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November 2, 2024

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SPP Board of Directors and Members Committee Briefs

RAPID CITY, S.D. — Less than a year after enjoying a 2-cent reduction in SPP’s administrative fee, the RTO’s members are now facing the prospect of a 4-cent hike for 2017.

SPP’s Finance Committee announced the increase during last week’s Board of Directors and Members Committee meeting to minimal pushback. Members — with only three opposing votes — and the board approved the committee’s recommendation to hike the fee’s cap to 43 cents/MWh, which would allow room to raise it from its current 37 cents/MWh to a projected 41.1 cents/MWh.

The board’s approval means staff can file the necessary Tariff changes with FERC.

Staff said the move was necessary because the RTO expects 2016 expenses to exceed revenues by $6.7 million as a result of a 3.7% drop in peak loads since 2015.

SPP is forecasting revenue from the fee will be $5.4 million below budget for the year. Staff said raising the fee’s cap above 2017’s projected level would “accommodate any further reduction in peak load similar to what SPP utilities experienced in 2015.”

The committee said it will review the fee’s billing determinants to see “if a more predictable and equitable basis exists to allocate SPP’s costs of operations to its customers.”

“The admin fee is one of the places where the rubber hits the road,” said Oklahoma Gas & Electric’s Greg McAuley. “We just got done with a rate case, and I can tell you it is very, very difficult to raise rates.”

SPP’s addition of the Integrated System last October was expected to help keep the fee stable. However, the system’s reported loads have been 10% below expectations; SPP projected a 12% increase in transmission load last year with the system’s membership. (See SPP Board Approves Budget, SPC Expansion.)

“We thought we would bring the number down 5 cents with IS, but it actually brought them down by 3,” Board Chairman Jim Eckelberger said.

“The costs in all of this equation didn’t change very much,” SPP CEO Nick Brown said. “The load in the footprint changed a lot, so what we’re collecting from each market participant will be roughly the same, regardless of what that rate is. It’s just the denominator” that changed.

This year’s budget assumed transmission volume of 407.2 million MWh. SPP’s draft 2017 budget projects 395 million MWh.

The Finance Committee said the 2017 budget still includes “several unknowns,” primarily because SPP has just started its 2017 planning process. A final budget will be presented to the board during its December meeting, when members will also vote on next year’s administrative fee.

Committee Chairman Harry Skilton noted that one favorable variable is the scorching summer heat that’s settled over the Great Plains. Skilton said SPP’s manpower costs have resulted in a $1.2 million hit above costs, “but we will carry on.”

Cybersecurity Insurance

Skilton also said cybersecurity insurance is becoming an available product, remarking, “Anything can be insured.” He said his committee will meet with Little Rock-based Stephens Insurance “once that market is a little solidified” as part of SPP’s overall insurance package.

Following the committee’s recommendation, members unanimously approved the selection of SPP’s controls, financial and benefit plan auditors KPMG, BKD and Thomas & Thomas. Members also authorized Brown and CFO Tom Dunn to negotiate the origination of a $30 million line of credit.

First Competitive Tx Project Pulled; ND 345-kV Line Approved

SPP members and its board wasted little time in approving the withdrawal of SPP’s first competitive project under FERC Order 1000, the 22.6-mile, 115-kV line from Walkemeyer to North Liberal in southwest Kansas. (See SPP Cancels First Competitive Tx Project, Citing Falling Demand Projections.)

The group also approved modifying Basin Electric Power Cooperative’s notice to construct (NTC) for a 33-mile line between two substations in western North Dakota. The modification will allow Basin Electric to build the Kummer Ridge-Roundup project — part of a larger project that is already under construction — as a 345-kV line, a motion rejected two weeks ago by the Markets and Operations Policy Committee.

SPP Kummer Ridge-Roundup Project

The project is expected to cost $45 million as a 345-kV line, compared to $24.9 million at 115 kV. Staff determined the 345-kV version performed better over a 10-year planning horizon, given projected 2.5% annual load growth driven by the nearby Bakken shale play.

Mike Risan, Basin Electric’s senior vice president of transmission, called the region the “sweet spot of the Bakken,” though field loads have proven to be volatile with the price of oil.

“The load is still coming here,” he said. “We have a pent-up demand from a number of wells already drilled and waiting to frack.”

Several members questioned whether Basin Electric was trying to run around SPP’s planning process by having the project — which was planned before the utility joined the RTO last year as part of the Integrated System — zonally allocated when it could be considered a regional project.

“We’re not trying to beat the system,” Risan said, saying the company was balancing serving load, planning for the future, transitioning to SPP and understanding new processes at the same time.

Bob Harris, senior vice president and regional manager of the Western Area Power Administration’s Upper Great Plains Region, stuck up for his fellow new member.

“The IS facility inclusion process was more restrictive than the SPP planning process,” he said. “I would submit if we had been part of SPP and part of SPP’s planning process back when we began this plan, it would have been in the SPP plan. It’s only because of the transition [to SPP] that we’re in this dilemma.”

SPP’s vice president of engineering, Lanny Nickell, said staff did not previously identify Kummer Ridge-Roundup as a “regionally needed” project, and it believes the project should be treated as a sponsored upgrade. “We didn’t determine any regional needs in the study.”

However, Nickell acknowledged that with its increased capacity, the line could have benefits that address regional needs identified in SPP’s Integrated Transmission Planning’s 10-year assessment.

“As I understand our model-build process, this project was not assumed to be built at 345, so it’s possible some of those ITP10 needs will go away.”

Most members agreed with the 345-kV solution. “I think that’s the best plan of action,” Xcel Energy’s Bill Grant said.

The board altered another MOPC recommendation from two weeks ago when it delayed until next quarter a decision to withdraw an NTC for American Electric Power’s $31 million rebuild of a 69-kV line in West Texas. Nickell said SPP is working to confirm AEP’s contention that the line suffers from congestion, saying reliability coordinators have not been able to observe the congestion in real time.

“AEP has addressed congestion on the line locally. Our findings may not necessarily change our recommendation to the board, but the situation warrants further investigation to accurately identify the frequency and significance of the congestion,” Nickell said.

The board and members also unanimously approved issuing an NTC for AEP’s rebuild of a 138-kV line near Shreveport, La. The project was initially expected to require a reactor, but that NTC was withdrawn, saving $3.55 million.

SPP Making FERC-Directed Changes to MMU

Oversight Committee Chairman Josh Martin told the board and members that SPP’s Market Monitoring Unit is well into the process of implementing changes recommended by FERC’s recent audit of the unit’s independence.

The commission last month released a report on its 17-month inquiry into the MMU, listing 16 recommendations to improve its independence. (See FERC Calls for Changes to Protect SPP Market Monitoring Unit Independence.)

Martin said the committee has begun holding “MMU-only” meetings, “consistent with the direction we got from FERC.”

He also said SPP has begun plans for the physical separation of the MMU from RTO staff, also recommended by FERC. Martin said it would be similar to the Regional Entity’s setup with SPP’s headquarters building, which requires key-card access and only allows RTO employees entrance when accompanied by an RE employee.

“There were a number of findings and recommendations that frankly were minor, in my opinion, considering the length of time and resources that went into this audit,” Martin said. “We were able to demonstrate we have a good structure and operate efficiently.”

CEO Brown noted FERC found no instances of the RTO “exerting inappropriate influence” on the MMU.

The committee has also begun discussing plans to replace MMU Director Alan McQueen, who has agreed to delay his retirement until 2017.

MMU Shares Draft State of the Market Report

McQueen shared a draft report of the MMU’s 2015 State of the Market report, the second such evaluation since the Integrated Marketplace went live in 2014.

According to the report, the Integrated Marketplace is a “significant maturing” market reflected in high levels of participation, lower levels of make-whole payments and mitigation compared to other markets, and a modest level of scarcity pricing. The MMU said the market was affected by continually declining natural gas prices, increasing wind generation capacity and output, and declining levels of overall congestion, but with increased congestion in wind-generation areas.

Wise © RTO Insider
Golden Spread’s Mike Wise makes a point during July board meeting © RTO Insider

Golden Spread Electric Cooperative’s Mike Wise disagreed with the report’s assertion that a “vast majority” of market participants running combustion turbines are able to recover their avoidable operations and maintenance costs.

“That is just not true. One of the reasons make-whole payments are so low is because you’re not allowing combustion turbines to get those start-up charges,” Wise said. “You have the view these are long-term charges. Is there an opportunity for us to continue this dialogue, not just Golden Spread, but all market participants?”

“We’ve had this discussion about the differences between what’s being used in mitigation and what’s being collected by any resource,” McQueen responded. “My disagreement with your interpretation of variable O&M is different when it comes to short run.

“I’ll reiterate my offer to look at specific units,” he continued. “If someone wants to come forward and have us look at those costs and see whether there’s adequate revenue on an annual basis, we’d love to have that conversation. The MMU can’t do it alone.”

Eckelberger closed the discussion by suggesting to McQueen that the final report include language indicating “the membership doesn’t agree with your conclusion.”

Board Approves Maher, Whitley as New RE Trustees

The board doubled the size of the RE’s trustees by approving the nomination of industry veterans Mark Maher and Stephen Whitley. The two were selected from an initial field of 22 candidates and will join Dave Christiano, the trustees’ chair, and fellow trustee Gerry Burrows.

“The two best candidates we thought we had,” Christiano told the board and members.

Both new trustees bring ample RTO leadership experience, Maher as former CEO of the Western Electricity Coordinating Council, and Whitley as NYISO’s former president and CEO and ISO-NE’s former COO.

Maher retired from WECC in 2014 after eight years of service. Before that, he was vice president of transmission services for PacifiCorp, where he was responsible for strategic and operational planning, developing transmission policy and ensuring FERC compliance. He also served as senior vice president at the Bonneville Power Administration. He is a graduate of the University of Washington.

Whitley served as NYISO’s CEO between 2008 and 2015 and was the COO and a senior vice president at ISO-NE from 2000 to 2008. He also spent 30 years at the Tennessee Valley Authority after earning an electrical engineering degree from Tennessee Technological University. He is a retired colonel in the U.S. Army Reserve.

Brown: Market Savings to Top $1B Before Year’s End

Brown said the Integrated Marketplace is on track to top $1 billion in accumulated savings by year-end. During his regular report, Brown said the markets yielded $802 million in net savings in 2014-15, after having opened in March 2014.

Integrated-Marketplace-Cost-Savings-(SPP)---content-web

SPP did not add any new market participants during the quarter. The markets currently have 172 participants, with 110 registered as financial-only and 62 as asset-owning.

Brown also said SPP has responded to the Mountain West Transmission Group’s request for proposal to develop an organized market. The group consists of a number of SPP members. (See Mountain West RTO Could Pose Competition for CAISO.)

Consent Agenda

The board’s consent agenda included issuing an NTC for a 17-mile, 115-kV line in West Texas (Mustang-Seminole) that was identified as a short-term reliability project in the 2016 ITP Near-Term assessment. The project could have been competitively bid, but because it has short-term reliability needs, it was awarded to the incumbent.

The board also re-set the baseline costs for a pair of projects both more than 20% under budget: a 69-kV Westar Energy rebuild and a 138-kV Mid-Kansas Electric transmission project.

The board also approved modifications to NTCs for four network upgrades, reducing the required emergency ratings, and approved a modification to a Nebraska Public Power District NTC for a new 345/115-kV transformer and a 22-mile, 115-kV line that resulted in no price change.

Eight revision requests were included on the consent agenda:

  • MWG-RR 7 MPRR155, revising instructions for dispatching generators out of merit order into two categories: reliability issues and emergency conditions.
  • MWG-RR 153, eliminating the requirement that market participants make two separate submissions for a single intraday change.
  • MWG-RR 161, changing the method for calculating make-whole payments for multi-configuration combined cycle resources; the new rules allow use of a netting approach in calculating the commitment-level costs eligible for recovery.
  • MWG-RR 166, removing references from the protocols and Tariff to the interim transmission congestion rights process developed for the transition into the Integrated Marketplace.
  • MWG-RR 167, avoiding Tariff violations resulting from the incorrect submission of annual revenue rights or TCRs.
  • ORWG-RR 159, moving requirements regarding the outage-coordination function into SPP Operating Criteria Appendix OP-2 “Outage Coordination Methodology,” eliminating redundant language elsewhere.
  • RTWG-RR 160, clarifying the ITP manual to note which generation interconnections and associated upgrades are required to be modeled in ITP assessments.
  • RTWG 163, correcting Tariff language to specify that the ITP manual includes references to requirements.

RR 165, which removes references to the retired Mitigated Offer Task Force from the Tariff’s Appendix G, was removed from the agenda because it does not require board approval.

– Tom Kleckner

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State Briefs

Report Cites Emissions Drop in Nine-State RGGI

A new report by the Acadia Center says that carbon emissions in the nine-state Regional Greenhouse Gas Initiative compact have dropped 37% since the program began in 2008.

acadiacenter(acadia)Part I of group’s “RGGI Status Report” found that emissions have decreased in each of the last five years. Electricity prices across the region have decreased by 3.4% on average since RGGI took effect, while electricity prices in other states have increased by 7.2%, according to the report.

RGGI states have reduced emissions by 16% more than other states and seen 3.6% more economic growth since the initiative launched, the report adds.

More: Acadia Center

CALIFORNIA

Survey Shows Most Residents Support Climate Measures

publicpolicyinstituteofCalif(institute)A majority of likely voters say they are willing to pay more for electricity generated by renewable resources to help reduce global warming, according to a survey by the Public Policy Institute of California.

The survey also found that voters approve of the 10-year-old law requiring the state to reduce greenhouse gas emissions to 1990 levels by 2020 and would support additional efforts to curtail emissions. Still, more than half of those surveyed had never heard of the state’s cap-and-trade program.

More: San Francisco Chronicle

Group Wants Waste Storage Included in San Onofre Review

A citizens group is asking the State Lands Commission to expand its environmental impact review of the San Onofre nuclear station’s decommissioning to include plans for long-term storage of nuclear waste at the shorefront facility.

Southern California Edison’s application to the agency makes no mention of its plans to indefinitely store spent fuel in containers located 100 feet from the beach. “It’s just in a really bad spot,” Ray Lutz, of Citizens Oversight, told the commission at its first public hearing on the decommissioning process. “And now we find out that that isn’t even part of the review of this project.”

A SoCalEd representative said the U.S. Nuclear Regulatory Commission has approved a license for a new storage facility at the site. The utility has proposed the EQR cover only two of four phases of the process; spent fuel storage is addressed in phase 3.

More: KPBS

COLORADO

Boulder Planning Board Approves Annexation Package

The City of Boulder’s Planning Board voted unanimously last week to recommend the annexation of 16 city-adjacent properties, part of the city’s effort to create its own municipal electric utility.

The bid to annex the properties, containing Xcel Energy facilities and customers, stems from a Public Utilities Commission ruling in November that partially rejected Boulder’s municipalization application. The commission ruled that the city could not force Xcel to sell or share facilities that also served residents outside the city’s limits.

The annexation package now goes before the City Council as the city prepares a new application for the PUC. However, Boulder and Xcel are also engaged in settlement negotiations that could bring an end to the city’s plan, which was spurred by its desire to get all of its electricity from renewable resources by 2030.

More: Daily Camera

CONNECTICUT

Groups Criticize Natural Gas Conversion at Bridgeport Plant

_POR4459Environmental groups criticized the $550 million conversion of a coal-fired power plant in Bridgeport to natural gas, saying it may actually be worse for the climate.

Environmental and community groups across New England said in a report that using natural gas until more renewable energy is available provides no gains and may actually worsen climate change. The report claims that the amount of methane leaked into the atmosphere from the extraction of natural gas is worse for the climate than burning coal.

PSEG Power has agreed to replace the coal-powered Unit 3 of Bridgeport Harbor station with a 485-MW gas-fired plant.

More: New Haven Register

KENTUCKY

IEFFA Recommends Shuttering Coal Plant

The Institute for Energy Economics and Financial Analysis is recommending that a  coal-fired power plant in the state be closed as soon as possible.

In a study, the organization said both units at the Elmer Smith Station in Owensboro should be shut down because the plant is “long past its prime” and is a financial drain on Owensboro Municipal Utilities ratepayers. The report was completed at the request of the Ohio River Valley chapter of the Sierra Club’s Beyond Coal Campaign.

“Tens of millions of dollars of new investment will be needed to keep the plant running and, using the utility’s own analyses, shows that retail rates will increase by 20% by 2018 and 80% by 2025 if both units at Elmer Smith are not retired,” IEEFA Director of Resource Planning David Schlissel said.

More: Messenger-Inquirer

EKPC Files with PSC to Build 60-Acre Solar Facility

easternkentuckypowercoop(coop)East Kentucky Power Cooperative has submitted an application with the Public Service Commission for permission to build an 8.5-MW solar energy facility in Clark County.

The proposed $17.7 million project calls for the installation of 32,000 photovoltaic panels on 60 acres next to EKPC’s offices.

A utility spokesperson said the solar facility would be funded through New Clean Energy Renewable Energy Bonds from the U.S. Energy Department, and retail customers will be able to receive monthly bill credits if they buy a 25-year, $460 license in exchange for a share of the facility’s generating capacity.

More: The Winchester Sun

MICHIGAN

State Energy Agency Backs ATC Plan for Removal of SSR

elmersmith(OMU)The state Agency for Energy said it backs a plan from American Transmission Co. to reconfigure its system in the Upper Peninsula, which would eliminate payments to a 60-year-old coal-fired power plant that it says costs ratepayers $7.3 million each year.

The agency, in a letter to MISO, endorsed ATC’s plan, which would also revise its system operating guide for the UP. The plan would eliminate the need for a system support resource (SSR) agreement to the White Pine power plant.

UP ratepayers have been making SSR payments for the operation of White Pine Unit 1 for more than two years and would be slated to continue payments until 2020. The state has challenged several other SSR agreements, which provide for payments to generators to continue running for reliability.

More: WJMN

NEBRASKA

Saline County Approves Aksamit’s 74-MW Wind Farm

aksamitresource(askamit)The Saline County Commission granted Aksamit Resource Management’s request to build a 74-MW wind farm southwest of Lincoln.

Construction is expected to begin after harvest this fall, with the turbines operational by Nov. 1, 2017. Aksamit is in negotiations to sell the wind farm’s power, but the company has declined to say with whom.

It is the first of three wind energy projects Aksamit plans for the state. The company plans to spend about $440 million on a nearby 300-MW farm and a 76-MW project.

More: Lincoln Journal Star

NEVADA

NVE Pushes Net Metering Grandfathering Proposal

NV Energy last week asked the Public Utilities Commission to allow some rooftop solar customers to receive the more generous net metering rates that were phased out at the start of the year.

Under the proposed change, customers who installed their panels or receive application approvals before the end of 2015 would be eligible to get compensated under the original net metering terms for a period of 20 years.

The utility’s request to grandfather some projects under the old rules comes as the state Supreme Court prepares to hear arguments over whether to allow a ballot initiative that would restore the original rates to all current and future customers.

More: Las Vegas Review-Journal

NORTH DAKOTA

Politicos, Regulators Fear More Coal Plants to Close

Great River Energy’s announcement that it would close a coal-fired power plant in the next year is just the first blow against the state’s coal industry, warned a congressman and a state utility regulator.

“I don’t think we can presume this is an outlier,” said U.S. Rep. Kevin Cramer, a former state utility regulator and an energy adviser to presidential candidate Donald Trump. He said he feared what has happened in the Appalachian region, where local economies have been hurt by the coal plant closures, will happen in the state.

Public Service Commissioner Randy Christmann acknowledged that low natural gas prices contributed to Great River’s decision to close its plant, but he pointed to competition from “heavily subsidized” wind energy. “I just think we’ve gotten to a point where they’re overly subsidized,” Christmann said.

More: Grand Forks Herald

TEXAS

EPE Kills $11 Charge on Rooftop Solar Customers

El Paso Electric will withdraw its proposal to charge customers with rooftop solar panels an additional $11/month under a settlement with a coalition of solar-energy companies and environmental advocates and the city of El Paso. The agreement was filed with the Public Utility Commission.

EPE withdrew the proposal after almost a year of claiming solar customers were more expensive to service and should be subject to an additional fee. Approval of the agreement by the PUC is likely to happen in the next couple months.

The battle between consumer advocates and the investor-owned utility began last year when EPE filed a rate case seeking to cover $1.3 billion in infrastructure investments. Among the proposals was an additional charge for the more than 1,770 Texas solar power users in the company’s service area.

More: The Texas Observer

WYOMING

State, Japanese Partner to Research Clean-Coal Technology

wyominggovmattmead(gov)
Mead

Gov. Matt Mead signed a memorandum of understanding last week with the president of the Japan Coal Energy Center, calling for cooperation between the consortium of Japanese companies and state experts in researching clean-coal technology.

Mead says he expects to see a conference in the state within a year that would allow Japanese researchers to work with researchers from the University of Wyoming School of Energy Resources on coal issues. The state has been pushing to try to gain access to ports in the Pacific Northwest to export coal to Asia.

More: The Associated Press

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Company Briefs

Mississippi Power said last week its Kemper County coal-gasification plant will tally up another $9 million in overruns, a cost that the company promised to absorb.

Kemper(wiki)The coal gasification plant now carries a $6.8 billion price tag, more than double its original estimate. Parent entity Southern Co. is responsible for $2.5 billion of the overall cost and wrote off $38 million before it announced its quarterly earnings last week. Southern said it spent $23 million on the Kemper plant in the second quarter.

Mississippi Power said the plant, designed to capture carbon dioxide emissions from coal, is scheduled to be completed by Sept. 30, but the company said it could announce further delays later this month. The plant is currently generating electricity by burning natural gas.

More: The Associated Press

Consumers Proposes Charging Station Network in Rate Request

michiganpsc(gov)Consumers Energy is proposing to construct a statewide electric vehicle charging network as part of its pending rate increase request before the Michigan Public Service Commission. The utility wants to install more than 800 charging stations at a cost of $15 million to its ratepayers.

Consumers spokesman Brian Wheeler said the plan would address the lack of public charging stations, earn Michigan recognition in renewable transportation and make residents more comfortable with the idea of purchasing an EV.

While stakeholders are generally supportive of the plan, advocates say Consumers should structure charging rates so EV owners see a savings over purchasing gasoline. Some also question whether general ratepayers should subsidize utility investments, including EV infrastructure.

More: Midwest Energy News

Ameren to Fund $2M in Clean Projects Under Settlement

amerenmissouri(ameren)Ameren Missouri and the Sierra Club have reached a settlement over the environmental group’s allegations that Ameren had repeatedly violated the Clean Air Act at three coal-fired plants.

The agreement, filed in U.S. District Court, requires Ameren to create a $2 million fund for “environmentally beneficial projects.” The Sierra Club said that the money will be split among community solar projects and a clean electric bus program in the St. Louis area.

The Sierra Club alleged that Ameren committed nearly 8,000 emission violations at its Labadie, Meramec and Rush Island plants from 2009 to 2013. The group said it settled partly because Ameren promised to take steps to retire the Meramec plant by 2022.

More: Sierra Club; St. Louis Public Radio

ICF Signs $11M Deal to Help KCP&L Customers Go Green

kansascityp&l(kcp&l)Global consulting and technology service provider ICF International has signed a three-year, $11 million contract with Great Plains Energy to support subsidiary Kansas City Power and Light’s residential energy-efficiency programs.

ICF will educate customers about the programs, which include heating and cooling rebates, a LED discount and income-eligible multifamily rebates.

“ICF helps us get [the] word out to customers in hopes of changing that behavior,” a KCP&L spokesperson said.

More: Kansas City Business Journal

FirstEnergy Completes Demolition of Burger Plant

burgerstation(firstenergy)FirstEnergy on Friday demolished an 854-foot concrete stack and the last remaining building at the former coal-fired R.E. Burger Power Station in Ohio.

The company plans to transfer the property to PTTGC America if the latter decides to construct an ethane gas cracker plant on the site.

The Burger plant, which began operating in 1944, was retired in 2011.

More: FirstEnergy; The Times Leader

NIPSCO Expands Indiana Car Charging Station Network

Northern Indiana Public Service Co. installed a public electric vehicle charging station last week at the offices of the Northwestern Indiana Regional Planning Commission in Portage.

The charging station is part of the utility’s two-year-old IN-Charge Around Town program, which encourages drivers to go electric. The utility has installed 80 stations throughout northern Indiana. The commission’s new charging station is free to use.

More: Post-Tribune

MidAmerican to Build Iowa’s Largest Wind Project

midamericanenergy(midamerican)The developers of what is billed as Iowa’s largest wind energy project reached agreements with major customers, including Google, Facebook and Microsoft, that will allow the facility to go forward.

Commercial customers had objected to some terms of the development, including the return on equity demanded by MidAmerican. The developer wanted 11.5%, the customers proposed 9.5% and they settled on 11%.

A final decision from state regulators on the 2,000-MW Wind XI project is expected in September, with construction to begin in December. Construction must begin by Dec. 31 in order for the project to receive the maximum federal production tax credits.

More: Midwest Energy News

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PGE Sees Transmission, Distribution Role in ‘Clean Energy Future’

By Robert Mullin

Pacific Gas and Electric’s second-quarter profits fell sharply because of a series of one-time costs — most related to the company’s natural gas business.

Still, the company sees bright prospects for its electricity business as California moves to aggressively reduce greenhouse gas emissions and increase reliance on renewable generation.

The company reported net income of $206 million, down from $402 million a year earlier. Earnings per share fell from 83 cents to 42 cents. Adjusted earnings came in at 66 cents, far short of the average analyst estimate of 93 cents.

PG&E Transmission (PG&E) - distribution clean energy future
Photo Source: PG&E

The one-time items included penalty costs stemming from the San Bruno pipeline explosion in September 2010. The company’s federal criminal trial for the incident went to a jury last week.

“We continue to believe that no PG&E employee knowingly and willfully violated the law,” CEO Tony Earley said during a call with analysts to discuss earnings. “But now it’s in the hands of the jury.”

Earley said mandates stemming from last year’s passage of California SB 350 “will influence both our procurement needs and investment opportunities.” The law raised the state’s renewable portfolio standard to 50% by 2030 and imposed increased energy efficiency requirements for buildings.

Efficiency gains will translate into declining energy demand in PG&E’s service area, Earley noted. The company also expects to lose some customers to community choice aggregators, which could seek to procure electricity from other suppliers.

PG&E will also have to cope with the rapid adoption of residential rooftop solar in California.

“We’ll have to continue to upgrade the distribution grid to handle increasing amounts of distributed generation,” Earley said.

On top of that, the company will require new and upgraded transmission lines to support the utility-scale renewables necessary to meet the state’s 50% RPS. The company is seeking an additional $100 million in capital expenditures through its 2018 transmission owner rate case filed with FERC last week, Earley said.

In April, PG&E established a strategic alliance with TransCanyon — a joint venture between Berkshire Hathaway Energy and Pinnacle West — to pursue competitive transmission projects solicited by CAISO. The arrangement “will allow us to compete in not just our service area, but the broader CAISO,” PG&E President Geisha Williams said.

“We’re well positioned to help drive California’s clean energy future through sustained investment,” Earley said.

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Overheard at NARUC’s Summer Meetings

NASHVILLE, Tenn. — Regulators and utility officials commiserated over the difficulty in overcoming public opposition to large energy infrastructure projects during a panel discussion at the National Association of Regulatory Utility Commissioners summer conference last week. About 1,000 people attended.

Libby Jacobs, Iowa Utilities Board, naruc
Jacobs © RTO Insider

Iowa Utilities Board member Libby Jacobs, who moderated the session, said she had become the target of vitriol following her vote in June approving the Dakota Access Pipeline, which will carry crude oil from North Dakota’s Bakken field through South Dakota and Iowa to Illinois. The week before the NARUC meeting, an activist group staged a street theater performance outside IUB offices called “In Bed with the Bakken,” in which one protester portrayed Gov. Terry Branstad bottle-feeding an oil pipe.

“I’m also very familiar with the anti-infrastructure protesters,” offered FERC Commissioner Cheryl LaFleur from the audience, referring to the monthly protests at FERC open meetings.

Opposition to infrastructure projects has been a challenge “since I’ve been in the industry,” she continued. “But I sense something different happening.

“I’m a little concerned … with the growing thought out there that maybe we don’t need any infrastructure at all,” LaFleur said. “‘We’re just going to close what we have and replace it with everything distributed.’”

Jacobs, a former corporate communications executive, said protesters have benefited from social media as an organizing tool.

Aakash Chandarana, Xcel Energy, naruc
Chandarana © RTO Insider

Aakash Chandarana, regional vice president of rates and regulatory affairs for Xcel Energy’s Northern States Power, said utilities need to do a better job of educating their customers.

“Often times we as a utility are trying to talk to our customers at the most intense period in our relationship — either through storms or during a rate case or something like that. … We have to approach our customers at a period of time where maybe there isn’t as much emotion.”

Robert Kenney, vice president of state regulatory relations for Pacific Gas and Electric, agreed. “I’m not sure that utilities or regulators have done [a good] job in helping customers understand why certain investments need to be made,” he said.

Robert-Kenney,-PG&E-web, naruc
Kenney © RTO Insider

He lamented the utility’s decision, announced in June, to retire the Diablo Canyon nuclear plant when its current operating licenses expire in 2024 and 2025, noting it “has been a source of greenhouse gas-free energy for the last 30-some odd years.” (See PG&E to Shut Down Diablo Canyon, California’s Last Nuclear Plant.)

“The political climate in California was such that being able to relicense that beyond 2024 and 2025 made it a huge challenge,” Kenney continued. “I say that as an example of the fact that we have technologies that will allow us to meet climate goals but then you have conflicting political goals that prohibit the running of nuclear generating facilities.”

Exelon CEO Talks Capital Allocations, New Products

NARUC President Travis Kavulla conducted an interview with Exelon CEO Chris Crane that touched on subjects from capital allocations and new utility products to the struggles of its nuclear generation fleet and cybersecurity.

Kavulla asked Crane whether Exelon, which now operates in five states and D.C. following its acquisition of Pepco Holdings Inc., favors states with higher returns on equity in determining where to allocate capital.

Crane said each of the company’s six utilities maintains its own balance sheet and cash flow and that the company makes investments based on reliability requirements.

Left to right: Crane and Kavulah © RTO Insider
Left to right: Crane and Kavulah © RTO Insider

“It does at times require equity infusion from the parent. PHI right now, and for the next five years, will have equity infusions … on an annual basis.

“We don’t find that as a conflict,” Crane said. “We’ve never had to make a decision that a dollar goes into one jurisdiction versus another … there is enough capital and our balance sheets are strong.”

Crane said Exelon’s decisions on what “utility of the future” products to offer is based on “understanding what is a trend and what is a fad.”

“We have to differentiate. Technology is changing faster than it ever has in our industry,” Crane said. “We have to watch what the consumer wants versus what the commercial side wants to sell.”

See related stories:

Commercial Customers Will Go it Alone to Meet Sustainability Goals

Commercial customers would like utilities’ help in meeting their sustainability goals but “will pursue their goals with or without” them, according to the Critical Consumer Issues Forum’s latest report released last week.

More than 80 state regulators, consumer advocates and utility representatives took part in meetings that resulted in the report, developing “consensus principles,” such as providing flexibility to consumers seeking new technologies and products while protecting nonparticipating consumers from cost shifts.

NARUC-Critical-Consumer-Issues-Forum-Panel-web
The Critical Consumer Issues Forum released its latest report last week with a panel discussion featuring (left to right) John Evans, Pennsylvania Office of Small Business Advocate; Commissioner Nick Wagner, Iowa Utilities Board; Katrina McMurrian, CCIF executive director; Bob Nelson, Montana Consumer Counsel and president of the National Association of Utility Consumer Advocates; Barbara Lockwood, vice president of regulation at Arizona Public Service; and Georgia Public Service Commissioner Stan Wise. © RTO Insider

To be responsive to customers, Arizona Public Service will initiate some innovative projects without getting regulatory approval first, said Barbara Lockwood, vice president of regulation.

“We have taken the approach that there are some projects that we’re going to embark on and we’re not going to ask the commission [in advance]. We’re going to go do it and then we’re going to ask for recovery of those costs. We’re taking some risk that we never took in the past,” she said.

Lockwood cited a 25-MW microgrid the utility is building with the U.S. Navy at Marine Corps Air Station Yuma. The microgrid’s diesel generator can provide peak power to APS customers during normal operating conditions and is large enough to power all base operations during a grid disturbance. “We didn’t seek preapproval for that project,” Lockwood said. “It was important to move quickly.”

Federal-State Battle over Plains & Eastern Transmission Line

Jordan Wimpy, an attorney representing landowners opposed to Clean Line Energy Partners’ Plains & Eastern transmission line, said he is likely to file a court challenge seeking to block the Department of Energy’s record of decision supporting the project. “We are prepared to file and we are moving in that direction,” Wimpy said.

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Jordan Wimpy (center) speaks as Sam Walsh, deputy general counsel for the Energy Department (left) and Clean Line Energy General Counsel Cary Kottler (right) listen. © RTO Insider

The department said in March that it would partner with Clean Line on the $2.5 billion, 700-mile HVDC transmission project, which would deliver 4,000 MW of wind power from the Oklahoma Panhandle to MISO and the Tennessee Valley Authority. The department acted after Clean Line was unable to win approval from Arkansas regulators. (See DOE Agrees to Join Clean Line’s Plains & Eastern Project.)

Who Will Do the Work?

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Bridgers © RTO Inisder

Mark Bridgers, a principal with Continuum Capital, a Raleigh, N.C., investment banking advisory firm, presented a forecast indicating utilities need to add 50,000 new transmission and distribution workers. By 2018, Bridgers said, all of New England, much of the Mid-Atlantic and several Western and Midwest states will face shortages in T&D workers.

Bridgers gave a plug to the Underground Construction Workforce Alliance, which is building a coalition of industry associations, unions, suppliers, engineers, contractors and utilities to develop training programs and regulatory approaches to develop the workforce required.

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Little Love for PJM in Capacity Market Debate

By Rich Heidorn Jr.

NASHVILLE, Tenn. — PJM’s Capacity Performance rules got little love last week during a panel discussion on the role of states versus markets in procuring electric generation.

Allison Clements, NRDC
Clements © RTO Insider

Other Eastern RTO capacity markets and New York’s planned nuclear subsidies also came under fire in a discussion at the National Association of Regulatory Utility Commissioners summer conference.

Economist William Hogan, of the Harvard Kennedy School, and Allison Clements, a Natural Resources Defense Council representative to the Sustainable FERC Project, led the criticism of PJM’s Capacity Performance rules.

Clements said the environmental community does not have a preference between wholesale markets and bilateral trading. “But if [markets are] going to exist, we want to make sure that the rules are fair so that clean energy resources can compete to provide services,” she said.

Aside from FERC Order 745, which helped demand response resources enter the wholesale markets, she said, “we haven’t been that successful, and we’ve come to this point where the energy/capacity market construct, at least in the Eastern Interconnect RTOs … [is] broken.”

Clements said PJM’s Capacity Performance rules, which favor baseload generation available 24 hours a day year-round, “locks in this traditional, outdated resource mix view” that favors nuclear energy over renewables and DR, a case NRDC and other environmental groups made last month in asking the D.C. Circuit Court of Appeals to review FERC’s approval of PJM’s rules. (See Clean Energy Advocates Appeal FERC’s Capacity Performance Rulings.)

Hogan © RTO Insider - pjm capacity performance
Hogan © RTO Insider

While CP rules allow summer and winter resources to aggregate a single capacity offer, no aggregate offers were submitted in the first Base Residual Auction with CP for delivery year 2018/19. In the second auction under the new rules in May, only 6% of cleared DR resources qualified as CP, compared with 9% of wind and one-tenth of 1% of solar.

“Because renewables can’t provide baseload Capacity Performance … the capacity they do provide doesn’t get counted, which means that your state policy to encourage clean energy that your customers are paying for isn’t getting full value,” Clements said.

Hogan also was critical of CP and of FERC’s oversight. He said the commission needs to ask the question: “‘Are the changes we’re making in market design going in the right direction?’ And when it’s not, to stand up and face it squarely and don’t succumb to double talk.”

PJM’s CP penalty mechanism means generators could face penalties of $5,000/MWh for shortfalls while the demand side will be seeing prices that are only $500/MWh, Hogan said.

“This can’t make sense,” he said. “You should be able to test these designs against [a] Platonic vision … and where there’s a dramatic difference like that you should be able to ask ‘Why are we doing this? Why are we sending signals to the generators and not to the load when we get into critical capacity situations?’”

Clements said it’s not necessary to abandon capacity markets and go to shortage pricing, as in ERCOT. “I think there’s something in between there,” she said, praising the “flexibility products” being offered in CAISO and MISO.

Jay-Morrison,-NRECA-web
Morrison © RTO Insider

Jay Morrison, vice president of regulatory issues for the National Rural Electric Cooperative Association, also contended that RTO capacity markets aren’t working.

“Where’s the tangible evidence that they’re failing in their mission?” asked panel moderator and NARUC President Travis Kavulla, noting the new resources that have cleared PJM and other capacity markets.

“My litigation budget,” Morrison quipped. “I could save a lot of money if these markets were working properly.”

But Morrison also challenged Hogan. “There’s no Platonic ideal of a market out there,” he said. “Markets are designed for specific purposes. These markets should be designed to meet the needs that the consumers express through the utilities that serve them, through their politically elected or appointed officials.

“The market should be designed to meet the needs that the consumers want,” he continued. “The consumer shouldn’t be asked to buy the product that the market says is the right product. We need to remember which is the dog and which is the tail.”

Morrison said states have intervened — sometimes running afoul of FERC jurisdiction — “because there are important values that they are trying to pursue … that aren’t important to the market operators and aren’t incorporated into the market design.”

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The entire panel with Travis Kavulla, NARUC President, on the far right. © RTO Insider

“Yes there are new resources [from capacity markets], but are they the right resources?” Morrison asked. “Yes, there are new resources, but are some of the people investing in them risking that they’re going to pay twice? Both for the resource in which they’re investing and the one that the market operator says they’re supposed to buy.”

RTOs have developed valuable new products for managing system operations but have not responded with the environmental or risk management products sought by consumers and state policymakers, he said. “Those are the kind of products for which bilateral markets are ideally suited,” he said. “And so long as we have the minimum offer price rule [and] buyer-side mitigation, we have trouble accessing those resources.”

Haugh © RTO Insider
Haugh © RTO Insider

The only panelists to offer much support for RTO capacity markets were Michael Haugh, assistant director of analytics for the Ohio Consumers’ Counsel, and Sarah Novosel, senior vice president and managing counsel for Calpine.

Haugh said PJM’s markets have brought new generation to serve Ohio and encourages sharing of resources among states, which reduces costs.

Novosel said her company would prefer capacity markets in all regions. She reserved her criticism for state interventions, such as proposals in Illinois, Connecticut, New Jersey and New York to subsidize nuclear plants. She said New York’s zero-emission credit program for its upstate nuclear fleet is discriminatory, will hurt markets and intrudes on federal jurisdiction, in violation of the U.S. Supreme Court’s ruling in Hughes v. Talen. (See related story, New York Adopts Clean Energy Standard, Nuclear Subsidy.)

“We’re troubled by all of these proposals because all of them, we feel, are going to undermine the wholesale markets, which competitive generators rely on for our revenue,” she said. “And once you start to pull the string and start to unravel these wholesale markets, you’re going to end up with having other generators who rely on the wholesale market needing a subsidy or long-term contract in order for them to also receive sufficient revenue to continue operations. … And by entering long-term contracts, you’re putting the risk back onto the ratepayers.”

Novosel © RTO Insider
Novosel © RTO Insider

Novosel acknowledged that “we don’t have any answers — yet.” But she said she is encouraged by the efforts being taken by RTOs to address the challenges. She cited PJM’s white paper in May and its Aug. 18 Grid 20/20 forum on public policy goals and market efficiency, and the New England Power Pool’s planned stakeholder meeting on Aug. 11 on how to preserve markets while also reducing states’ carbon footprints. “We’ve got a lot of smart people in this industry. We can come together and come up with a solution that works,” she insisted.

The simplest fix for the plight of nuclear generation and the desire for less polluting resources, the panel agreed, was to internalize the cost of carbon into the markets — a no-brainer to economists but a nonstarter for many politicians.

“I just don’t believe that” enacting a carbon tax is impossible, Hogan said, noting that he heard similar warnings before ERCOT’s move to scarcity pricing.

“I’ve been involved in lots of things that were ‘politically impossible’ when we first started talking about them,” he said. “And now they’re old hat and conventional wisdom.”

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Akins: AEP Wants Only Partial Restructuring of Ohio Market

By Tom Kleckner

American Electric Power CEO Nick Akins said last week the Columbus-based energy giant is seeking only a partial “restructuring” of Ohio’s energy market, not full reregulation.

After FERC ruled in April that it would review state actions to guarantee income for some of AEP’s Ohio power plants, Akins had said the company would lobby Ohio lawmakers for reregulation of the state’s electricity market while also considering selling off its Ohio fleet. (See All Eyes on AEP, FirstEnergy with Ohio PPAs in Doubt.)

AEP Dresden Gas Plant in Ohio (AEP) - Akins: AEP Wants Only Partial Restructuring of Ohio Market
AEP Dresden Gas Plant in Ohio Source:AEP

Asked during a July 28 call with analysts whether AEP was de-emphasizing “reregulation” of the market, Akins said, “Reregulation just has a larger connotation to it and actually is a much heavier lift to put the entire genie back in the bottle.

“With FERC’s order essentially taking the Ohio [power purchase agreement] proposal approved by the Ohio commission off the table, which I discussed last quarter, AEP is addressing the situation by pursuing restructuring in Ohio,” he said. “Note this is restructuring, not reregulation.”

Akins said state lawmakers and other power generators are discussing the company’s proposed legislation that would transfer its competitive power generation to its AEP Ohio subsidiary. The legislation would also allow AEP to invest in new natural gas and renewable energy power sources.

“The proposed legislation strikes a balance between our ability to invest and maintain generation in the state and the customers’ ability to choose generation suppliers,” Akins said.

AEP has said it won’t build new gas plants in the state and would sell all its Ohio plants if the legislature is unable to come up with a solution. The Public Utilities Commission of Ohio had approved the earlier guaranteed-income proposal after almost two years of debate.

The company reported a quarterly profit of $502 million ($1.02/share), up from $430 million ($0.88/share) a year ago. It reported sales of $3.9 billion, up slightly from $3.8 billion. Akins said AEP’s focus on process improvement, cost discipline and capital allocation “gives us confidence that we can achieve operating earnings within our guidance range of $3.60 to $3.80 per share for 2016.”

AEP stock closed up at $69.30 Friday, an increase of 43 cents since the earnings announcement.

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SPP, MISO No Closer to Day-Ahead FFE Exchanges

By Amanda Durish Cook

Negotiations with MISO over the exchange of day-ahead firm flow entitlements “are proving to be more difficult than originally expected,” SPP told FERC in its third informational report on the RTOs’ market-to-market coordination (ER13-1864).

The RTO said it continues to review MISO and PJM’s new day-ahead FFE exchange process and collect daily data from MISO. However, “SPP’s experience with the real-time market-to-market coordination procedures and the ensuing negotiations with MISO to try to improve those procedures has reinforced SPP’s belief that it would be premature to implement a day-ahead firm flow entitlement exchange process at this time,” it told the commission. (See “Regions Begin FFE Exchanges,” MISO/PJM Joint and Common Market Meeting Briefs.)

spp, miso, seams steering committee -Day-Ahead FFE Exchanges

SPP said it was concerned about the potential impacts on its transmission congestion rights markets. “SPP needs to be reasonably certain that the firm flow entitlements being exchanged will result in equitable and efficient operational and settlement outcomes,” it said.

The RTOs have fared little better on implementing interface bus pricing, SPP said. It attended preliminary analysis presentations given by both MISO and PJM and discussed the issue separately with staff members of each RTO. The results, SPP said, make it unsure that the PJM-MISO seam is comparable with SPP and MISO’s.

Instead, SPP said, the RTOs are planning a study that would examine interface consistency, gaming opportunities, equity concerns and flow issues. The study is expected to begin in September and wrap up by the end of the year.

Despite the apparent lack of progress, SPP said it was interested in continuing its analysis of the MISO-PJM processes and working with both RTOs.

SPP’s informational reports were mandated by FERC in a January 2015 order. Reports are due every six months until the RTOs reach an agreement.

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PJM Markets and Reliability and Members Committees Briefs

WILMINGTON, Del. — PJM needs to increase its fees to cover rising expenses and rebuild its diminishing operating reserve, officials told the Members Committee on Thursday.

Staff presented a first reading on five options for revising the administrative rate used to collect fees from members and market participants.

PJM is looking for member approval to increase the rates to $0.41/MWh of load served, up from the current $0.34/MWh. The options presented include a single change to a $0.41 rate, a 2.5% annual increase starting in 2018 through 2023 or an annual $0.01 increase through 2022. The 2017 rate in all options is $0.36/MWh.

A new method is necessary because PJM has been below its authorized operating reserve of $15 million since 2013. Staff had expected to rebuild the reserve to $17 million in 2015. Instead, it saw the reserve fall to $7 million because of lower-than-expected revenues. Although it trimmed expenses by $10 million below budget, to $273 million, it generated revenues of only $269 million.

2006 – 2015 Service Volume Changes (PJM) Markets and Reliability Committee, Members Committee

PJM has changed the way it charges members and market participants several times over the past 20 years.

Before 1999, the RTO charged members a single formula rate based on load served. From then until May 2006, the RTO moved to multiple formula rates based on both load and market activity.

In 2006, PJM added a rider to cover the cost of the Advanced Control Center (AC2), and in 2011 it decreased service category rates by 3%, citing economies of scale. All proposals assume an early retirement of this rider because the debt attached to it will be paid off in September

The Finance Committee is expected to make a recommendation to the Members Committee and Board of Managers at its meeting Aug. 24.

CFO Suzanne Daugherty said she expected the committee to choose an option calling for a 2.5% annual increase from 2018 through 2023, which would restore the reserve to full funding by the end of 2017 and maintain it through 2026.

PJM will return to the Members Committee in September for an endorsement vote. It will then make a filing with FERC with a target effective date of Jan. 1.

(Editor’s Note: An earlier version of this story incorrectly stated that PJM’s expected administrative rate for 2017 will be $0.37/MWh.)

Grid Remains Strong During Recent Heat Wave

PJM canceled maintenance outages for the first time under Capacity Performance rules as the system experienced seven days of hot weather beginning July 21, Mike Bryson, vice president of operations, told the Markets and Reliability Committee on Thursday.

The peak load for the period — 151,882 MW — occurred July 25. That was the RTO’s 13th-highest ever and the highest since July 2011, when PJM set an all-time record of 165,492 MW.

The daily average LMP for July 25 was almost $36/MWh, Bryson said. Forced outages for the period were less than 13,000 MW.

“The transmission system has been very strong on the voltage side,” he said. During the period, however, two 765/345-kV transformers tripped in different parts of the system, causing local congestion.

The Dumont T2 line in Indiana tripped July 21, and the Cloverdale-Joshua Falls line in Virginia tripped July 26 because of storms, Bryson said.

 

PJM Moves Toward Order 825 Compliance Filing

The MRC approved a problem statement to begin work on compliance with FERC Order 825, which set new rules for RTO settlement intervals and shortage pricing triggers. Staff will begin work at the Aug. 10 Market Implementation Committee meeting to identify and address potential impacts. (See “Members Prepped for Problem Statement on Settlement Intervals, Shortage Pricing,” PJM Markets and Reliability and Members Committees Briefs.)

The order requires settling transactions in the same time intervals they are scheduled, priced or dispatched, along with aligning shortage pricing to work in the same intervals. While PJM already incorporates shortage pricing, staff realized the current system requires changes to ensure pricing signals aren’t unnecessarily erratic. The RTO’s problem statement goes beyond the requirements of the order to address these issues as well.

The original language of the final key work activity didn’t sit well with some participants, who were concerned it might open the door for revising the demand curves rather than simply adjusting the pricing intervals within them. The language was updated prior to approval to read: “Develop a new set of steps within the demand curves to be implemented in the final rule, if necessary.”

The debate went on for nearly an hour, leading PJM CEO Andy Ott to weigh in and assure members that the point was to avoid wild price fluctuations, not to adjust the overall rate structure.

PJM’s plan is to smooth out the pricing signals over time so they only trigger shortage pricing when it’s a trend.

“The look-ahead engine looks out over time, and it has to see the shortage for a persistent period of time before it will pass the indicator over to the [real-time schedule] engine,” PJM’s Rebecca Carroll said.

PJM has only had one incident of shortage pricing in recent memory, on Jan. 6-7, 2014.

Susan Bruce, who represents the PJM Industrial Customer Coalition, supported the focus on shortage pricing. Under the current demand curves, she said, consumers can be charged higher prices for a whole hour for a shortage that might last only five minutes.

Work on Fuel-Cost Policy Updates Moves Ahead

PJM market analysis manager Jeff Schmitt presented a timeline for the days remaining before the RTO’s Aug. 16 deadline for making a FERC compliance filing on its fuel-cost policy protocols.

The Market Implementation Committee held a special meeting on July 27 and has another scheduled for Aug. 4. Schmitt said he hopes to have the language updated prior to the committee’s regular meeting on Aug. 10. He asked that any additional feedback be sent to him.

In June, FERC ruled that PJM “lacks provisions for sufficient review of cost-based offers and could permit a resource to submit inaccurate cost-based offers.” It ordered PJM to add to its Tariff and Operating Agreement a requirement that generators submit fuel-cost policies that are approved by the RTO prior to submitting cost-based offers, including a penalty structure for those that file inaccurate information (ER16-372).

Feedback from the MIC meetings will be used to update PJM’s Manual 15. Schmitt said PJM has asked for a Dec. 1 effective date but that implementation of the new language will be based on when FERC responds.

MRC Endorses Manual Changes

Members unanimously approved the following manual changes:

Manual Changes Clarify ‘Physicality’ of Transactions

MRC members endorsed changes to Manual 18 clarifying the rights and responsibilities involved in auction-specific bilateral transactions. (See “Members OK Clarifications to Preserve ‘Physicality’ of Auction-Specific Bilateral Transactions,” PJM Market Implementation Committee Briefs.)

New PLS Exception Process Offers Flexibility

The Members Committee approved Operating Agreement and Tariff language giving more flexibility to the parameter-limited schedule exception process. (See “More Flexible PLS Process Approved,” PJM Markets and Reliability and Members Committees Briefs.)

— Suzanne Herel and Rory D. Sweeney

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PJM Members Spar over CP Penalty Rate

By Suzanne Herel

WILMINGTON, Del. — PJM stakeholders rejected a pair of dueling measures Thursday, leaving a new senior task force to decide whether to reconsider a formula key to calculating nonperformance penalties under the new Capacity Performance rules.

The sector-weighted votes capped more than an hour of heated discussion at the Markets and Reliability Committee that included allegations of political maneuvering and a call for one member to be sanctioned for “ad hominem attacks.”

The debate was sparked by the proposed charter of the Underperformance Risk Management Senior Task Force (URMSTF), an item that had been approved by lower committees with little to no discussion, despite months of controversy over the problem statement that created the group. (See PJM Generator Risk Proposal Faces Resistance.)

In recent task force meetings, however, some members had raised the question of whether the RTO was using an unrealistic number in figuring its performance assessment hour (PAH) charge rate. They worried it would artificially lower penalties in the new regime, under which generators are eligible for bonus payments and exposed to financial penalties depending on their performance. Lowering the penalties, some members argued, would weaken generators’ incentive to perform under the new market model.

Thus ensued speculation over whether such a discussion fell within the task force’s scope.

Calpine Offers Problem Statement

Fearing that the issue might be determined to be beyond the group’s mandate, David “Scarp” Scarpignato of Calpine brought a problem statement to the MRC to ensure the formula would be discussed somewhere.

David Scarpignato (Scarp), Calpine - PJM Members Spar over Capacity Performance
Scarpignato © RTO Insider

“PJM had suggested that maybe it could be covered under the” task force, Scarp said. “I had indicated that I wasn’t sure that was the group to cover it because they seem intent on reducing the incentives for performance.”

According to the problem statement, informed by data from the Independent Market Monitor, “The current PAH number used in the denominator of the nonperformance charge rate does not reflect the expected number of PAHs as intended. The use of 30 hours is not adequately supported. The average of the RTO-wide PAH in the last three years was 14 hours, including the 30 hours in delivery year 2013-2014 that resulted primarily from January 2014, an outlier year.

“Too low of an expected PAH value avoids confronting capacity resources with the intended nonperformance disincentives under CP philosophy.”

The penalty nonperformance charge rate is the net cost of new entry ($/MW-day) multiplied by 365 days and divided by the 30-hour PAH value. Thus, if the value were reduced from 30 hours to 14, the penalties would more than double.

Scarp said that he had raised this issue at the last task force meeting.

“People talked at least five minutes about what’s in the scope and out of scope with this charter. There were varying opinions. People for the most part wanted to go past managing the risk and talk about the penalties you’d be exposed to. … If the group is looking at risk, it can’t be only one side, to make CP weaker.”

If the task force is limited to hedging risk, he said, its charter might as well be called the “reduce the CP effectiveness proposal.”

Incentives Key to CP

Dan Griffiths, executive director of the Consumer Advocates of PJM States, said it was important to guard performance incentives.

“If the incentives are, in fact, less, we feel like we are losing ground here,” he said. “That’s the only thing [consumers] got out of this — it’s in the interest of consumers to have strong incentives.

“You can’t quintuple the actual rate, but there is a discussion to be had here.”

Mitigating Risk for Generators

On the other side of the debate was Bob O’Connell on behalf of PPGI Fund A/B Development, who authored the problem statement that begat the task force. PPGI is the parent company of Mattawoman Energy, which is building a combined cycle plant near Brandywine, Md., in Prince George’s County.

O’Connell introduced the initiative in October, saying CP allows companies with multiple generators to offset poor performance with over-performing units but does not allow after-the-fact offsets, such as bilateral trades, that could help smaller generators. (See Generators Seek to Reopen PJM Capacity Performance Rules.)

At Thursday’s meeting, he proposed a motion to put off reassessing the PAH charge rate formula until after PJM has submitted an annual informational filing mandated by FERC in approving the charge rate. It was seconded by Jason Cox of Dynegy.

Countered Scarp: “Putting this off into limbo is a terrible thing to do to a fellow stakeholder, and something I have never done.” He accused O’Connell of using “procedural moves to prevent voting on this order” and being “disingenuous,” which elicited a call from O’Connell to have him sanctioned for “ad hominem attacks.” Committee Chair Suzanne Daugherty did not formally act on his request.

Breaking a Rule of Thumb

Indeed, most members prefaced their comments by saying as a rule of thumb, they do not oppose problem statements. It’s highly unusual for them to be rejected.

But after O’Connell’s measure failed with slightly less than 49% approval, members also voted down the Calpine problem statement, which was endorsed by slightly more than 44% of the votes.

Members subsequently approved the task force charter by acclimation.

The votes cut across sector lines, with generators split on the issue but more favoring O’Connell’s motion. The only sector to unanimously support Calpine’s initiative was the End-Use Customers (albeit with one abstention).

Jason Barker of Exelon had provided the “second” needed for a vote on the problem statement.

“The data shows quite strongly that 30 hours … is vastly overstated,” Barker said.

He joined Scarp in criticizing his colleagues for “procedural shenanigans and weak arguments” and encouraged them to put aside politics, saying that no one got everything they wanted out of the CP construct. “Let’s be honest around the table,” he said.

FERC Has Spoken

Some members said they were hesitant to revisit the issue because FERC had approved the charge rate using the 30 PAH hours.

Although the commission approved the 30-hour proposal as a “reasonable approximation of the upper bound” of hours during which PJM is likely to experience emergency actions, it also required the RTO to submit informational filings for five years evaluating the impact of the 30-hour assumption on resource performance. “We also encourage PJM, as it gains more experience under its new capacity construct, to reassess the assumed number of performance assessment hours and file with the commission if it believes a revision is warranted,” the commission said.

Scarp noted that FERC’s order hasn’t stopped stakeholders from questioning other aspects of the ruling, including operating parameters and seasonal capacity. The 30 hours, he said, is an error.

Carl Johnson, of the PJM Public Power Coalition, said, “We do not like to oppose a problem statement — that’s how we got to move forward with the URMSTF and seasonal capacity. But in this particular case, we’re talking about something so specific that FERC gave us a directive on.”

He referenced PJM’s recent experience spending months hammering out consensus on a ramp rate for the CP product, only to have FERC reject it.

“I’m not inclined to use our time on this,” he said. “I don’t want to spend time taking things to them that aren’t going to go anywhere.”

Susan Bruce, of the Industrial Customer Coalition, agreed that the charge rate was a core issue of CP, but she said it was just one and hesitated to approve re-evaluating it without looking at others.

“If you say we can’t talk about those other components, I think it’s a conversation to be had in a vacuum,” she said.

Scarp responded, “If you think that there are other numbers that are incorrect, I’m happy to look at them. I am not redesigning CP in any way. I’m probably one of the few people in the room who has never tried to redesign CP.”