Page 1280 – RTO Insider

September 1, 2017

UPDATED: Texas PUC Praises Harvey Restoration Efforts

By Tom Kleckner

Texas regulators last week praised the response of the state’s utilities, ERCOT and first responders during discussion of a preliminary report on restoration efforts in the wake of Hurricane Harvey.

Speaking during an Aug. 31 open meeting of the Public Utility Commission of Texas, Commissioner Ken Anderson noted the “remarkable” restoration effort in flood-stricken Houston, especially when compared to Hurricane Ike’s aftermath in 2008.

Brandy Marty Marquez, the PUC’s other commissioner, described a road trip she took a day earlier to the deep-sea fishing community of Port Aransas. Port A, as South Texans refer to the beach town, was devastated by Harvey’s 130-mph winds.

“I saw linemen with all different uniforms [on the way]. It was very inspiring,” Marquez said. “We have a long way to go, but you can’t mess with Texas. We’ll be fine. This is a big test for us, but everyone’s risen to the occasion.”

ERCOT PUCT Hurricane Harvey — ERCOT’s Brian Lloyd

PUC Executive Director Brian Lloyd became visibly emotional as he talked about the 10,000 utility workers from around the country who have descended to help Texas with the restoration.

Taking a few seconds to regain his composure, Lloyd told the commissioners, “It’s great to see that work.”

“As an industry, we should be very proud of what has happened in the response,” said NRG Energy Director of Regulatory Affairs Bill Barnes. “We have a lot of friends to thank across this industry.”

American Electric Power, CenterPoint Energy, Entergy Texas and Texas-New Mexico Power reported just more than 200,000 combined customer outages Aug. 31, down from about 278,000 the day before. That number had dropped to almost 78,000 by Sunday afternoon.

“Other than the areas with extensive damage and flooding, a good chunk of this will be back online this weekend,” Lloyd said.

‘This is Personal’

ERCOT filed a status report with the commission Aug. 30 indicating that two of the six 345-kV lines that Harvey knocked out of service have yet to be restored. Another 55 high-voltage transmission lines in the storm-affected areas were still out of service as of Friday morning, the ISO said.

Most of those outages are in the Coastal Bend area between Corpus Christi and Houston, which took the full brunt of high winds when Harvey made landfall as a Category 4 storm. AEP Texas said Thursday that more than 4,600 workers have spent 14- to 16-hour days restoring power.

The bulk of those without power — about 40,000 — are in the Rockport-Victoria-Aransas Pass area. AEP Texas estimates it will take until Sept. 8 to complete its restoration work in the region.

Barnes offered a note of caution to the PUC: Just because it’s stopped raining doesn’t mean Harvey’s damage is over.

“What we’re dealing with is something that is very devastating and will have a lasting impact,” he said. “This is going to take a significant amount of time to recover from. A lot of people have had their lives changed forever as a result of this. That includes our employees, our families, our friends.

“The Corpus Christi-Victoria area is our backyard; Houston is our home. So this is personal.”

Barnes told the commissioners that NRG and its retail electric providers would halt disconnect notices through Sept. 30 for its customers in affected areas, and provide “direct financial relief” in the form of payment extensions, late fee and deposit alternatives or waivers, and increased funding of bill payment assistance programs.

The companies will also provide more than $2 million in disaster relief resources, including donating money to relief agencies and deploying a mobile generation station and disaster relief command center for affected communities, according to a filing with the PUC.

TXU Energy said it would also be waiving late fees through Sept. 30, along with extending payment due dates with no down payment required, and reducing down payments and deferring balances over five equal installments.

Anderson commended the retailers for their actions, saying, “It’s a good example for the rest of the retail industry.”

Generation, Demand Down

ERCOT also reported Friday that 7,500 MW of generation remains unavailable or operating at reduced capacity. The loss does not represent a reliability concern, and the ISO expects to have sufficient generation for the “foreseeable future.”

System demand has been down significantly since shortly before the storm made landfall Aug. 25, ranging between 41 and 48 GW, approximately 15 to 20 GW lower than normal. Demand has started to increase as service is restored and temperatures begin to rise, with projected peaks over the weekend of 56 GW. (ERCOT had predicted a peak of 73 GW this summer.)

The South Texas Project nuclear plant in Bay City, 90 miles southwest of Houston, remained online during the storm. Like other plants in the area, operators at the 2,760-MW double-unit facility were “literally locked in [the] plant for days,” Marquez said.

Barnes agreed. “Road access was flooded,” he said, referring to the situation at other NRG plants. The company is one of STP’s co-owners.

September 1, 2017

CAISO Considering Transmission Charge Changes

By Jason Fordney

CAISO is moving forward with a proceeding that could result in changes to how it allocates transmission costs to participants in its wholesale markets, meant to better reflect increased adoption of distributed generation and other factors.

The grid operator is considering a proposal to replace its current method, which utilizes end-use metered load to bill a volumetric transmission access charge (TAC). That method does not reflect the role of DG in reducing transmission costs.

CAISO is analyzing whether to reduce TAC charges in transmission owner service areas for load that is offset by DG output, and how best to do so. It also is considering a demand-based charge instead of — or in addition to — its volumetric charge, or one based on time-of-use pricing.

The ISO on Tuesday held a stakeholder working group on the proposed TAC changes outlined in a June 30 issue paper. Neil Millar, CAISO executive director of infrastructure development, said during the meeting that because transmission charges are applied both to energy provided from central stations and DG, the cost of delivering energy is ignored, creating an inefficient market.

“It distorts cost allocation, distorts energy markets [and] costs money,” Millar said. Transmission costs are also rising, making dealing with the issue a “political necessity.”

CAISO wholesale market transmission costs — Graph of Declining Load Factor of California Investor-Owned Utilities | *Energy Policy Initiatives Center; California Energy Commission*

CAISO also considered changing another settlement process that uses a volumetric rate for wheeling power to loads off the ISO-controlled grid, but it put it on hold after talking with stakeholders and deciding the initiative had “a number of complex and controversial issues.”

Moving the point where transmission usage is measured would solve a lot of the issues, according to Millar. To address the issue, the ISO is considering a Clean Coalition proposal that would rely on gauging hourly net load at each transmission-distribution interface substation, referred to as “transmission energy downflow.”

In an effort to place some boundaries on the proposal, CAISO plans to remove some other topics that are broad in scope regarding the TAC. Among those initiatives were an assessment of current regional and local transmission charges that are recovered through a postage-stamp rate and an analysis of the ISO’s role in collecting the TAC. Other topics to be postponed are alternative types of transmission service. CAISO said it would study other regions and some other proposals put forth by stakeholders.

CAISO plans to issue a straw proposal on the TAC changes by Oct. 31, followed by a Nov. 15 stakeholder call. A final proposal will be submitted to the ISO Board of Governors sometime in 2018.

The grid operator earlier developed a proposal to allocate transmission costs over an expanded balancing area if the ISO integrates new members such as PacifiCorp. (See CAISO Floats Latest Cost Allocation Plan for Expanded Balancing Area.) That proposal has been shelved until CAISO expands into other regions of the West.

September 1, 2017

State Could Reject Ameren Illinois Efficiency Target Reset

By Amanda Durish Cook

Ameren Illinois may have hit a roadblock in its efforts to lower its energy efficiency targets prescribed under a new law.

Illinois Commerce Commission Administrative Law Judge Jan Von Qualen on Tuesday issued a preliminary order (17-0311) denying the utility’s request to lower its energy efficiency goals established under the state’s recently enacted Future Energy Jobs Act (FEJA). The ICC is expected to render a final decision on the request by mid-September.

Under the law, Ameren is required to meet 9.8% in cumulative annual energy savings by 2021, but the utility is planning for 8.24% in savings. The utility has allocated $114 million per year for the program, the maximum budget under the law, but claimed it still could not meet the savings goal. A maximum budget triggers the ICC’s authority to reduce annual incremental savings goals.

“Based on the record, the commission finds that [Ameren] should modify its plan in a manner that ensures cost efficiencies and serves the customers, including low-income customers, to the maximum extent practicable throughout its service territory,” Von Qualen said. “The commission will not modify the [annual savings] goal absent a showing that every attempt has been made to meet the goal and it cannot be met.”

The Illinois Clean Jobs Coalition, along with other environmental and consumer activists, last month held a press conference to criticize Ameren for setting low energy efficiency goals and to urge state regulators to reject the utility’s four-year efficiency and demand response plan. (See Ameren Illinois Criticized for Lowered Energy Efficiency Goals.)

Von Qualen said the state attorney general’s office — as well as the Citizens Utility Board, Environmental Defense Fund and the Natural Resources Defense Council — provided multiple suggestions in testimony regarding how Ameren could meet its annual savings goal “while staying within the budget cap.”

The judge suggested that Ameren reallocate its optional $6 million per year efficiency research and development spending to programs that actually lower costs per kilowatt-hour. She also said the utility could use a portion of the $4.7 million budgeted for air conditioners on more cost-effective programs. The judge directed Ameren to work with the Illinois Energy Efficiency Stakeholder Advisory Group, the Economically Disadvantaged Advisory Committee and the Illinois Home Weatherization Assistance Program to make better use of its required $8 million in spending on third-party energy efficiency implementation programs, instead of using national retailers and online stores.

She did approve other aspects of Ameren’s plan, including savings goals for its gas program and riders for the recovery of electric energy efficiency costs.

Ameren: No Change

Ameren defended its plan and said it has no plans to change its filing in light of the proposed order.

“We have put forth the right plan to help working families in our territory save energy and we look forward to making our case with the Illinois Commerce Commission,” Ameren Illinois spokesperson Marcelyn Love told RTO Insider.

Ameren illinois energy efficiency — Ameren Illinois linemen at work in 2017 | *Ameren Illinois*

Ivan Moreno, communications manager of the Natural Resources Defense Council, said Ameren has been heavily lobbying state legislators to lean on the ICC to approve the plan.

“This is unusual given that legislators have already debated and voted on this issue through the Future Energy Jobs Act,” Moreno said, adding that he expects Ameren to escalate efforts to get the ICC to approve the plan “despite the proposed order.”

The Illinois Clean Jobs Coalition welcomed the preliminary ruling: “As the Illinois Clean Jobs Coalition has said from the start, Ameren should be able to deliver energy efficiency programs that serve low-income communities and — at the same time — achieve the energy efficiency targets that the company agreed to under FEJA. We are hopeful that members of the Illinois Commerce Commission will agree with the judge in this case.”

The group said it looked forward to working with Ameren on a new plan “that meets the goals set forth in FEJA which can create jobs, savings and better health across Illinois and, in particular, deliver benefits to economically disadvantaged communities throughout the state.”

August 31, 2017

Aliso Canyon Measure Clears Calif. Assembly Committee

By Jason Fordney

SACRAMENTO, Calif. — A key California State Assembly committee on Wednesday advanced a Senate bill requiring publicly owned utilities in the Los Angeles Basin to support deployment of distributed energy resources and energy storage.

Aliso canyon Energy Storage DER — Appropriations Committee Chair Lorena Gonzales-Fletcher | © *RTO Insider*

The Committee on Appropriations approved SB 801, which now goes to the full Assembly for a vote.

The legislation was drawn up by State Sen. Henry Stern (D) in response to the 2015 leak that resulted in the closure of the Aliso Canyon natural gas storage facility. Many area residents are trying to get the facility closed permanently, but owner Southern California Gas recently resumed gas withdrawals after a court battle. (See Aliso Canyon Resumes Injections.)

Stern noted that investor-owned utilities Southern California Edison and San Diego Gas & Electric deployed energy storage quickly after the blowout, which threatened to compromise fuel deliveries to the region’s gas-fired generators.

“However, publicly owned utilities in the area have not yet adopted the same aggressive approach to clean energy storage and other safe reliability solutions in response to Aliso Canyon,” Stern said.

If passed, the measure would require the Los Angeles Department of Water and Power (LADWP), which serves 250,000 customers, to make data available that would help DER providers identify solutions to increase reliability in the region. It also requires LADWP to maximize use of demand response, renewables and energy efficiency in the area where reliability has been impacted by the Aliso Canyon outage.

The bill would allow LADWP to offset any ratepayer expenses with fines or fees levied over the leak against SoCalGas and its parent company Sempra Energy.

It would also require LADWP to study deployment of 100 MW of energy storage and oblige SCE to deploy 20MW of storage by June 1, 2018.

Stern has called the reopening of Aliso Canyon “premature and unnecessary.” California Energy Commission Chairman Robert Weisenmiller has said the facility should be closed permanently.

The committee also suspended until Friday a vote on SB 100, which mandates that the state’s utilities procure 100% of their electricity from zero-carbon resources by 2045. The Senate in May approved the legislation introduced by Senate President pro Tempore Kevin de León, a Los Angeles Democrat. (See California Senate Passes Bill Mandating 100% RPS.)

August 31, 2017

FERC Approves MISO Plan to Share Generator Gas Data

By Amanda Durish Cook

FERC on Tuesday approved a MISO pilot program allowing the RTO to share information on power plants’ gas use with pipeline operators (ER17-1556-001).

Starting in December, MISO will share day-ahead hourly burn estimates from gas-fired generators with a trio of gas operators: Northern Natural Gas, ANR Pipeline and DTE Energy. The RTO says the program will help ensure adequate fuel supplies for gas plants.

MISO FERC Natural Gas — DTE’s Washington 10 Complex near Detroit | *DTE Energy*

FERC agreed that the program complies with the communications permitted in Order 787.

“We find that MISO’s proposal to extend the information sharing provisions to LDCs [local distribution companies] and intrastate natural gas pipeline operators will help ensure and optimize the reliable operation of the grid, particularly during the winter months where demand for natural gas is strongest,” the commission said.

The commission noted that Order 787 encouraged grid operators to make Tariff filings “to facilitate greater sharing of nonpublic, operational information with entities such as local distributions companies.”

“We note that the proposed revision will improve communication and coordination among MISO and operating personnel of the interstate natural gas pipeline companies in the MISO region to ensure that MISO and interstate natural gas pipeline control room operators have better information on which to base operating decisions,” FERC said.

The acceptance comes after FERC in June issued MISO a deficiency letter in response to an earlier version of the proposal. The letter noted that the pilot lacked a no-harm clause and that the RTO failed to justify its reason for sharing confidential information with LDCs, which FERC must approve on case-by-case basis. (See FERC: MISO Gas Data Sharing Plan Falls Short.)

In response, MISO amended its filing with language borrowed from PJM that expressly states that any shared information will not be used “to the detriment of any natural gas and/or electric market.” MISO also contended communication with LDCs is crucial because about 25% — or 12,511 MW — of the RTO’s gas-fired capacity is served by the companies.

FERC accepted both responses, saying that MISO’s use of nondisclosure agreements and restrictions placed on shared data “minimizes the opportunity that the information can be used in an unduly discriminatory or preferential manner by the recipient or to the detriment of the market.”

The commission rebuffed Indianapolis Power and Light’s protest against the pilot. The utility asked that MISO not be allowed to “grant itself the ability to provide proprietary data to anyone without the expressed consent of the generation owner.” FERC, however, noted that Order 787 did not require “three-way communications” for such programs.

Some MISO stakeholders earlier this year voiced opposition to the pilot, saying it could affect reliability if participating gas operators make burn rate decisions relying solely on partial day-ahead data. (See MISO Stakeholders Question Electric-Gas Info Sharing.)

August 31, 2017

Echoing DOE Report, Industry Study Touts Coal ‘Resiliency’

By Amanda Durish Cook

A new study prepared for the American Coalition for Clean Coal Electricity (ACCCE) spotlighting the “resiliency” of coal-fired generators echoes the findings of a U.S. Department of Energy report released earlier this month.

Although the study by PA Consulting Group concludes that “no single electricity resource has all of the attributes necessary for a reliable and resilient grid” and that “a mix of resources is the best strategy,” it lauds coal generation for its “many critical attributes,” including stable fuel prices and an on-site fuel supply that can act as a hedge against potentially volatile natural gas prices, interruptible fuel deliveries and intermittent renewable and demand response resources.

ACCCE DOE coal — Coal stockpile | *Worldcoal.org*

The study’s release may prove to be an early salvo in the possible “fuel wars” predicted by one former senior FERC official who said that new FERC commissioners could break with agency tradition by each acting as advocates for favored types of resources. (See Coal Seeks ‘Resiliency’ Premium; FERC ‘Fuel Wars’ Coming?)

The study ranked generation resources on 11 attributes, giving coal high marks in all but black start capability.

The report is effectively a response to a study done by The Brattle Group for the American Petroleum Institute (API), which concluded that gas-fired generation is “relatively advantaged” in all but one of the 12 attributes identified in that study. (See NG Lobby Goes on Offensive vs Coal, Nukes.)

The API/Brattle report ranked coal as only “neutral” on two categories for which ACCCE claimed a full score — frequency response and ramp rates (referred to as “ramp capability” by ACCCE).

API did not score three categories in which ACCCE said coal had an advantage over gas: on-site fuel supply, reduced exposure to a single point of disruption and price stability.

“This new report shows the coal fleet is essential to help maintain the reliability and resilience of the electricity grid,” said ACCCE CEO Paul Bailey. “For that reason, we are especially supportive of DOE’s recent recommendation that policymakers need to establish criteria to value attributes, such as on-site fuel, that help protect the grid against low probability events that have extreme consequences.”

Bailey said he looked forward to “working with policymakers to implement DOE’s recommendation as quickly as possible” that RTOs begin valuing on-site fuel storage as a measure of “resiliency.” (See Perry Grid Study Seeks to Aid Coal, Nuclear Generation.)

Natural Gas Criticisms

The report took particular aim at natural gas-fired generation, coal’s biggest competitor. According to the report, coal generators on average stockpiled 82 days of bituminous coal and 73 days of subbituminous coal on site over the last five years. It compared that to the position of “vulnerable” gas-fired plants, which last year on average had about 60 days of fuel in storage reserves and rely on interruptible deliveries via pipeline.

It also pointed out that low-probability, high-impact events like earthquakes can cause supply shocks in the gas distribution network. More than 50% of gas storage capacity is located in five states — Michigan, Texas, Louisiana, Pennsylvania and California — PA Consulting warned, and 18 states in the continental U.S. have “no material storage capability,” including New England and North Carolina, South Carolina, Georgia and Florida.

The study also said that because most U.S. coal is used for electricity, coal-fired generation “does not compete with higher-priority uses” and will not have to be forcibly curtailed. It also pointed out that “all but two lignite coal-fueled plants [in the U.S.] source their coal from mines within 30 miles of the plant.”

The popularity of gas-fired generators relies on the continuation of low-cost shale natural gas, the study contends.

“The current investment boom in natural gas-fired plants is driven in part by an expectation of continued low natural gas prices of approximately $3-4/MMBtu,” the study said. The 77 GW of gas-fired capacity built since 2009 might be a result of an “over-focus on short-term price signals,” the authors contend.

Over the last decade, monthly average natural gas prices have “repeatedly seesawed” from $3/MMBtu to more than $12/MMBtu, reaching $100/MMBtu in some markets during the so-called “polar vortex” of 2014, the study noted. It also pointed to dramatically fluctuating gas prices during 2015’s Aliso Canyon leak and an extreme cold front in Texas in 2011 that caused 193 generating plants to either fail outright or experience weak output.

“Retaining existing coal-fueled power plants can help insulate ratepayers against rising and possibly volatile natural gas prices,” the report said.

August 31, 2017

NYISO Management Committee Briefs – August 30, 2017

NYISO locational-based marginal prices (LBMPs) have averaged $36.35/MWh for the year through July, a 12% increase from a year earlier, COO Rick Gonzales told the Management Committee during its Aug. 30 meeting. Natural gas prices were up 13.1% over the same period.

LBMPs averaged $35.84/MWh during July, up 13% from June and down 10% from July 2016. Last month’s daily sendout averaged 498 GWh/day, compared with 532 GWh/day a year earlier.

July natural gas prices and distillate price averages gained from the previous month, with Transco Z6 NY gas up 4% to $2.44/MMBtu, jet kerosene Gulf Coast up 9% to $10.49/MMBtu and NY Harbor ultra-low sulfur No.2 diesel up 7% to $10.85/MMBtu. Distillate prices increased 11.1% from the same period a year ago.

NYISO locational-based marginal prices LBMPs — | *NYISO*

Average uplift costs — not including NYISO cost of operations — were down to -43 cents/MWh for the month, compared with -37 cents/MWh in June. The local reliability share fell 4 cents to 11 cents/MWh. The statewide share of -54 cents/MWh came in 2 cents below June. July’s total uplift costs were also lower than in June.

The monthly peak load of 29,699 MW occurred July 19, far short of the all-time summer peak of 33,956 MW recorded on July 19, 2013.

NYISO Evaluates Energy Market Offer Cap

The ISO is continuing to evaluate its energy market offer cap to prevent differences in regional offer caps from interfering with economic and reliability-driven interchange scheduling, according to a report presented by NYISO Senior Vice President for Market Structures Rana Mukerji.

Under FERC Order 831 issued last November, NYISO is required to cap each resource’s incremental energy offer at the higher of $1,000/MWh or that resource’s verified cost-based incremental energy offer, and cap verified cost-based incremental energy offers at $2,000/MWh when calculating LBMPs. The grid operator last December filed a request for clarification/rehearing on the issue with FERC and submitted a compliance filing in May.

Mukerji also noted that the ISO is working to improve forward horizon coordination of real-time constraints (RTC) and real-time dispatch (RTD). NYISO aims to improve modeling consistency between RTC and RTD and evaluate improvements in look-ahead evaluations to facilitate more efficient scheduling and price convergence.

Pending issues include possible proposals to allow market participants to buy and sell reserves and regulation service between NYISO and adjacent control areas and to develop a market mechanism to assign external parties with the costs associated with congestion rent shortfalls resulting from external transmission outages.

The ISO is also examining the reciprocal elimination of fees on export transactions in order to increase interregional transmission scheduling efficiency. Rate pancaking between NYISO and ISO-NE has already been eliminated.

Interconnection Queue Improvements Approved

The committee approved steps intended to improve the efficiency of the interconnection queue process while maintaining needed reliability evaluations.

The proposed changes clarify and update existing practices and procedures, except for the transmission interconnection procedures, which are still pending FERC acceptance. Transitional rules would allow projects currently in the interconnection process to benefit from the proposed changes. (See “Committee Advances Interconnection Queue Improvements,” NYISO Business Issues Committee Briefs: Aug. 9, 2017.)

NYISO expects to file associated Tariff changes with FERC in late September following board approval.

New York Easily Handles Solar Eclipse

NYISO easily met operational reliability criteria throughout the solar eclipse Aug. 21, despite a 1,010-MW reduction of net load that exceeded predictions by nearly 300 MW, according to a report from NYISO Vice President of Operations Wes Yeomans.

The ISO did not experience the slight projected load increase early in the eclipse, possibly because of lower loss of behind-the-meter solar than originally anticipated, as well as public reaction to the event. He attributed the higher-than-expected net load increase later in the eclipse to high humidity.

New York experienced a partial solar eclipse from 2:30 to 2:45 p.m., with peak obscuration ranging from 80% in Chautauqua County, to 75% in New York City and Long Island and 67% in Clinton County.

— Michael Kuser

August 30, 2017

California Agencies, Utilities Prep for Climate Change

By Jason Fordney

California utilities and state agencies are cooperating on developing plans to manage the effects of global climate change on the electricity grid, an issue that looms especially large for the state.

Rising sea levels, reduced snowpack, more wildfires and extreme weather events such as drought and severe rain are predicted for California, which experts say will be more affected by global warming than other states because of its warm climate and extensive coastline.

California utilities climate change — California Energy Commission Chairman Robert Weisenmiller | © *RTO Insider*

Partnership between state officials, local government and utilities was the theme at a Tuesday workshop hosted by the California Energy Commission. Participants discussed the physical impacts of climate change on the grid, geophysical changes, temperature trends and the challenges facing vulnerable populations.

State law requires the CEC to assess and forecast the state’s energy production, supply and demand, and develop policies that conserve resources. The agency is studying climate change impacts on the energy grid as part of its 2017 Integrated Energy Policy Report process, which is updated every year and adopted every two years.

Pacific Gas and Electric is a critical infrastructure company with 16 million customers and a “critical responsibility,” said Melissa Lavinson, vice president of federal affairs and policy. The company is getting more requests from local governments for information on its efforts to prepare for climate change, she said.

PG&E favors a regional approach to the issue that would help with coordination, rather than going community by community. The utility has proposed a “climate resilience clearing house” to aggregate information and a regional governing body to coordinate local governments.

“We are far from the end of this process. We are at the beginning of this journey,” she said.

San Diego Gas & Electric is in the midst of a “Climate Vulnerability and Adaptation Options” study consisting of both electric grid and natural gas tracks, Sempra Energy Meteorologist Brian D’Agostino said. The electric analysis looks only at the effect of the rising water level and flooding on the coast where many of the company’s power plants are located, while the natural gas program also looks at climate hazards inland. The report also highlights downstream impacts on customers, electricity demand and the economy.

Historic and Project State-Wide Temperature | *California Energy Commission*

PG&E is working with the University of California, Berkeley and the California Department of Water Resources on a program to deploy wireless remote sensors to study moisture, temperatures and snowpack and more effectively manage hydro assets, said Gary Freeman, the company’s principal hydrologist. The company closely studies weather and increasing “atmospheric rivers,” which are columns of moisture that occur in the atmosphere and can dump large amounts of rain.

Atmospheric rivers hundreds of miles wide occur in California because of the Pacific Ocean and mountains that cool the air as it travels inland. The formations provide up to 50% of the annual precipitation on the West Coast, and their increasing activity is another example of how climate change affects grid planning and reliability in a region with extensive hydroelectric capacity.

Gov. Jerry Brown in April 2015 signed an executive order that set 2030 greenhouse gas reduction targets that were recently codified into law. (See California Lawmakers Extend Cap-and-Trade.) The state has also developed online tools providing climate change data, including climateconsole.org and cal-adapt.org.

August 30, 2017

ATC Fined over Improper FERC Reporting

By Amanda Durish Cook

American Transmission Co. has agreed to pay a federal fine and undergo a year of monitoring after failing to properly report more than 60 agreements and transactions to FERC over the past 16 years.

Under an agreement reached with FERC’s Office of Enforcement, Milwaukee-based ATC will pay a civil penalty of $205,000 to the U.S. Treasury and submit semi-annual compliance monitoring reports for one year detailing any further violations (IN17-5).

FERC ATC American Transmission Co — ATC headquarters in Milwaukee | *Mortenson Construction*

The office found that ATC repeatedly failed to seek approval to merge or acquire FERC-jurisdictional facilities and to file “timely” contracts and agreements relating to rates and charges for jurisdictional service.

“Enforcement determined that, although ATC’s violations did not result in quantifiable market harm, they created a lack of transparency in the market by failing to have all of ATC’s jurisdictional agreements on file with the commission, and by consummating purchases of commission-jurisdictional assets without commission authorization,” the commission said.

In an internal review of its filing processes during 2014 and 2015, ATC discovered 63 instances in which it failed to either properly report or file information starting in 2001.

Those include several agreements that it failed to file pursuant to Federal Power Act obligations, relating to operations, transmission design on shared 345-kV projects, pole replacements, repairs on jointly owned substations, transmission line relocation and ownership, and cost-sharing for jurisdictional facilities. ATC in some cases also neglected to file notices to terminate existing agreements. The company has already paid $1.4 million to several affected parties in time-value refunds.

The company also identified 21 jurisdictional facilities it acquired without gaining FERC approval. The facilities range in value from $1,513 to $1.2 million. FERC retroactively approved each transaction after ATC sought permission between 2014 and 2015.

Section 203 of the FPA requires public utilities to file for FERC authorization to merge or acquire jurisdictional facilities, and Section 205 requires public utilities to file “all contracts which in any manner affect or relate to such [jurisdictional] rates, charges, classifications and services.”

FERC said that, since discovering the violations, ATC has taken steps to “strengthen its compliance policies and procedures and to prevent noncompliance in the future regarding jurisdictional agreements,” holding employee training seminars, updating training documents and developing an internal review process to make sure the company has proper authorization.

August 29, 2017

MISO Sets Target for Market Platform Upgrade Decision

By Amanda Durish Cook

CARMEL, Ind. — Now that it has completed a seven-month evaluation of its existing system, MISO says it will provide a detailed decision on how it would rebuild its computer-based market platform in 2019.

MISO market platform — Porter | © *RTO Insider*

The RTO’s near-term focus: to protect and extend the life of the existing market system while exploring and discussing upgrade options with vendors, according to MISO General Counsel Andre Porter.

MISO will present a business case for the making the upgrade at a Sept. 6 workshop on the status of the market platform. MISO’s Board of Directors in June urged RTO officials to provide stakeholders with upgrade details — and a plan — in order to solicit comments. (See MISO: $130M Needed for New Market Platform.)

“Stakeholder participation is critical for the market system enhancement program,” Porter said, urging stakeholders to bring questions to the workshop.

At an Aug. 24 meeting of the board’s Technology Committee, Director Baljit Dail praised the RTO’s stakeholder outreach, but stressed that it should make the upgrade information easier to understand.

MISO expects to select an upgrade option and confirm a vendor in 2019, with roll-out of the new platform targeted for no later than 2024. Officials plan to finalize a budget in October for the estimated $65 million needed to preserve the existing system for another five to seven years, while another $65 million would be allocated to build a new modular platform. The budget will also include a total contingency amount equating to up to 25% of the project cost.

Director Thomas Rainwater commended MISO for being able to finish the evaluation stage of the project on time. “We think that’s a bellwether of what’s to come,” he said.

“The progress you all have made is phenomenal, and you guys should be very proud of this. As a committee, we want this project to be successful. It has the potential for a huge payout,” Dail said, urging officials to provide frequent updates on the project.

As MISO completes the platform rebuild, officials will also explore the intellectual property rights of the software. A deeper discussion on possible copyrights was saved for a closed session of the Technology Committee.

The existing market system, designed by General Electric, was built from scratch in 2005 for $245 million. To incorporate the ancillary services market in 2009, MISO spent $75 million. It spent an additional $30 million to expand the platform upon integration of MISO South in 2013. In any given year, MISO invests about $6 million to $9 million in maintenance and improvement costs, Vice President of System Operations Todd Ramey said.

“The system we use today, and have used since the start of our markets in 2005, is really based on infrastructure used in the late 1990s. This system has started to show signs of its age,” Ramey said.

Several Market Roadmap design changes have been put on hold because of the aging infrastructure, Ramey said. MISO has growing concerns about security and, in some cases, market participants must use older versions of web browsers to view web pages.

ISO-NE and PJM also use GE-designed platforms. Both RTOs will undergo “common” upgrades using a staged approach in the next few years, said Jeff Bladen, MISO executive director of market design.

“In some respects, we’re catching up [with other RTOs], but we have a plan to go beyond what’s done today,” Bladen said during an Aug. 23 Advisory Committee meeting.

Ramey noted that MISO would eventually be forced to change to its platform because GE plans to phase out IT support for the aging software.

The computer overhaul will mostly affect MISO’s day-ahead market and Energy Management System programs. The RTO’s settlement software system is being rebuilt in a different project launched in 2014. The RTO is currently completing system testing and expects to launch the new settlements platform sometime in the fourth quarter, in time for the early spring 2018 roll-out of five-minute settlements.