER19-166).

The commission had directed SPP to seek approval of any new, removed or modified FCAs when the RTO submitted Tariff revisions in 2012 to implement its Integrated Marketplace. SPP and its Market Monitoring Unit worked with stakeholders to develop the designation process for areas with high levels of congestion and a dominant or pivotal supplier.

The commission agreed with SPP’s argument that the designation process may result in a significant lag between the MMU’s annual evaluation of FCAs and when they are updated in the Tariff. It said SPP’s proposal allows the RTO and MMU to address market power concerns in a timely fashion.

“We find that this delay could result in the inappropriate application of mitigation measures during the lag period or, conversely, the lack of application of mitigation measures when appropriate, potentially allowing market participants to exercise market power,” FERC said.

SPP’s Tariff requires the MMU to re-evaluate FCAs at least annually.

The MMU said it strongly supported SPP’s proposed revisions, noting that under the previous process, it could take up to six months to update the FCA list following its report. With the change, the Monitor’s updates and associated analysis will be publicly available at least 14 days before any updates take effect. Affected market participants can raise any concerns with the MMU.

SPP stakeholders approved the Tariff revision during July’s Board of Directors and Markets and Operations Policy Committee meetings.

The MMU’s 2017 analysis reduced the FCA list to one, effective April 2018. (See SPP’s FCA List Pared to One Area.)

NPPD Complaint Against Tri-State Denied

Tri-State G&T transmission upgrade project in Colorado | Tri-State G&T

The commission denied Nebraska Public Power District’s complaint against fellow SPP member Tri-State Generation and Transmission Association that certain costs in the latter’s annual transmission revenue requirement (ATRR) and its failure to credit certain revenues are unjust and unreasonable (EL18-194).

NPPD alleged that Tri-State unfairly included in its ATRR the costs of two grandfathered agreements (GFAs) and its facilities not physically connected to SPP’s system. It also said Tri-State excluded point-to-point revenue from the credits applicable to revenue requirements for network service. The utility asked the commission to remove all costs related to the two GFAs and the facilities from Tri-State’s ATRR and SPP’s rates for NPPD’s transmission zone, and to include point-to-point revenue as a credit to the cooperative’s revenue requirement.

The complaint stems from Tri-State’s placement in NPPD’s transmission zone when the cooperative wholesale power supplier joined SPP in 2015 as part of the Integrated System. NPPD protested at the time but reached a settlement with Tri-State and SPP in 2017.

FERC ruled the disputed cost components were covered in the settlement agreement, saying that NPPD had failed to demonstrate that without its proposed modifications, the settlement “seriously harms the public interest.”

SPS Gets Partial Approval to Issue Refunds

El Paso Natural Gas’ iconic “Blue Flame” headquarters in El Paso | Texas Historical Commission

FERC granted one of Southwestern Public Service’s three waiver requests related to the issuance of customer refunds, but it rejected a second and dismissed a third as unnecessary (ER18-2377).

The Xcel Energy subsidiary requested the waivers in September, saying it had received a $12 million refund from El Paso Natural Gas (EPNG), which provides fuel to SPS and third-party-owned gas-fired plants on its system. The utility said each wholesale requirements customer has a power supply agreement that contains a fuel cost adjustment clause, through which SPS recovers fuel transportation costs.

The commission accepted SPS’ request for a waiver of section 35.14 of FERC’s regulations, which limits the fuel cost adjustment clause to the recovery of current fuel costs. That clears the way for the utility to issue about $3 million in refunds to eight of its current and former wholesale customers.

FERC rejected the utility’s request for a waiver of section 35.19a of its regulations and its methodology for computing interest on refunds. SPS requested the waiver to avoid paying interest for the period between its receipt of the refunds from EPNG and the distribution of refunds to SPS’ wholesale customers.

The commission said the utility’s arguments were insufficient to explain why it should be exempt from paying interest.

Finally, FERC dismissed SPS’ request for a waiver from the utility’s fuel cost adjustment protocols as unnecessary, saying they don’t conflict with providing EPNG refunds to wholesale requirements customers.

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FERC OKs Mich. Wind GIA, Leaves Open Funding Issue

By Amanda Durish Cook

FERC last week accepted a revised generator interconnection agreement (GIA) between MISO and a Michigan wind farm, avoiding complex analysis from the fallout of a vacatur of the commission’s previous orders covering transmission owners’ ability to fund network upgrades.

The Dec. 20 order allows Invenergy’s 150-MW, 60-turbine Crescent Wind Farm near the Michigan-Ohio border to interconnect to the MISO system under a revised agreement that eliminates TO Michigan Electric Transmission Co.’s (METC) “unilateral right to elect to provide initial funding for network upgrades” (ER18-2340). The new GIA allows METC to provide initial funding for network upgrades “only upon mutual agreement with the interconnection customer.”

Crescent Wind Farm interconnection site map | MISO

In approving the GIA, FERC focused on the requested effective date, not the issues still in flux around agreements executed between mid-2015 to mid-2018, after the D.C. Circuit Court of Appeals early this year vacated FERC orders dealing with TOs’ rights to fund upgrades.

MISO in July submitted a pre-emptive Section 205 filing to retain the option to allow new generators to self-fund interconnection transmission upgrades. (See MISO Files Revised Upgrade Funding Provisions.) FERC dismissed that filing as moot after deciding TO initial funding should be included in MISO’s pro forma GIA only prospectively as of Aug. 31, 2018. It instituted a briefing schedule to determine how to address GIAs, facility construction agreements and multiparty facility construction agreements that were entered into between June 24, 2015, and Aug. 31, 2018.

FERC said because MISO and Crescent Wind filed for an Aug. 15, 2018, agreement effective date, MISO’s previous pro forma GIA should be followed, which allows TOs to provide initial funding for network upgrades “only upon the mutual agreement of the interconnection customer.”

“We find the amended agreement to be just and reasonable because such language was not included in MISO’s pro forma GIA as of the effective date of the amended agreement,” FERC said.

METC had requested FERC reject the amended agreement, arguing that MISO’s removal of the funding language is premature because the commission is still working through whether to include language allowing the initial TO funding of network upgrades for all GIAs executed between June 24, 2015, and Aug. 31, 2018. METC also pointed out that the agreement does not contain any network upgrades that would be subject to TO initial funding. FERC did not address the argument.

The Crescent Wind GIA is also exempt from FERC Order 842 primary frequency response requirements because MISO requested an exemption for all projects having reached at least the second decision point in its interconnection queue before May 15, 2018.

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FERC Approves Mystic Cost-of-Service Agreement

By Michael Kuser

FERC last week voted 2-1 to approve ISO-NE’s cost-of-service agreement with Exelon for its Mystic Generating Station Units 8 and 9, including payments to the company’s Distrigas LNG facility. It also ordered a paper hearing on the issue of return on equity for the plants.

FERC Chairman Neil Chatterjee and Commissioner Cheryl LaFleur approved the order — issued after the commission’s open meeting Thursday — with Commissioner Richard Glick dissenting (ER18-1639). The agreement becomes effective June 1, 2022.

The RTO sought the agreement after Exelon said in March that it would retire the 2,274-MW plant when its capacity supply obligations expire on May 31, 2022 (ER18-1509).

The commission tentatively accepted the agreement in July while ordering an expedited hearing on unresolved issues. (See FERC Advances Mystic Cost-of-Service Agreement.)

The agreement would allow the gas-fired units in Massachusetts an annual fixed revenue requirement of almost $219 million for capacity commitment period 2022/23 and nearly $187 million for 2023/24. But the commission found the information Exelon provided to support those figures insufficient and ordered the company to submit a compliance filing within 60 days of the order.

In the most recent order, the commission directed Mystic to adopt Exelon’s capital structure for ratemaking purposes, include an amortization of excess deferred income taxes and amend the agreement to state that it will recover 91% of the costs of Distrigas as Mystic fuel costs, determining that other New England beneficiaries of the LNG terminal should bear some of its operational costs.

Glick’s Dissent

In his dissent, Glick argued the commission “cannot and should not use its authority over wholesale sales of electricity to bail out an LNG import facility. … The commission concludes that it can use the [Federal Power Act] to bail out an LNG import facility simply because that LNG import facility has an undefined and unexplained ‘extremely close relationship’ to the Mystic facility.”

The commission is attempting to regulate the costs incurred and sales made by a non-jurisdictional facility, he said.

“A more reasonable construction of the commission’s jurisdiction would be to limit its reach to the entities that can or actually do participate directly in the wholesale market for electricity,” he said.

“The jurisdictional puzzle in which the commission now finds itself only reinforces the fundamental mistake that the commission made in rushing to seize control of the debate over fuel security in New England and dictate a particular outcome. That outcome, ‘individual, ad hoc contracts with particular resources whose retirement might, under the most conservative assumptions, create a fuel security concern,’ is no way to address a region’s long-term fuel security,” Glick said, quoting from his previous dissent in the commission’s July tentative acceptance of the agreement.

FERC on Dec. 3 approved ISO-NE’s interim proposal to use an out-of-market mechanism to address concerns about fuel security (ER18-2364). (See ISO-NE Fuel Security Measures Approved.) The RTO’s Tariff had previously only allowed cost-of-service agreements to respond to local transmission security issues, with the interim proposal developed in response to FERC’s July denial of a request for waiver to allow for the Mystic agreement. (See FERC Denies ISO-NE Mystic Waiver, Orders Tariff Changes.)

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New Mexico Regulators Say PNM Can Join EIM

By Hudson Sangree

New Mexico regulators on Thursday gave Public Service Company of New Mexico (PNM) permission to join the Western Energy Imbalance Market, clearing the way for the state’s largest electric utility to begin participating in the interstate real-time market in April 2021.

The Public Regulation Commission voted 5-0 to allow the move by PNM, which declared its intent to join the EIM in August. (See PNM Seeks to Join Energy Imbalance Market.)

The New Mexico Wind Energy Center is among the resources that PNM could bring to the Western Energy Imbalance Market. | PNM

CAISO, which administers the EIM, welcomed PNM in a news release, saying the utility’s participation would increase the EIM’s efficiency in trading resources across the West. New Mexico is fast becoming one of the West’s largest producers of wind power, and California has a legal mandate to gather an increasing share of its electricity from renewable resources.

PNM generates about 2,580 MW of electricity, including 800 MW from low- or zero-carbon resources, CAISO said.

“The diversity and location of PNM’s resources, along with the transmission connectivity to the rest of the EIM footprint will provide significant benefits to their customers,” CAISO said in its statement.

The EIM has generated a half-billion dollars in benefits for its members since its founding in November 2014, including $100 million in the third quarter of 2018 alone, CAISO has said.

The EIM’s current members include Arizona Public Service, Idaho Power, NV Energy, Portland General Electric, Puget Sound Energy and Powerex. The Los Angeles Department of Water and Power, the Sacramento Municipal Utility District and several other entities are scheduled to join between 2019 and 2021.

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GAO Critical of TSA Pipeline Security Efforts

By Rich Heidorn Jr.

The Transportation Security Administration’s oversight of natural gas pipeline security is hampered by staffing constraints and vague criteria for identifying critical facilities, the Government Accountability Office reported last week.

Pipeline security reviews conducted, fiscal year 2010 through July 2018 | GAO Analysis of Transportation Security Administration

TSA’s Pipeline Security Branch, which is responsible for more than 2.7 million miles of natural gas, oil and hazardous liquid pipelines, currently has only six full-time equivalent employees. Staffing has fluctuated from a high of 14 in fiscal year 2013 to only one in 2014. The agency, part of the Department of Homeland Security, also lacks a “strategic workforce plan” to identify the skills required of its employees, such as cybersecurity expertise.

GAO also found TSA has not updated its risk assessment methodology since 2014 to reflect current threats to pipelines and that its data sources and underlying assumptions on threats and vulnerabilities are not fully documented. Its risk assessment has not been peer reviewed since it was initiated in 2007, the report said.

Although TSA issued revised guidelines in March 2018 incorporating most of the National Institute of Standards and Technology’s “Framework for Improving Critical Infrastructure Cybersecurity,” it did not include all of the framework and lacks a formal process for revising the guidelines on a regular basis. “Without such a documented process, TSA cannot ensure that its guidelines reflect the latest known standards and best practices for physical security and cybersecurity, or address the dynamic security threat environment that pipelines face,” GAO said.

GOA
Map of hazardous liquid and natural gas transmission pipelines in the U.S., September 2018 | U.S. Department of Transportation

Critical Facilities

The guidelines also lack clear definitions to ensure that pipeline operators identify their critical facilities — one reason, auditors speculated, that one-third of the 100 largest pipeline systems have not identified any critical facilities.

TSA’s eight criteria lack “additional examples or clarification … to help operators determine criticality,” the report said.

GAO said pipeline operators told it that pipelines may interpret one TSA criterion, “cause mass casualties or significant health effect,” differently. “One of these operators that we interviewed stated that this criterion could be interpreted either as a specific number of people affected or a sufficient volume to overwhelm a local health department, which could vary depending on the locality. Another operator reported that because TSA’s criteria were not clear, they created their own criteria which helped the operator identify two additional critical facilities.”

GAO said one unnamed industry association it met with is working with TSA to develop supplementary guidance for its members to clarify the agency’s critical facility criteria. The American Gas Association (AGA), which represents more than 200 local distribution companies, confirmed it is the group mentioned.

TSA conducts security reviews of the largest 100 companies, but it hasn’t checked in the last five years whether its recommended improvements are being followed, leaving it unable to know whether its efforts are reducing risks, the report said.

Based on the company reviews, TSA may also review the security on a company’s critical facilities. Although the reviews are voluntary, TSA told auditors no company has ever rejected an inspection request.

The agency conducted 23 corporate reviews and about 60 facility reviews in fiscal year 2018 (through July 31). In 2014, when the safety unit had only one FTE, it conducted no corporate reviews and about 30 facility reviews.

U.S. natural gas and oil pipeline systems’ basic components and examples of vulnerabilities | GAO Analysis of Transportation Security Administration

Dispute on Mandatory Rules

At FERC’s open meeting Thursday, Chairman Neil Chatterjee said the GAO report “reiterated” concerns he and Commissioner Richard Glick expressed in a June op-ed calling for mandatory reliability standards for natural gas pipelines like those the commission and NERC enforce on the grid. “Despite having the authority to enforce mandatory cybersecurity standards, the TSA relies on voluntary ones,” they wrote.

Glick said TSA performs a valuable role in airport security but is ill-suited for overseeing pipeline security. “I continue to believe that Congress should … consider moving authority over gas pipeline cybersecurity to another agency such as the Department of Energy.”

Chatterjee said that although the GAO report identified gaps, he has been pleased by recent efforts by industry and DHS to improve pipeline security, including the creation of a risk assessment program that includes DHS, TSA, DOE and FERC.

In a press release, Don Santa, CEO of the Interstate Natural Gas Association of America (INGAA), also cited what he called his group’s “partnership” with TSA, DHS and DOE to conduct cybersecurity assessments of pipelines, saying, “This interagency approach will bring to bear the particular expertise of each agency, along with those of the industry itself.” INGAA says its 26 members represent most of the interstate natural gas transmission pipeline companies in the U.S. and Canada.

But he rejected the idea of mandatory standards. “In this environment of rapidly evolving cyber threats, it is important that we take an approach that enables flexibility and allows us to quickly adapt and update protocols,” he said. “Experience shows that mandatory standards are all too often outdated almost as soon as they are introduced. We need the flexibility and ability to build on our baseline practices to look forward towards addressing the threats of the future.”

AGA said in a statement that GAO’s criticism “is missing the mark.”

TSA officials “understand the industry and have a strong working relationship with natural gas utilities,” said AGA CEO Dave McCurdy, who called for expanding the agency’s budget and staff “so that they can come into our member companies and make the assessments themselves. In addition to our numerous voluntary programs in the cybersecurity arena, we believe that this is the best way to build upon the success of this public-private partnership.”