Federal Suit Challenges NY Nuclear Subsidies

By Ted Caddell and William Opalka

Despite its best efforts to avoid litigation, the New York Public Service Commission saw its Clean Energy Standard challenged in federal court Wednesday by a group of energy companies and trade groups calling the rule’s subsidies to several nuclear power plants unconstitutional.

The suit, filed in U.S. District Court for the Southern District of New York in Manhattan, claims the zero-emission credits (ZECs) intrude on FERC’s jurisdiction over interstate electricity transactions, asking the court to find them invalid and order the PSC to withdraw them from the CES.

The ZECs are “purely protectionist in nature, enacted for political reasons to save jobs at the subsidized generators and the property tax revenues there from,” said the plaintiffs, which include Dynegy, Eastern Generation, NRG Energy and the Electric Power Supply Association.

The CES, adopted by the PSC in August, mandated that New York obtain 50% of its power from renewable resources by 2030. The ZECs were seen as a way to keep the state’s nuclear plants operating while utility-scale renewables are built. The 12-year subsidies would help keep open Exelon’s R.E. Ginna and Nine Mile Point and Entergy’s James A. FitzPatrick plant, the sale of which to Exelon is pending regulatory approval.

Nine Mile Point | Constellation Energy Nuclear Group

When it issued its order, the PSC said it had revised it in a way that it believed would avoid legal issues that caused the U.S. Supreme Court to void a contract between Maryland and Competitive Power Ventures in Hughes v. Talen. (See NY Attempts to Thread Legal Needle with Clean Energy Standards, Nuke Incentives.) The court found the contract unconstitutional, as it was tied to prices in PJM’s capacity market, over which FERC has jurisdiction. The PSC instead tied the price of its ZECs to EPA’s social cost of carbon and the price of carbon allowances in the Regional Greenhouse Gas Initiative.

The plaintiffs, however, said the ZECs were still tethered to FERC-regulated wholesale energy prices and thus unconstitutional.

“Apparently recognizing that its original proposal was plainly unconstitutional under Hughes, the PSC staff hastily revised its recommendation in July 2016 and changed the formula for determining the amount of ZEC subsidies,” they said. “Although the new formula was ostensibly based upon a federal interagency working group’s ‘social cost of carbon,’ this was window dressing, changing the name but not the intent to replace the FERC-determined energy price with a state-determined energy price.”

The plaintiffs argued that the subsidies disadvantage out-of-state generators who participate in NYISO’s markets.

“The ZEC order is directly discriminatory, as only specified New York nuclear facilities are eligible to receive ZECs,” they said. “Although states have the right to regulate the retail sale of electricity within their own borders, the wholesale sale of electricity involves interstate commerce, which the state may not regulate. NYISO’s wholesale marketers are interstate and international in nature, as they involve the sale and transmission of energy and capacity from generators located in other states and in Canada, and the purchase of such commodities by customers in other states.”

They also claimed that the ZECs could inhibit competition because they “would cause more efficient interstate generators to leave the market and discourage the entry of new competitors.”

Proponents of the CES were quick to denounce the suit.

“This lawsuit, filed by gas, oil and coal generators, is blatantly putting specific business interests ahead of what is best for New York,” said Gary Toth, vice chair of the County of Oswego Industrial Development Agency.

“Today’s lawsuit … is wholly inconsistent with the values of the countless New Yorkers who want to achieve a clean energy future,” said Ted Skerpon, chairman of the IBEW Utility Labor Council of New York.

“The bottom line here is that eliminating the nuclear provision from the CES will cause electricity prices to spike and will put thousands of New Yorkers out of work,” said Gregory Lancette, president of the Central-Northern New York Building and Construction Trades Council.

“Ultimately, if upstate nuclear plants close, it is the generation facilities that burn coal, oil, and gas that will benefit from the electricity price spikes that would result,” said Dave Young, president of the Rochester Building & Construction Trades Council.

Downstate Legislators Blast ZECs Again

On Monday, a group of New York City-area legislators again blasted the ZECs in a second letter sent to the PSC.

The legislators, now numbering seven, also said the PSC’s response to their first letter mischaracterized their opposition. (See New York Legislators Question Nuclear Subsidy.) They said they support the standard’s renewables goal but contend that the $965 million ratepayers will spend on the subsidies over the first two years of the program will be disproportionately borne by downstate ratepayers. They again called for the cost review of the power plants’ operating costs to be made public.

Audrey Zibelman, NY PSC Chair © RTO Insider

“The commission has kept the cost review concealed from the public, presumably on the grounds that the costs of the nuclear plants are trade secrets, but the commission in its order acknowledged there was little competition involved,” the letter states. “Upon sale of the FitzPatrick plant, Exelon/Constellation will become nearly the exclusive owner. Accordingly, there is no justification for withholding this information on the basis that the costs are protected trade secrets.”

The PSC responded to the first letter by saying the benefits of low emissions are shared statewide. It also has said the move toward a low-carbon energy portfolio would suffer if the nuclear plants retired prematurely.

October 19, 2016

UPDATED: PJM to Seek FERC OK for Seasonal Capacity Proposal

By Rich Heidorn Jr. and Rory D. Sweeney

pjm ferc seasonal capacity — Adam Keech, PJM | © *RTO Insider*

COLUMBUS, Ohio – PJM officials said Wednesday they will seek FERC approval of the RTO’s seasonal capacity proposal despite a lack of stakeholder consensus.

The proposal, which would relax the current prohibition on seasonal resources aggregating across locational deliverability areas, received less than one-third support in a Seasonal Capacity Resources Senior Task Force poll last month. (See No Consensus Among PJM Stakeholders on Seasonal Resources.)

Adam Keech, executive director of PJM market operations, told the annual meeting of the Organization of PJM States Inc. that the PJM Board of Managers had approved making a FERC filing in November.

In addition to what Keech called PJM’s “facilitated aggregation” proposal — which is intended to improve the ability of intermittent resources and demand response to participate in the capacity auction — the RTO also will consider changes in load forecasting and incorporating summer DR’s curtailment capabilities after the auction, Keech said.

“We’re looking for other ways to value seasonal resources” in addition to changes in capacity rules, Keech said. “We recognize there’s more work to be done in this area.”

Keech said PJM’s proposal is a response to complaints that the aggregation options offered to seasonal resources under Capacity Performance rules are unworkable because of the difficulty summer and winter resources had in “finding one another” and reaching commercial agreements.

Under the proposal, PJM would match summer and winter resources, eliminating the need for commercial ties between them. Summer and winter resources would have separate six-month obligations and would not be liable for another resource’s nonperformance.

The RTO’s proposal also would allow resources to aggregate beyond LDA borders, with unmatched resources moving up to the next LDA level until a match is found. For example, an offer containing individual resources located in the EMAAC LDA and SWMAAC LDA would be modeled in the MAAC LDA. An offer with resources in COMED and EMAAC would be modeled in the “Rest of RTO.” Performance penalties would be distributed evenly between the resources, no matter which failed to perform.

Measurement Rules, Injection Rights, Load Forecasting

Keech said PJM also will propose a change in how it measures winter DR, returning to the former firm service level (FSL) calculation “that is more conducive for demand response capability for industrial resources.”

PJM also plans to propose that wind be able to obtain higher winter capacity injection rights, in recognition that wind farms, which are rated at a 13% capacity factor in the summer, can produce 40% of their nameplate capacity in the winter. Hydro resources “potentially” could receive higher winter injection rights as well, Keech said.

Another initiative will seek ways to better incorporate DR into load forecasts, which would reduce costs by reducing the amount of capacity procured. PJM’s current method requires load reductions to be repeated for 15 years before they are reflected in the load forecast, Keech said. “There’s probably some room to improve in that area,” he said.

In addition, PJM is considering registering summer load curtailment capabilities after the capacity auction, which he said will borrow from its former interruptible load for reliability (ILR) program and “operational attributes” concept.

“We realize the operational flexibility value to that,” Keech said, adding “the details remain to be ironed out.”

Mixed Reception

The announcement of PJM’s plans got a mixed reception from other speakers at the OPSI meeting.

John Farber, an analyst with the Delaware Public Service Commission, called PJM’s choice “disappointing.”

Susan Bruce, counsel for the PJM Industrial Customer Coalition, said the group supports PJM’s filing. “We think it will help with the next auction,” she said. “It’s not a silver bullet though.”

Katie Guerry, of DR aggregator EnerNOC, made a pitch for her company’s proposal, which combined PJM’s plan with a “balancing ratio” that changes how DR is valued. It won support from one-third of the task force. Keech said PJM is discussing whether to apply the balancing ratio — currently used only for generation — to other resources.

James Wilson, a consultant for state consumer advocates, said PJM’s proposal falls short of his winter performance equivalents plan, which would auction “WIPES” credits that allow capacity resources to not perform in the winter. Opposed by PJM, Wilson’s proposal was supported by less than a quarter of task force members.

Wilson said the 2014 polar vortex was “a real wake-up call on the value of winter capacity” and said the CP rules properly created much stronger incentives for performance.

But he said CP went in the “wrong direction” in not recognizing the seasonal nature of both capacity resources and PJM’s peak loads. PJM’s projected 2020 summer peak load is 20,000 MW greater than its winter peak in a 50/50 forecast — with the difference rising to 26,000 MW in a 90/10 forecast.

“PJM’s reliability studies have always suggested that all of the outage risk is really in the summer, not in the winter,” he said.

Wilson said his “simple simulation” found that a “full seasonal” approach would save ratepayers about $1 billion annually by procuring 20,000 MW less in winter and accommodating more participation by seasonal resources — solar, wind and DR.

He said separate summer and winter price signals “would be potentially very helpful” for both renewable developers and gas-fired generators weighing the cost of obtaining firm gas supplies in winter.

Wilson praised PJM’s efforts to revise its load forecasts to recognize increasing energy efficiency. The changes reduced the forecast peak for the 2019/20 Base Residual Auction by 5,660 MW (-3.5%). (See Changes to PJM Load Forecast Cuts Benchmark Peaks.)

“But it’s too soon to … conclude that we’ve solved the over-forecasting problem,” Wilson said.

No Consensus in Task Force

The task force polled members last month on five proposed rule changes, with the most popular proposal — retaining the base capacity product for an additional year, delivery year 2020/21 — claiming 43% support. Only 48% of members who voted favored any change, while 52% chose the status quo.

Bruce Campbell of energy management company CPower said “a handful of large entities” can skew the voting in lower committees not subject to sector-weighted voting because they have multiple business units represented with stakeholder votes. “It’s my opinion that that probably has happened in this case,” he said.

October 19, 2016

CFTC Exempts RTOs from Private Rights of Action

By Tom Kleckner

The U.S. Commodity Futures Trading Commission on Tuesday unanimously issued a final order granting SPP’s request to exempt certain energy transactions in the RTO from the Commodity Exchange Act (CEA) and commission regulations.

The order is similar to the commission’s March 2013 ruling that provided six other grid operators with the same exemption, according to CFTC. But it also exempts those transactions from private rights of action, judicially inferred rights to relief that could have left the RTOs and their market participants as potential targets for lawsuits outside the FERC process.

The commission simultaneously amended its 2013 order to expressly exempt the six other grid operators from private actions, it said. SPP was not a party to the original order because its day-ahead market was not in operation, but it filed a “me-too” exemption in 2013 when it became apparent the market would soon be live. In response, the commission said in May that it never intended to protect the RTOs from private actions.

The ruling was expected after CFTC Chairman Timothy Massad said in a September letter to Sen. John Boozman (R-Ark.) that he would recommend the commission provide the exemption, reversing his previous position after receiving substantial industry feedback. (See CFTC Chair Flips on Private Rights of Action in RTO Markets.)

cftc private rights of action — Boozman (L) and Massad

Commissioners J. Christopher Giancarlo and Sharon Y. Bowen joined Massad in a seriatim process, in which the commissioners vote in sequence and in private, rather than at an open meeting. Massad and Giancarlo have both issued statements supporting their votes.

Mike Ross, SPP’s senior vice president of government affairs and public relations and a former six-term Arkansas congressman, guided the effort that provided 38 comments against the proposed rule to allow private actions. There were only five comments in favor.

“We’re pleased with the commission’s decision to keep existing exemptions in place,” Ross said in response to the ruling.

October 18, 2016

Mexico’s Grid Operator to Explore Participation in EIM

By Robert Mullin

An isolated area of Mexico’s grid already interconnected with California could become the first non-U.S. participant in the Western Energy Imbalance Market.

El Centro Nacional de Control de Energía (CENACE) — Mexico’s grid operator — and CAISO today announced an agreement to explore the benefits of having the Baja California Norte region join the West’s only real-time energy market.

While the region has no transmission connections with Baja California Sur or Mexico’s mainland grid, it boasts two 230-kV links with California through the Imperial Valley and Otay Mesa substations. Those lines, known as Path 45, provide about 800 MW of transfer capacity.

caiso eim cenace — The isolated Baja California Norte region’s only transmission interconnections are to the north – with California. | *Mexico Ministry of Energy*

“CENACE’s Baja California Norte participation in the Western EIM will enable it to benefit from the savings that a large geographic region can offer,” CAISO CEO Steve Berberich said in a statement.

Baja already hosts natural gas-fired generation built in part to serve California’s market, including Sempra Energy’s 625-MW Termoelèctrica de Mexicali and Intergen’s 1,100-MW La Rosita. Deliveries into Imperial Valley can serve San Diego County via the 500-kV Sunrise Powerlink, which was energized in 2014.

The region also has promising potential for wind energy, which is increasingly valuable to California as the state seeks to balance its solar-heavy portfolio in pursuit of a 50% renewable standard. Sempra’s Energía Sierra Juárez, a 155-MW wind farm completed near the U.S. border last year, operates under a 20-year power purchase agreement with San Diego Gas and Electric.

“Mexico has had a long, productive relationship with the ISO as we coordinate the management of our interconnected electricity grids,” CENACE General Director Eduardo Meraz said. “It is only logical for CENACE to carefully consider Baja California Norte’s participation in the Western EIM, with its promises of lower-cost electricity and increased renewable integration.”

Mexico’s energy policy requires the country to generate 30% of its electricity from hydro and other renewable sources by 2021, a mandate that increases to 35% in 2024.

Legislation enacted in 2014 named CENACE the nationwide grid operator and partially deregulated Mexico’s power sector, allowing for expanded private sector participation. The agency, which manages the nation’s wholesale electricity market, operates more than 33,000 miles of high-voltage transmission.

The recently expanded EIM has four members operating in eight U.S. states: Arizona Public Service, NV Energy, PacifiCorp and Puget Sound Energy. (See Arizona Public Service, Puget Sound Energy Begin Trading in EIM.)

October 17, 2016

Monitor Says FERC Erred in PJM FTR Ruling, Seeks Rehearing

By Rory D. Sweeney

PJM’s Independent Market Monitor asked FERC on Friday to reconsider its “flawed” ruling on PJM’s financial transmission rights market, saying it “contradicts the fundamental purpose of returning congestion revenues to load” (EL16-6-001, ER16-121).

bwj5qlkorwocayk5c6nh_full_bowring-joseph-monitoring-analytics-rto-insider — Bowring, PJM’s IMM | © *RTO Insider*

“A consistent theme of the Sept. 15th order is the unsupported view that load must provide guaranteed and risk-free funding of FTRs as a hedge against day-ahead congestion, and that this is somehow in the interest of load,” the Monitor wrote in its rehearing request. “This approach, favored by the financial participants who own most FTRs, is not consistent with the reason that FTRs exist and has no basis in market logic.”

The commission’s order rejected PJM’s proposal to reduce Stage 1A infeasible auction revenue rights by increasing its zonal load forecast growth rate, saying the change would result in unnecessary transmission projects because it would rely on outdated source and sink points. The commission also rebuffed PJM on its plan to eliminate the netting of negative ARRs in a portfolio against positive ones.

FERC also ordered PJM to allocate balancing congestion to real-time load. It gave the RTO until Nov. 14 to submit a compliance filing. (See FERC Finds PJM ARR/FTR Market Design Flawed; Rejects Proposed Fix.)

An FTR entitles its holder to credits based on locational price differences in the day-ahead energy market when the transmission grid is congested. FTRs can be purchased or converted from ARRs, which are allocated to network and firm point-to-point customers.

market monitor ferc pjm financial transmission rights — | *PJM*

The Monitor’s request argues that FERC departed from precedent and contradicted earlier orders in striking balancing congestion from the FTR definition.

“Elimination of the total congestion revenues rule means that load-serving entities will be forced to pay to make up the difference when congestion revenues paid to FTR holders are in excess of the total congestion revenues collected,” the Monitor said. “This requires load to pay total congestion, including day-ahead and balancing, and then pay balancing again when it is negative. This is not consistent with the objective of the FTR/ARR design, which is to return congestion revenues to load.”

The Monitor described FERC’s ruling on portfolio netting as “unexplained” and said it “fails to address extensive arguments and examples that show the portfolio netting rule does result in cross subsidies.” The netting rule should be eliminated, the Monitor argued, because it “provides unjustified subsidies to participants holding FTRs with negative target allocations.”

It also challenged the commission’s determination that the Stage 1A allocation rule is necessary, saying it “avoids addressing the actual problem: the complete disconnect between the allocation of ARRs and actual system usage.” The Monitor said “the entire concept of generation to load paths is archaic, reflecting the contract path approach to physical transmission rights prior to the introduction of market.”

October 17, 2016

Report: Calif. ‘Duck Curve’ Growing Faster than Expected

By Robert Mullin

A new research report indicates that the belly of CAISO’s “duck curve” is deepening more quickly than originally expected, with its effects increasingly spread across the year — and not just on the typical spring day depicted by the graph.

The report from consulting firm ScottMadden also suggests that distributed energy resources such as rooftop solar are contributing only modestly to the decline in net load and ramping rates associated with the widespread adoption of solar energy in California.

california duck curve utility-scale solar — The ScottMadden report contends that growth in distributed energy resources is keeping a lid on total load growth, but has little impact on system load —and, therefore, the deepening of the duck curve. | *Scott Madden*

“The duck curve is driven by utility-scale solar in California, not distributed resources,” the report says.

The report’s authors contend that understanding the root causes and impact of the curve is necessary for responding appropriately to its effect on grid operations.

“If we are to effectively address renewable integration challenges, it is imperative that we understand and address the actual issues that exist,” the report says. “Solutions for a seasonal, weekend, utility-scale solar issue may well be different than solutions for an everyday, distributed resource issue.”

California’s duck curve first appeared in 2013, the product of CAISO’s effort to forecast the long-term impact of increased renewable penetration on its daily operations.

That forecast demonstrated how the adoption of solar and other renewable resources would steadily undercut the ISO’s “net load,” which represents the portion of load that must be served by dispatchable resources such as gas-fired generation and imports. The net load calculation looks at total load for a given interval and subtracts energy generated by variable renewable resources.

Load Declines not Limited to Spring

The duck-shaped curve illustrates how daytime solar output crowds out the need for dispatchable resources during much of the day. That, in turn, creates the need for the sharp ramping of dispatchable resources as the sun begins to set. Over the long term, that ramp is expected to grow steeper as more solar resources come online and further depress net load as the state seeks to meet a 50% renewable energy mandate.

While CAISO’s original duck curve forecast predicted that minimum net load would fall to about 15,000 MW in 2016, this past spring already saw that figure — represented by the curve’s trough — sink to a low of 13,894 MW, a 31% decline from 2011. (See Solar is the Generation of Choice in California.)

Since 2011, ScottMadden said, CAISO’s daytime minimum net loads have been declining throughout the year, not just during the spring periods characterized by low residential loads coupled with relatively high solar generation. Furthermore, steep ramps are becoming more frequent, with the late-day three-hour ramp exceeding 5,000 MW on 58% of days in 2015, compared with 6% in 2011. Last year’s steepest ramp was 10,091 MW, a 62% increase from four years earlier, the report shows.

And the most significant ramps are occurring in fall and winter, when California’s net loads are at their lowest. In 2015, the 20 steepest ramps occurred in December (10), November (eight) and January (two).

The firm’s analysts also determined that the sharpest ramps consistently occur on weekends, the low point for weekly loads. Weekend ramps average 10% higher than those occurring on weekdays.

Weekends More Prone to Impacts

“These results suggest that weekends are more prone to experience the impacts of the duck curve because of their lower system loads,” the report says. “Conversely, higher system loads on weekdays mitigate the midday decline in net load and the impact of the duck curve.”

Perhaps most important from a system planning perspective, the report attempts to dispel the notion that DER is contributing significantly to the shape of the duck curve.

The authors explain that, while behind-the-meter distributed resources and energy efficiency appear to be offsetting growth in California’s total load, together they have little impact on the shape of the daily curve of system load — or load that must be supplied by system resources.

The authors back this claim by comparing CAISO — where distributed resources are just 3% of utility-scale capacity and do not participate in the wholesale market — with Hawaii, where residential solar represents 9% of generation managed by the state’s largest utility. In California, daytime system load has changed little since 2011, while Hawaii has seen a sharp decline over the same period.

Based on those findings, grid solutions need not “be totally dependent on complex DER management,” the report contends.

“Instead, the operational challenges associated with utility-scale solar present the potential for more targeted utility-scale solutions,” the report says.

October 17, 2016

SPP Strategic Planning Committee Briefs

LITTLE ROCK, Ark. — Heather Starnes, counsel for the Missouri Joint Municipal Electric Utility Commission, briefed the Strategic Planning Committee on Thursday on the work that the Billing Determinant Task Force she chairs has done in developing a business practice for behind-the-meter generation.

| © RTO Insider — Michael Deselle, SPP (left) and Mike Wise, Golden Spread Electric Coop | © *RTO Insider*

The task force has produced a revision request (BRR158) that sets guidelines to determine a customer’s network load and define the parameters for what should be considered BTM generation.

However, the Regional Tariff Working Group remanded the change back to the task force in June to address SPP’s request to delineate responsibility for reporting network load. With the consolidation of SPP’s legacy balancing authorities into one, Starnes said the RTO has been having difficulty gathering complete zonal information from the transmission zones’ lead transmission owners.

“SPP’s position is they would like to see something created that mimics what it did before we created the consolidated balancing authority,” she said.

Under the revision, network load would include all network service, including the sum of generators’ metered values behind the delivery point. If the generator’s meter data is not available when it’s online, network customers would use its nameplate rating.

Starnes said the task force meets later this week and hopes to send BRR158 back to the RTWG for final consideration.

LP&L Task Force Looks at Precedent

SPC Chair Mike Wise, senior vice president of commercial operations and transmission for Golden Spread Electric Cooperative, encouraged the task force studying the migration of Lubbock Power & Light’s load to ERCOT to identify any strategic implications of the municipality’s exit. (See Texas PUC OKs ERCOT, SPP Studies on Lubbock Move.)

“This is an entirely new study process,” he said.

“Certainly there are broader implications beyond just Lubbock,” said Oklahoma Gas & Electric’s Jake Langthorn, the Exit Study Task Force’s chair. “It’s kind of an absence of facts … no one’s given much more thought at this point to what happens, but we’ll certainly pursue that as well.”

SPP and ERCOT are conducting separate studies on LP&L’s proposal to move 430 MW of load into the Texas market in June 2019. The grid operators will file a joint report to the Public Utility Commission of Texas next spring, though it has yet to be determined who will pay for the studies.

“Where’s Lubbock?” one member asked pointedly. PUC Chair Donna Nelson has said she doesn’t believe ERCOT ratepayers should pay for the studies, a sentiment shared in ERCOT.

“I didn’t get the sense from anyone in the group that SPP should pick up the costs,” Langthorn said. “We believe the party that wants to get it done, Lubbock, should pick up the costs.”

– Tom Kleckner

October 17, 2016

State Briefs

Judge Recommends Pause To TEP’s Rooftop Solar Plan

An administrative law judge has recommended that state regulators defer approval of Tucson Electric Power’s plans to expand company-owned solar energy programs pending findings of a separate proceeding on the value of rooftop solar.

As part of a renewable energy plan filed last year, TEP wants to expand a program in which it installs solar panels on the roofs of customers who pay a flat monthly fee for power. It also seeks to build neighborhood-scale solar farms and offer nearby customers the power at a flat rate.

Judge Jane Rodda found that expansion should wait until the results of technical studies and potential modifications to net metering tariffs are known.

More: Arizona Daily Star

SolarCity Spent $140K on Corporation Commission Election

SolarCity last week disclosed that it has spent $140,000 on an independent campaign to re-elect Republican Bob Burns and elect Democrat Bill Mundell to the Corporation Commission.

The commission is expected to decide as early as 2017 the rate structure for utility customers who generate some of their own power through solar. The disclosure comes as the commission debates whether to force Arizona Public Service, which is fighting net metering in the state, to disclose how much it spent to influence the election of two Republicans to the commission. Burns has issued a subpoena to APS for its records, but the state attorney general has said that would require a majority vote from the commission.

Mundell and fellow Democrat Tom Chapin have said they would deliver the necessary votes if elected. But Mundell last week lamented the spending on both sides. “I wish everyone would stay out of the race,” he said.

More: Capitol Media Services

CALIFORNIA

SoCalGas Down to Final Safety Tests at Aliso Canyon

Southern California Gas is nine safety tests away from reopening its Aliso Canyon natural gas storage facility in Los Angeles, which it shut down in October 2015 following a massive methane leak.

The state Division of Oil, Gas and Geothermal Resources must approve the company’s safety testing of 114 wells at the facility before SoCalGas can request authority to resume injecting fuel into the field.

Twenty-seven wells have passed all safety tests, nine await results and 78 are temporarily out of operation, according to a report issued by SoCalGas in early October.

More: Reuters

Environmentalists May Receive $72K ‘Interveneor’ Award in San Onofre Case

Environmentalist group Friends of the Earth could receive $72,000 for participating in the investigation of the San Onofre nuclear plant failure, making it the most recent recipient of so-called “intervener” funds. If approved by the Public Utilities Commission, the award would be significantly less than the $483,503 the group sought.

The commission has awarded more than $600,000 to participants in the case, which is the subject of a criminal investigation into improper contacts between regulators and utility executives.

The intervenor compensation program awards money to groups that contribute meaningfully to commission decisions. The program is funded by utility companies, which pass the cost along to customers.

More: The San Diego Union-Tribune

‘Wiring Error’ Blamed for Flare-Off at Torrance Refining

| Source: Torrance Refinery — | *Source: Torrance Refinery*

A “wiring error” associated with an ongoing equipment upgrade project in the South Bay has been blamed for a flare-off last week at Torrance Refining and a power outage affecting some 100,000 Southern California Edison customers.

Torrance Refining was shut down and partially evacuated, according to the Torrance police and fire departments.

Power was restored to the affected customers in parts of Gardena, Hawthorne, Hermosa Beach, Manhattan Beach, Redondo Beach and Torrance.

More: CBS Los Angeles

Committee Recommends Monterey County Join Power Collaborative

Monterey County’s alternative energy and environmental committee took initial steps last week to take local control over electric power purchasing from Pacific Gas and Electric and promote renewable energy.

The committee recommended that its Board of Supervisors sign a resolution to join the Monterey Bay Community Power agency. The agency calls for a collaborative, including Santa Cruz, Monterey and San Benito counties, which would combine their purchasing power to increase renewable energy in their portfolio and use savings from lower-cost power to invest in renewable energy projects.

If the board approves the resolution, the county could start developing a governing joint powers authority agreement and address financing.

More: Monterey Herald

ILLINOIS

Villages Agree to Joint Defense, Confidentiality for Power Line Fight

Five villages bordering the Elgin-O’Hare Expressway are fighting a proposed Commonwealth Edison power line project and have agreed to individually approve a joint defense and confidentiality agreement.

Leaders in Schaumburg, Elk Grove Village, Hanover Park, Roselle and Itasca claim that the West Central Reliability Project, which calls for a transmission line stretching about 9 miles between substations in Bartlett and Itasca, would lower property values and create unpleasant views without serving their residents and businesses.

ComEd spokesman David O’Dowd said he wasn’t familiar with any precedent for similar agreements.

More: Daily Herald

ICC Report: Residents Overpaid $125M for Power

Residents overpaid more than $125 million for power for the 12 months ending in May 2016, according to an annual report issued by the Commerce Commission.

Residents of municipalities that contracted with alternative electrical suppliers other than Ameren and Commonwealth Edison rarely saved money.

Customers who used alternative carriers overpaid an average of $57 more per year, compared with rates offered by ComEd, the report found. Ameren customers using alternative providers largely broke even depending upon where they lived in the state.

More: Illinois News Network

MASSACHUSETTS

Convanta to Receive $562K to Upgrade Facility

Covanta will receive $562,000 in Pittsfield Economic Development funds to upgrade its solid waste-to-energy and recycling facility to meet state and federal environmental standards and remain profitable.

The Pittsfield City Council approved the funds to pay for a state-mandated recycling enclosure and upgrades to Covanta’s fossil fuel boiler.

Covanta, which had announced in July that it planned to close the facility, will sign a four-year contract extension with the city until June 2020.

More: The Berkshire Eagle

MINNESOTA

Regulators Approve Shutdown of Xcel’s Coal-Fired Generators

State regulators approved last week Xcel Energy’s plans to shut down its coal-fired Sherco plant by 2026 but rejected the company’s plan to build a large gas-powered generation plant on the site as a partial power replacement.

The Public Utilities Commission asked Xcel to explore renewable energy options in conjunction with its proposed gas plant. The commission also told Xcel to consider more demand-side management.

The Sherco plant generators are the state’s largest emitters of greenhouse gases.

More: Star Tribune

MISSOURI

PSC Approves Ameren’s Community Solar Proposal

solar Community solar took a step forward last week when the Public Service Commission approved Ameren’s proposal to build one, and possibly two, 500-kW solar arrays, which could provide residential and small business customers with up to half their energy.

Ameren has indicated that it will not begin construction on the first array until it is fully subscribed.

“I think it sends a very good signal to industry and consumers that utilities are starting to invest more in renewable energy, and are allowing customers to invest in it also,” said Caleb Arthur, chief executive officer of Missouri Sun Solar and president of the Missouri Solar Energy Industries Association.

More: Midwest Energy News

NEVADA

Switch Again Seeks To Bypass NV Energy

Data company Switch filed a September application with the Public Utilities Commission seeking to bypass middle-man NV Energy when it powers a new industrial center it is building in Storey County.

Switch wants to go competitive and have a choice in the energy market, according to Adam Kramer, executive vice president of strategies.

The company, which powers all its facilities with 100% renewable energy, is presently in litigation against the Public Utilities Commission and NV Energy over a ruling denying its application two years ago to leave the utility.

More: KRNV

Voters Seek to Invalidate Energy Choice Ballot Question

Two voters filed suit in Carson District Court to invalidate a ballot question intended to deregulate the state’s energy market regardless of whether voters approve retail choice on Nov. 8.

The question “directs the Legislature to enact legislation providing for the establishment of an open, competitive electricity market by not later than July 1, 2023.”

The lawsuit claims that the ballot question improperly binds the Legislature and governor by mandating they enact specific legislation.

More: Lahontan Valley News

NEW YORK

Protesters Spend 16 Hours in Pipeline

Four protesters carrying food, water and sleeping bags locked themselves inside the Algonquin Incremental Market Project pipeline for 16 hours last week at a worksite near the Indian Point nuclear power plant.

The protest, which coincided with Columbus Day (or Indigenous Peoples’ Day), showed solidarity with groups like the Standing Rock Tribe, which is protesting the Dakota Access oil pipeline.

More: The Journal News

Regulators Predict Decrease In Natural Gas, Energy Prices

| Source: Public Service Commission of Wisconsin — | *Source: Public Service Commission of Wisconsin*

State regulators predicted natural gas and electricity will be cheaper this winter compared with recent years.

The average residential electric customer will pay 14% less than the five-year winter average, while gas bills will be 10% less, according to an analysis by the Public Service Commission.

Notwithstanding, the commission predicts heating bills will be slightly higher this winter compared with last year because of last year’s unseasonably warm weather.

More: The Journal News

TEXAS

Solar Poised to Create Peak-Hour Price Drop

Steckler | Source: LinkedIn — Steckler | *Source: LinkedIn*

Developers are expected to build some 4 GW of commercial-scale solar panel capacity in the state by the end of the decade, up from 559 MW this year, according to a report issued last week by Bloomberg New Energy Finance.

The report predicts that by 2020, solar power will cause a $2.58/MWh price drop during peak hours in the state’s west hub.

“Just having this new influx of daytime energy production is going to bring down energy prices on average during the day,” said Nicholas Steckler, an analyst at BNEF.

More: Bloomberg

UTAH

Regulators Approve $15.6M Decrease for Electricity Customers

The Public Service Commission approved a $15.6 million rate decrease for Rocky Mountain Power’s electricity customers after the utility beat forecasted fuel and electricity costs. The overall rate decrease is 0.8%, which includes about $6.84 in annual savings for a typical residential customer.

More: Daily Herald

VERMONT

Iberdrola Offers to Pay for Favorable Wind Project Vote

Iberdrola Renewables has offered to pay 815 registered voters in two towns $14.1 million over 25 years if a wind project consisting of 24 turbines that would generate 82.8 MW of power wins voter approval on Nov. 8.

Iberdrola is seeking to build the state’s largest wind project on land spanning Windham and Grafton.

The offer does not violate state law, said Michael O. Duane, senior assistant attorney general. “The proposal doesn’t say that the funds go only to those people who signed a sworn statement that they had voted for it,” he said.

More: The New York Times

WASHINGTON

Voters Consider Carbon Tax on Polluters

For the first time in the U.S., state residents will vote in November on whether to levy a carbon tax on polluters for the greenhouse gases they produce.

The proposed tax would start at $15/ton beginning in July and jump to $25 in 2017. Incremental increases would follow.

More: The Christian Science Monitor

WISCONSIN

Judge Hears Challenge to New ATC Power Line

A La Crosse County judge heard arguments last week on whether to uphold state approval of a high-voltage power line with a $580 million cost that will be passed on to MISO ratepayers.

The 180-mile line is a joint venture of American Transmission Co. and several regional utility companies. It was not presented to the state as a project necessary to meet supply demand, but rather as one that would make the electric grid more resilient and ultimately save ratepayers millions of dollars.

The town of Holland argues the project violates state law because the need for it was not established, the environmental review was insufficient and existing poles should be used to route it through the town.

More: La Crosse Tribune

October 17, 2016

Federal Briefs

The U.S. Army Corps of Engineers is holding off on work for the $3.8 billion Dakota Access oil pipeline in southern North Dakota while it examines whether to reform how tribal views are considered for such projects.

Last week, the corps issued a joint statement with the Justice Department and Interior Department calling upon pipeline owner Energy Transfer Partners to voluntarily stop work on private land around Lake Oahe. The statement came in the wake of a ruling by the D.C. Circuit Court of Appeals that allowed construction after the Obama administration halted it.

Officials “look forward to a serious discussion … on whether there should be nationwide reform on the tribal consultation process for these types of infrastructure projects,” the statement said.

More: The Associated Press

Countries Close Deal Phasing out HFCs

At a summit in the Rwandan capital of Kigali on Saturday, more than 150 countries sealed an agreement to phase out the use of hydrofluorocarbons (HFCs), potent greenhouse gases used as refrigerants.

Under the agreement, most developing countries will be required to begin their plans by 2019 and freeze their HFC levels by 2024. Developed nations, including the U.S., will be required to begin by 2024. The European Union adopted a measure to reduce its HFC emissions in 2014.

HFCs were designed to replace chlorofluorocarbons, which were phased out under the 1987 Montreal Protocol because of the damage they caused to the ozone layer. Secretary of State John Kerry hailed the Kigali agreement as a “monumental step forward” and said it would avoid as much as a half degree Celsius of global warming.

More: Financial Times; The Guardian

US Gov’t Makes Largest Renewable Purchase Yet

The U.S. federal government made its largest ever purchase of renewable energy Friday when it signed a power purchase agreement for the 150-MW Mesquite 3 solar power station in Maricopa County, Ariz. The power from the desert solar array will supply one-third of the power demands of 14 naval installations in California, including San Diego’s naval base and the Marines’ Camp Pendleton.

The Navy will buy the power at a fixed price for 25 years from owner Sempra Energy. “To me, the essence of solar power is, you know what the price of the fuel is going to be for the next 25 years, or more,” said Dennis McGinn, the Navy’s assistant secretary for energy, installations and environment. “It’s going to be reliable, it’s going to be cheaper than what we’re paying for brown power and it just diversifies our energy sources for these bases.”

The Energy Department says the growth of large-scale solar plants in the Southwest is a result of $4.6 billion in investments it made as part of the stimulus legislation passed in the wake of the 2008 financial collapse.

More: The Washington Post

Bay Appoints Suzanne Krolikowski as FERC ALJ

FERC Chairman Norman Bay on Monday announced the appointment of Judge Suzanne Krolikowski as an administrative law judge.

Krolikowski has served as an ALJ for the Social Security Administration since June 2015. She received her bachelor’s in civil engineering from the Massachusetts Institute of Technology and her law degree and a master’s degree in ecology from the University of North Carolina at Chapel Hill.

“I am pleased to welcome Judge Krolikowski to FERC,” Bay said. “Her legal and technical background and experience is impressive and will [be] an asset to the FERC bench.”

More: FERC

October 17, 2016

SPP Markets and Operations Policy Committee Briefs

LITTLE ROCK, Ark. — The SPP Markets and Operations Policy Committee endorsed a 41% increase in a delayed 345-kV project along the Red River in southeastern Oklahoma as reasonable and reset the project’s baseline.

American Electric Power was supposed to have upgraded a pair of substations and built 76 miles of transmission line between Valliant, Okla., and a substation outside Texarkana, located on the Texas-Arkansas border, for $131.7 million. That total has grown to $185.8 million following a two-year delay attributed mostly to weather. The project was supposed to be energized in October 2014, but that date has now slipped to December 2016.

AEP’s Brian Johnson said the company was late to notify SPP of the delay because of internal communication problems between project management and those reporting costs. He said the company didn’t realize how far the project was outside its bandwidth until July, calling the situation “embarrassing.”

The company attributed 51% of the cost overruns to extensive flooding along the 76-mile route. The project was also hampered by siting problems and a landowner group’s opposition. “It was a combination of everything,” Johnson said.

The Project Cost Working Group, which reviews projects when updated cost estimates fall outside a 20% bandwidth, passed the recommendation on to the MOPC with a no vote from Kansas City Power & Light and two abstentions.

SPP Regional Entity: Wind Farms not Meeting New Standards

SPP Regional Entity General Manager Ron Ciesiel said wind farms unfamiliar with new NERC standards for reactive power, voltage controls and frequency caused a spike in reported reliability violations during the third quarter.

SPP Markets and Operations Policy Committee Briefs — | *SPP*

There were 71 violations of the MOD-025-2 (Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability), PRC-019-2 (Coordination of Generating Unit or Plant Capabilities, Voltage Regulating Controls, and Protection) and PRC-024-2 (Generator Frequency and Voltage Protective Relay Settings) standards, most of them by individually registered wind farms.

“The only good news is they aren’t operating problems,” Ciesiel said. He said the violations resulted from wind generators’ lack of awareness with the new standards’ implementation plan and a shortage of third parties to conduct testing. Only 40% of the generation units covered by the new standards had their capability tested or settings verified by July 1, when the standards took effect, Ciesiel said.

The RE expects to report more than 200 violations this year, a number it hasn’t topped since 2011.

Ciesiel said 33 new or revised standards will take effect over the next 12 months.

Members Vote to Cancel 69-kV line in West Texas

The MOPC approved staff’s recommendation to withdraw a notice-to-construct (NTC) for the Hobart City-Roosevelt Tap-Snyder 69-kV line in West Texas, based on the availability of an AEP operating guide that can mitigate the congestion through pre-emptive redispatch.

fas4qawysjmhwbnlo9qd_full_spp-mopc-committee-rto-insider-alt-fi — | © *RTO Insider*

The project was one of five withheld from the 2016 Integrated Transmission Plan (ITP) Near Term portfolio to determine whether they were needed to solve Scenario 5, which assumes renewable energy operating at 100% capacity.

Staff found while there have been 17 hours of congestion in the area since 2014, the 2017 ITP 10-year study indicated there were no congestion hours or future needs for the project, which had an estimated cost of $31 million.

Southwestern Public Service’s Bill Grant abstained from the vote, saying he did not want to live with operating guides forever.

The committee also endorsed staff’s recommendation to accelerate the NTC for an Oklahoma Gas & Electric 345-kV circuit upgrade project, but to leave a SPS 230-kV circuit upgrade in West Texas as is.

SPP staff said OG&E’s Amoco–Sundown project is necessary to meet additional congestion expected from more than 300 MW of wind energy added to the system this summer. With more wind energy on the way in Oklahoma, staff pushed the project’s in-service date to April 2018, a year earlier than originally planned.

SPP’s recent Wind Integration Study pegged both projects for further analysis. (See Study: 60% Wind Penetration Possible in SPP.)

MWG Clears 15 Change Requests

The Market Working Group brought five revision requests to the MOPC, which approved all over a small handful of no votes and abstentions. The committee unanimously approved 10 more changes as part of its consent agenda.

A revision request concerning the triggering of shortage pricing (MWG-MRR175) generated the most discussion among members — some concerned over sudden price spikes, others over a lack of scarcity events. The change incorporates language to comply with FERC Order 825 by using shortage pricing for any interval in which energy or operating reserves are short during the resources’ pricing. The change applies to any shortage, regardless of the duration or its cause. (See FERC Issues 1st RTO Price Formation Reforms.)

“Price spikes that occur over certain intervals can wipe out the entire day,” Nebraska Public Power District’s Paul Malone said. “There doesn’t seem to be any discussion about what can be done to mitigate this stuff. You can’t respond to a $500 price spike over five-minute intervals.”

The MWG recommendation was pushed for approval this month because it is a compliance matter. SPP staff and the group will both continue working to improve the process.

“We’re going to go back and see if we can make it better,” said Richard Dillon, SPP’s director of market design. “Scarcity pricing … is becoming more prevalent in the industry. We’d like to take a second look and see if we can do something better than the industry.”

“This will happen,” said AEP’s Richard Ross, chair of the MWG. “We are motivated to do something else, and staff is motivated to do something else.”

The motion passed with three no votes and two abstentions.

Golden Spread Electric Cooperative cited Order 825 in opposing a related change, (MWG-MRR173), which replaces the terms “head-room” and “floor-room” with “instantaneous load capacity.” Golden Spread said procuring rampable capacity for instantaneous load change, hourly load forecast or variable resource output through reliability unit commitment “masks shortage conditions in a manner inconsistent with the requirements of FERC’s shortage-pricing rule.”

Other rule changes approved by the committee were:

MWG-MRR183: Updates the violation relaxation limits (VRLs) operating constraint based on staff’s annual analysis, allowing additional redispatch to solve cases with fewer violations. Golden Spread abstained.
MWG-MRR188: Gives staff the option to include up to 100% of instantaneous load capacity (as opposed to the current 0% of capacity) in clearing the day-ahead market, an effort to minimize the gap between day-ahead and real-time energy prices. The motion received nine abstentions.
MWG-MRR193: Adds rules for solar resources to the market protocols and Tariff, including incorporating a solar forecast in SPP studies, increasing the solar forecast’s accuracy and including solar resources in dispatchable variable energy resource registration. Nebraska Public Power District cast an opposing vote, contending behind-the-meter generation would be required to register in the market should their loads change and they end up injecting power onto the system.
BPWG-RR123: Removes obsolete language and clarifies SPP’s current practices for short-term service requests and the system impact study process.
MWG-MRR178: Specifies that SPP’s Market Monitoring Unit will review the costs included in each mitigated resource offer, on an ex-post basis.
MWG-MRR179: Aligns the protocols with FERC-approved language (ER15-2265) ensuring long-term congestion rights are not affected by potential resource hub terminations, and that resource hubs used in bilateral contracts can’t be unilaterally terminated by the hub’s owner.
MWG-MRR181: Corrects outdated references in the Tariff and protocols related to the allocation of annual auction revenue rights, an oversight noted by FERC (ER16-13).
MWG-MRR182: Removes the term “control area,” which is no longer used by SPP, from the market protocols.
MWG-MRR184: Exempts resources from charges when they clear the day-ahead market with real-time meter readings of zero following either decommitment by SPP or dispatch to zero.
MWG-MRR185: Clarifies which document — SPP Planning Criteria or SPP Operating Criteria — is referenced when used in the market protocols and Tariff.
ORWG-RR168: Requires transmission owners to provide the highest available emergency ratings and specifies SPP’s interpretation of those ratings.
RTWG-RR176: Corrects and clarifies the responsibilities and requirements under the process that allows generation resources to be compensated for reactive support.
TWG-RR174: Revises Attachment AQ of the Tariff to no longer require transmission customers to submit a request for changes in delivery point facilities without a corresponding change in load.

– Tom Kleckner