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February 12, 2018March 25, 2025

NERC MRC/Board of Trustees Briefs: Feb. 7, 2018

FORT LAUDERDALE, Fla. — The chairman of NERC’s Board of Trustees said last week the organization hopes to have a new CEO in place by the summer.

Roy Thilly told the Member Representatives Committee (MRC) during its Feb. 7 quarterly meeting that the selection process is “well underway,” with a goal for this spring.

“This is an important decision the full board needs to be involved in,” he said.

Russell Reynolds Associates has been conducting the executive search. Thilly said the board will select a group of about eight potential candidates, with a small group of trustees whittling that list down to two or three final candidates. The board will interview each of the finalists.

Roy Thilly, Board of Trustees’ chair, and NERC Interim CEO Charlie Berardesco prepare for the board meeting | © RTO Insider

“Essentially, we want to be enthusiastic about the final candidate and have no hesitation that we have the right person for this job,” Thilly said. “If we don’t, then it’s important that we step back and take the time to do so.”

NERC has been without a CEO since Gerry Cauley resigned in November following his arrest for domestic abuse. General Counsel Charlie Berardesco stepped into the CEO role on an interim basis. (See Cauley Resigns; NERC Launches Search for Replacement.)

Thilly complimented NERC’s management team and staff for “really stepping up,” along with the Regional Entity CEOs.

“We feel like we’re in a good place right now,” he said. “The feedback I’ve gotten is that Charlie has stepped into the job in a seamless way and pulled the organization together.”

SPP RE Trustee Dave Christiano shares the news of Gerry Burrows’ recent death | © RTO Insider

NERC also needs to hire a new chief security officer to replace Marcus Sachs, who resigned shortly after Cauley. (See NERC Parts Ways with Chief Security Officer.) Thilly said candidates have been “assembled,” but the agency won’t move forward until the new CEO is in place.

“It’s essential the new CEO participate in that hiring process and be very comfortable with the selection,” he said.

FERC’s McIntyre Says Resiliency Still of Interest in DC

FERC Chair Kevin McIntyre | © *RTO Insider*

FERC Chairman Kevin McIntyre told NERC trustees and stakeholders that the federal government still remains focused on grid resiliency, despite the commission’s rejection of the Department of Energy’s Notice of Proposed Rulemaking meant to address the issue. FERC launched a new resiliency initiative Jan. 8 after declining to take up the department’s proposal.

“Interest in that subject is not waning on [Capitol Hill], and it is not waning in the administration,” McIntyre said. “When real-world engagements occur with resiliency, like it’s old-fashioned cousin, reliability, we should use that as a teachable moment, and take lessons forward into the game plan and be better prepared for future events.”

McIntyre said the commission looks forward to working with NERC, and that it must remain “vigilant” in ensuring the grid’s resiliency, “a phrase you’ve no doubt heard.”

McIntyre and Berardesco were among several industry witnesses who recently testified before the Senate Energy and Natural Resources Committee about the January “cold-weather bomb.” (See FERC, RTOs: Grid Performed Better in Jan. Cold Snap vs. 2014.)

“Hanging in the air was the broader overall topic of grid resiliency,” McIntyre said. “I was very glad to be in a position to report that, based on various analyses, the bulk power system operated very reliably. My general impression was that my report, and those of the other witnesses, was well-received and appreciated in how well the grid performed.”

Resiliency is a priority at FERC, McIntyre said, and he expressed his gratitude to NERC for its work on the issue. He referenced the MRC’s Reliability Issues Steering Committee, which, at the trustees’ request, is developing a framework for resiliency.

The committee told stakeholders that most resilience definitions have two common elements: that it is “time-dependent” and differs from business-as-usual operations, and that it cannot be measured in a single-unit metric. It said the National Infrastructure Advisory Council’s framework for establishing critical infrastructure goals is a “credible source for further understanding and defining resilience.”

ISO-NE’s Peter Brandien (left) visits with ERCOT’s Matt Mereness before NERC’s MRC meeting | © RTO Insider

The framework includes four outcome-focused abilities:

Robustness: the ability to absorb shocks and continue operating.
Resourcefulness: the ability to skillfully manage a crisis as it unfolds.
Rapid Recovery: the ability to restore services as quickly as possible.
Adaptability: the ability to incorporate and improve with lessons learned from past events.

“We think this framework makes sense,” said ISO-NE’s Peter Brandien, the steering committee’s chair.

DOE Looks to Work with NERC, FERC to Shape Policies

Bruce Walker, assistant secretary of the Energy Department’s Office of Electricity Delivery and Energy Reliability, said the department’s goal is to develop partnerships within the industry and provide resources to move issues forward.

“We have the opportunity to see the results of real work being done by FERC and NERC, and to shape policy through our coordination with both of these agencies,” said Walker, whose nomination was approved in October. “The [DOE] has stepped back to take a look at what our mission really is. It is … our mission-critical focus across the energy sector.”

Walker, formerly a deputy executive for Putnam County, N.Y., ran a boutique consulting firm focused on risk management at investor-owned utilities and served in leadership positions at National Grid and Consolidated Edison. He said his first goal is to develop a North American energy model “that integrates all different forms of energy so that we can run, like we do on our transmission system, a load flow.”

He said the bulk power system’s interdependencies will identify “those assets than can be enhanced, replaced or installed” to improve the system’s “affordability” as “we start moving forward” with the administration’s proposed $1.5 trillion infrastructure bill.

Other goals will focus on cyber and physical security, rapidly moving forward storage technologies, making use of sensing technologies and developing hardening strategies that add “some resiliency in a viable way.”

WECC: CAISO, SPP Efforts Pressure Peak Reliability

Jim Robb, CEO for the Western Electricity Coordinating Council, said recent developments within the Western Interconnection have put “substantial financial pressure” on Peak Reliability, the region’s delegated reliability coordinator (RC).

Within the past few months, Peak has announced it would team up with PJM Connext to attract participants to a new Western energy market. (See Peak, PJM Pitch ‘Marketplace for the West’.)

CAISO has responded by saying it will leave Peak and provide its own RC function. (See SPP, Mountain West Resolving ‘Contentious’ Issues.)

“Obviously, significant changes are going on that create a lot of uncertainty about how the ultimate reliability landscape will play out,” Robb said. He thanked FERC staff for working with WECC staff “as we move to a multiple RC model.”

NERC, WECC, British Columbia Agree to MOU

The board unanimously approved a memorandum of understanding between the British Columbia Utilities Commission (BCUC), WECC and NERC.

Modeled on recent MOUs with other Canadian jurisdictions, the agreement recognizes the parties’ roles under existing laws and authorities, maintains the status quo on funding arrangements, and provides for sharing of confidential and compliance-related information. WECC will periodically provide information on the Canadian province’s noncompliance for NERC’s review.

WECC General Counsel Steve Goodwill said a fully executed MOU should be in place in March, pending board approval from NERC and WECC.

NERC began formal correspondence with British Columbian authorities in 2006, while WECC has provided compliance monitoring for BCUC since 2009 through an administration agreement.

Goodwill said WECC is also negotiating similar terms with Mexico that recognize the changes in that country’s regulatory structure.

“Like the MOU with British Columbia, it will openly recognize for the first time the ability to share critical information on compliance enforcement in Mexico with NERC,” Goodwill said. “This is an all-around good story. The ability to share data among ourselves is critical.”

MRC Elects, Re-elects 4 Trustees to Board

NERC NERC DOE Peak Reliability Roy Thilly — NERC’s Member Representatives Committee meeting | © *RTO Insider*

The MRC approved two new members and re-elected two incumbents to the board. Suzanne Keenan was elected to a two-year term expiring in 2020 and Rob Manning to a three-year term expiring in 2021, while George Hawkins and Jan Schori were re-elected to three-year terms also expiring in 2021.

Keenan served as CIO and senior vice president of process improvement for Wawa from 2008 to 2017. Her industry experience includes field services, re-engineering and performance, regulatory performance, and emergency preparedness experience with PECO Energy.
Hawkins, CEO of the D.C. Water and Sewer Authority, was first elected to the board in 2015. He serves on the Standards Oversight & Technology and Corporate Governance & Human Resources committees.
Manning was involved in transmission and distribution infrastructure research for the Electric Power Research Institute but will give up those duties with his election. He also spent six years with the Tennessee Valley Authority.
Schori, former CEO of the Sacramento Municipal Utility District for more than 14 years, was elected to the board in February 2009. She chairs the Finance and Audit Committee and serves on the Compliance and Enterprise-wide Risk committees.

— Tom Kleckner

February 12, 2018

DC Circuit Rejects KCC Appeal of Future Rates

By Tom Kleckner

The D.C. Circuit Court of Appeals last week dismissed the Kansas Corporation Commission’s appeal of a 2015 FERC ruling over formula rates, saying it lacked standing in the case (No. 16-1093, 16-1164).

The KCC argued before the court in November that FERC acted unlawfully by approving formula rates for future public utilities to use in operating electric transmission facilities. The Kansas commission asserted that FERC couldn’t determine that the formula rates for “not-yet-existing entities to implement at some point in the future” are just and reasonable.

KCC FERC ramp rates DC Circuit — D.C. Circuit Courthouse | *U.S. Court of Appeals*

Writing for the three-judge panel on Feb. 6, Judge Karen Henderson said the KCC had not suffered harm sufficient to establish standing. “A harm that will not occur unless a series of contingencies occurs at some unknown future time is not concrete, particularized, actual and imminent,” she said.

The Kansas commission was appealing a 2015 FERC decision, in which the agency granted Transource Energy’s request for formula rates for future affiliates by replicating approved rates for Transource Kansas. Transource formed the wholly owned subsidiary to compete for Kansas-based transmission projects in SPP and said it expected to create additional subsidiaries in the future.

FERC rejected the KCC’s rehearing request in 2016, ruling that preapproving a formula rate for Transource Kansas, which did not operate any active transmission facilities, was “no different” from preapproving a formula rate for future Transource affiliates.

The KCC’s appeal to the D.C. Circuit also included a similar FERC proceeding involving MPT Heartland Development, which formed Kanstar to compete for Kansas-specific projects. The federal agency in 2015 approved Kanstar’s request for a formula rate for its own use and that of future affiliates and later denied the KCC’s rehearing request.

The court consolidated the two appeals.

In November, the KCC lost another appeal in the D.C. Circuit when it attempted to challenge a 2014 FERC order approving SPP’s merger with the Integrated System. (See Court Rejects Challenge to SPP-Integrated System Merger.)

February 11, 2018

PG&E Vows Fight over Wildfire Cost Recovery

By Jason Fordney

Pacific Gas and Electric CEO Geisha Williams said Friday that the utility will fight for the right to recover costs stemming from California wildfires “in the legal, regulatory and legislative arenas.”

San Francisco-based PG&E and other investor-owned utilities are being investigated for causing the devastating fires that wracked the state last year. Investigators for the California Department of Forestry and Fire Protection have not yet found evidence indicating the fires were caused by IOU infrastructure.

Williams said PG&E will seek a rehearing of the California Public Utilities Commission’s decision to deny San Diego Gas & Electric’s request to recover from ratepayers $379 million in costs related to the 2007 Southern California wildfires. (See Besieged CPUC Denies SDG&E Wildfire Recovery.) Heavy winds exacerbated the effects of the deadly infernos that swept across the region.

“It’s bigger than just PG&E and the other California IOUs, and much bigger than just this past year’s fires,” Williams said of the wildfires, drawing a link between them and climate change. “This is a collective societal challenge.”

PG&E reported $13 billion in electric operating revenues in 2017 and associated operating expenses of $4.3 billion. Net income was $1.6 billion after taxes, compared with $1.4 billion in 2016 and $861 million in 2015.

california wildfires pg&e cost recovery — The 2017 Tubbs and Pocket Fires in Northern California

The company had earlier announced a suspension of dividends amid uncertainty over its liability associated with last year’s Northern California fires. For the fourth quarter of 2017, GAAP results were $114 million ($0.02/share) compared with $692 million ($1.36/share) for the same quarter in 2016.

No Challenge to Diablo Canyon Decision

PG&E also said it will not contest a CPUC ruling that granted the utility just a fraction of the cost recovery it had requested for retiring the Diablo Canyon nuclear power plant, the last remaining nuke in a state where more than 60 such plants were proposed in the 1970s.

pg&e cost recovery california wildfires — Diablo Canyon Nuclear Power Plant | *PG&E*

PG&E said “today’s announcement comes after all the parties had the opportunity to confer” following the CPUC’s Jan. 11 decision on the joint proposal agreement. (See PG&E Disputes ALJ’s Diablo Canyon Recommendation.)

February 11, 2018

MISO Tempers Dispatch Plan After Stakeholder Pushback

By Amanda Durish Cook

CARMEL, Ind. — Market participants have united to develop a trio of alternatives to MISO’s plan to crack down on generators that fail to follow dispatch instructions, while the RTO has softened its position on moving ahead with a nearly final proposal.

Stakeholders representing 13 member companies began meeting to address the issue after MISO last November revealed its plan to tighten tolerances for uninstructed deviations based on a generator’s ramp rate. MISO currently flags generators that deviate from dispatch by more than an 8% over four consecutive intervals.

During a Feb. 8 Market Subcommittee meeting, DTE Energy’s Nick Griffin said informal meetings with MISO staff and the Independent Market Monitor to “brainstorm” on the topic have produced three proposals to curb deviations:

Rely on MISO’s proposal requiring a generator to move at least half its offered ramp rate, but use a more generous ramp rate multiplier;
Use a standard 6% deviation tolerance from dispatch signals; or
Employ an “energy mileage” concept that would set a tolerance based on how much electricity a unit actually moved over a one-hour period compared to how much it was asked to move.

miso dispatch instructions uninstructed deviation — Griffin | © *RTO Insider*

Griffin said all three encourage generators to follow dispatch signals.

“We don’t want units to drag on the system and be paid for dragging on the system,” he said.

However, Griffin said MISO’s solution must consider the “operational limits of resources, including wind forecasting and coal mill and boiler feed pump limits.”

Stakeholders have repeatedly called for a softer uninstructed deviation threshold than what MISO is proposing.

Before this month, MISO was close to wrapping up a final approach on stricter rules using Monitor David Patton’s proposal requiring generators to move at half their offered ramp rate, with a 20-minute grace period before being flagged and possibly losing make-whole payments. Last fall, ‎Ameren Missouri urged MISO to keep the percentage threshold, saying it could be constricted to 7 or 6% over time. The company also asked the RTO to focus only on generators that fail to move for an hour after dispatch instructions. (See Ameren Calls for Milder MISO Response to Uninstructed Deviations.)

MISO staff are now offering two new proposals developed after the informal stakeholder meetings. The first is a slightly modified approach of the RTO’s original proposal, with a cap of 12% of the dispatch level instead of the previously proposed 10%, leaving more tolerance for fast-ramping units.

The second is a performance-based approach similar to the “energy mileage” concept that partly decouples MISO’s uninstructed deviation rules from price volatility make-whole payments, preventing a generator’s deviation from immediately triggering ineligibility for those payments. In those instances, MISO would rely on an hourly price volatility make-whole payment calculation based on generator performance, ensuring that unit owners are incentivized to submit accurate ramp rates and then perform to them. The payments are designed for resources that either fail to cover production costs in the market, or have their day-ahead margins eroded by intra-hour price spikes.

MISO Market Quality Manager Jason Howard said the RTO still plans to have a final proposal readied for filing in time for the April subcommittee meeting, and that he would return to the subcommittee in March after gauging stakeholder reception to the two new proposals. MISO is also considering holding a workshop to ensure stakeholders understand what it is proposing, Howard said, although no date has been set.

February 11, 2018

MISO Scales Back Multiday Market Proposal

By Amanda Durish Cook

CARMEL, Ind. — MISO is scaling back a proposal to develop a multiday energy market, opting instead to create multiday forecasts intended to provide generators more advanced insight into ramping up for future day-ahead commitments.

The change takes the potential for multiday make-whole payments out of the equation.

The proposed effort will forecast price signals a week in advance but leave unit owners the option of whether to abide by them. As a result, MISO has scrapped the idea of providing make-whole payments to units that follow the RTO’s recommended commitment. MISO has also pushed back the target go-live date from 2019 to 2021 but still expects the effort to yield $30 million to $45 million in annual benefits once implemented. (See MISO Researching 30-Minute Reserves, Multiday Commitments.)

MISO Markets System Analyst Chuck Hansen said the RTO will assemble a cost-benefit analysis in 2022 or 2023 that could make or break the case for creating financially binding multiday commitments — after it collects 18 months of data using the multiday forecast.

Until then, the RTO sees comparable value in producing seven-day forecasts to influence generator commitment decisions without pressure, Hansen said. Market participants likewise sought to have the multiday market forecast before attaching financial commitments to it.

“There’s an opportunity here from a MISO fleet perspective to improve commitment decisions,” Hansen told stakeholders at a Feb. 8 Market Subcommittee meeting.

miso multiday market multiday forecasts — Feb 8 Market Subcommittee meeting | © *RTO Insider*

MISO’s current day-ahead market construct is not designed to forecast economic commitments beyond the next day, leaving units that have long leads or high start-up costs unable to economically commit in the market. Hansen said only 22% of the RTO’s capacity is economically committed in the day-ahead market, with the remaining 78% committed before the day-ahead market on a must-run basis, creating a prime opportunity to improve commitment decisions made before the day-ahead run. He also said a multiday forecast could be useful in scheduling weekend natural gas purchases and scheduling pumped storage resources.

miso multiday markets multiday forecasts — | *MISO*

Hansen added that MISO does already complete a multiday reliability look-ahead, but it’s solely focused on reliability and ensuring sufficient capacity and does not make suggestions based on economics.

MISO will begin working on conceptual design of multiday forecasts in 2019, Hansen said.

February 11, 2018

MISO Monitor to FERC: Order Sloped Demand Curve

By Amanda Durish Cook

MISO’s Independent Market Monitor is seeking to use the RTO’s recent refiling of its resource adequacy construct to force a FERC ruling on changing its capacity demand curve.

In an out-of-time Feb. 8 protest, the Monitor contends MISO’s use of a vertical demand curve in its annual Planning Resource Auction is a “critical design flaw” that results in “inefficient, unjust and unreasonable prices” (ER18-462).

MISO FERC demand curve resource adequacy — | *Potomac Economics*

On Dec. 15, MISO pre-emptively refiled its entire resource adequacy construct — Module E of its Tariff — following a D.C. Circuit Court of Appeals ruling that FERC overstepped its jurisdiction when prescribing revisions to PJM’s minimum offer price rule. MISO made the filing out of concern that a future ruling could undo some of its resource adequacy rules that were enacted in response to FERC’s suggestions. (See MISO Seeks FERC Reapproval to Keep RA Rules Intact.)

The filing provided the IMM a venue for forcing a FERC ruling on the sloped demand curve, a change Monitor David Patton has been unable to persuade MISO officials to adopt. Patton asked the commission to accept MISO’s filing for the 2018/19 PRA while initiating a proceeding under Federal Power Act Section 206 to force the RTO to make the changes for the 2019/20 PRA.

In 2011, FERC accepted MISO’s current resource adequacy rules, which replaced a monthly capacity auction with an annual auction using coincident peak demand forecasts to establish planning reserve requirements (ER11-4081).

FERC directed MISO in 2011 to remove proposed MOPR provisions from its capacity auction construct and instead use a peak load contribution methodology as its default for assigning capacity obligations.

The Monitor said that had MISO relied on sloped demand curve in its 2017/18 PRA, the auction would have cleared at about $115/MW-day instead of the $1.50/MW-day price in all zones. (See All Zones at $1.50/MW-day in 5th MISO Capacity Auction.) The higher price would have properly valued the reliability of the capacity, the Monitor claims.

The Monitor said the $1.50/MW-day clearing price offers suppliers less than 1% of revenues needed to break even on investment in a new peaking resource in MISO. The auction’s unreasonably low prices, Patton said, cannot support new investment “at levels that would satisfy the one-day-in-10-years reliability standard.”

“The commission relies on well-designed competitive markets to produce prices and market outcomes that are just and reasonable. No objective analysis of the MISO capacity market could demonstrate that the outcomes under the current Module E are just and reasonable by any appropriate standard. In fact, the flawed design of the market precludes it from producing just and reasonable prices. … Further, MISO made no attempt to provide evidence that its capacity market has produced reasonable outcomes or that it is an economically sound market design,” the Monitor wrote.

The Monitor also pointed to MISO’s unsuccessful 2017 filing to implement a partial forward market and downward-sloping demand curve for its retail choice areas — in which the RTO admitted that its capacity market has not produced efficient prices. During stakeholder meetings on the design proposal, Patton often repeated the need for a systemwide sloped demand curve. (See MISO Won’t Seek Rehearing on Auction Redesign.)

The Monitor’s protest came almost four weeks after the Jan. 12 deadline for filing responses to the RTO’s refiling. It said the commission should permit its out-of-time filing, contending it will not prejudice any party in the proceeding because it has not yet acted on MISO’s refiling.

In early January, the Electric Power Supply Association also protested MISO’s refiling, claiming that the RTO’s existing construct is “fundamentally flawed and has failed to support resource adequacy in the region because it lacks critical capacity market elements the commission has approved (or required) for other ISOs/RTOs.” EPSA said MISO should require capacity auction participation by all supply and demand resources, implement a downward-sloping demand curve with auctions held at least three years ahead of time and enforce a MOPR. Those three elements, EPSA argued, would create a “sustainable forward capacity market” in the footprint.

February 11, 2018

MISO Considering Time Limits on Dispute Resolution

By Amanda Durish Cook

CARMEL, Ind. — MISO is proposing to set limits on the amount of time its members have to initiate alternative dispute resolution measures, but stakeholders are saying the RTO might not be leaving them enough room to research and raise settlement issues.

MISO dispute resolution — Weissenborn | © *RTO Insider*

The RTO is recommending market participants have a 30-day time limit to request either an informal or formal alternative dispute resolution, John Weissenborn, director of market services, told a Feb. 8 Market Subcommittee meeting. Settlement disputes and corrections would be wrapped up within one year from the operating day in question under the proposal, he said.

The process is used in place of a lawsuit or FERC complaint when parties seek to negotiate contractual disputes over settlements. The RTO’s current Tariff doesn’t contain provisions that “categorically bar settlement disputes raised after a long time,” according to MISO.

MISO plans to revise Attachment HH of its Tariff — which governs such disputes — to provide market participants with 30 calendar days from the RTO’s denial of a settlement dispute to ask for an informal alternative dispute resolution, then another 30 days after that to request a formal dispute resolution if the informal request is denied by MISO.

Weissenborn said the deadlines will apply to both transmission and market settlements. The deadlines will promote “market certainty, prevent stale claims and facilitate accuracy in corrections of settlement statements,” he said.

MISO is aiming to file the plan with FERC by May, with the deadlines imposed by July.

Weissenborn said other RTOs have time limits ranging from five months to three years. Both SPP and PJM impose a two-year cutoff, while CAISO follows a three-year limit. NYISO employs the shortest cutoff at five months.

“There is precedent for this type of thing,” Weissenborn said. “It will encourage market participants to file their claim in a timely manner.”

Northern Indiana Public Service Co.’s Bill SeDoris and Dynegy’s Mark Volpe both asked how MISO’s one-year limit will line up with other RTOs’ disparate time limits should disputes involve inter-RTO matters, such as pseudo-ties and coordinated transaction scheduling, and which timeline MISO market participants should follow.

Weissenborn said MISO looked into such transactions and concluded that alternative dispute resolution would be separate for each RTO’s settlement.

Other stakeholders cautioned that the 30-day limit to research and initiate a dispute resolution may be too tight, asking instead for 60 or 90 days to initiate a dispute.

Weissenborn asked for more stakeholder comments over the next two weeks and said the comments could influence the final draft of MISO’s plan.

February 11, 2018

Lubbock Council, Utility Board Approve LP&L Settlement

By Tom Kleckner

Lubbock’s City Council and Electric Utility Board last week both approved a settlement agreement with all parties involved in Lubbock Power & Light’s effort to move 470 MW of its load from SPP to ERCOT.

The agreement, with intervenors from both systems, was approved unanimously in separate votes. Following the board’s vote, LP&L on Thursday filed the stipulation and proposed order with the Public Utility Commission of Texas for its consideration. The PUC is scheduled to take up the issue during its Feb. 15 open meeting (Docket No. 47576).

ERCOT SPP LP&L settlement agreement — LP&L power plant | *LP&L*

Under the agreement’s terms, LP&L will make a $24 million hold-harmless payment to Southwestern Public Service, which serves the utility’s load through a pair of long-term contracts, upon the transition’s effective date (targeted for June 1, 2021). The utility will also make five annual payments of $22 million, credited to ERCOT’s transmission customers in compensation for integration costs, and has committed to opting into the Texas ISO’s competitive market.

LP&L settlement agreement ERCOT SPP — Preferred Option 4OW for Integrating LP&L | *ERCOT*

LP&L said it expects to achieve annual savings exceeding the two payments.

“The agreement … sets Lubbock on the best possible path forward that saves their ratepayers money and opens the door to retail electric competition in Lubbock,” the utility said in a statement.

The only issue left to decide is what entity will build the transmission facilities linking LP&L with ERCOT. The parties signing on the settlement agreement, which include PUC staff, SPS and several consumer groups, have recommended moving forward with a project already identified by ERCOT. A pair of independent transmission companies, Cross Texas Transmission and Wind Energy Transmission Texas, are urging the PUC to open the construction to competitive bidding.

ERCOT in 2016 said its preferred solution was “Option 4ow,” a $364 million project that would result in 141 miles of new 345-kV lines. Staff last week said a competitive bidding process would “consume time and commission resources” not needed if the PUC simply followed ERCOT protocols, which provide “a suitable guide in this unique situation.” (LP&L is not yet registered in the ISO and therefore not covered by its protocols.)

ERCOT SPP Settlement Agreement LP&L — | *ERCOT*

Cross Texas said it envisions a competitive bidding process, conducted by the PUC, that could be accomplished in about 90 days.

LP&L formally announced in September its intention to move after one of its SPS contracts expires in 2021. A second SPS deal that expires in 2044 serves the remaining 130 MW of its load.

The PUC conducted two days of hearings on the matter in January. (See Texas Regulators Noncommittal After LP&L Hearings.)

February 11, 2018

MISO Accepting Market Roadmap Ideas

CARMEL, Ind. — MISO is seeking stakeholder suggestions on how it can improve its market design under its Market Roadmap process.

The project suggestion window, open through April, is part of the RTO’s biennial process of soliciting input from market participants.

MISO FERC MISO Market Roadmap Market Monitor — Johnson | © *RTO Insider*

This year’s effort will be scaled back because of the ongoing, $130 million project to replace MISO’s market platform, Lakisha Johnson, market strategy adviser, said during a Feb. 8 Market Subcommittee meeting. (See 8 Projects Set for 2018 MISO Market Roadmap.)

Stakeholders have until May 1 to submit new ideas for market improvements, and the RTO has scheduled a June 7 workshop to discuss submissions. Stakeholders will then have until July 12 to rank the new ideas, which will influence MISO staff decisions on what improvements to pursue. Through December, MISO and stakeholders will work to integrate the selected ideas into the RTO’s existing list of Market Roadmap projects.

Minnesota Public Utilities Commission staff member Hwikwon Ham asked MISO if this year’s submission window will line up with the Independent Market Monitor’s annual State of the Market report, which provides market design recommendations.

The Monitor is planning to release the report earlier this year in an attempt to better align the two sets of recommendations, IMM staffer Michael Wander said.

— Amanda Durish Cook

February 11, 2018

EPIC Interest Growing Rapidly in California

By Jason Fordney

SACRAMENTO, Calif. — Nearly 600 people crowded into the California Energy Commission’s EPIC Symposium on Wednesday, doubling attendance from last year.

It was a testament to the widespread interest in securing the hundreds of millions of dollars in grant funding California makes available to research and deploy innovative energy technologies.

California Energy Commission CEC EPIC Symposium — The California Energy Commission’s EPIC Symposium is rapidly growing each year | © *RTO Insider*

Funded through a charge on utility electric bills, the CEC’s Electric Program Investment Charge program was designed to provide $162 million annually from 2013 to 2020 to bring innovative technologies to market. The California Public Utilities Commission created the initiative in December 2011 to promote clean energy technologies, reliability, lower costs and safety. About $130 million of the annual funds are administered by the CEC.

State Sen. Nancy Skinner (D) told a packed room that the EPIC program is a way to explore and develop energy storage technologies that can reduce the curtailment of renewables and foster other efficiency improvements.

“We want to wrestle every bit of output from each unit of electricity or energy we produce,” Skinner said, discussing how her 2010 legislation, AB2514, fostered storage deployment by requiring the CPUC to consider mandating storage procurements for investor-owned utilities. “IOUs bought more storage and the price of storage came down. We want it to come down further.”

“EPIC has contributed to the development of numerous green technologies and facilitated the creation of thousands of jobs,” State Assemblymember Autumn Burke (D) said.

The CEC marked its third iteration of the EPIC program when it submitted its 2018-2020 Triennial Investment Plan last spring. The document lays out in detail the commission’s strategy over the three-year period for allocating the funds provided through EPIC, promising more coordination with local governments and enabling market growth of distributed energy resources.

“When we look at EPIC 3, we are really kind of thinking of that next generation of grid technology,” said Daniel Ohlendorf, Pacific Gas and Electric’s senior manager of electric emerging technologies.

“Electric vehicles and storage continue to be very important to us,” he said, as well as new maintenance approaches using new technologies such as augmented reality (computer-generated imagery) and drones.

Utilities at the symposium also discussed the growing pains associated with implementing storage technology. PG&E’s Morgan Metcalf described the challenges of behind-the-meter implementation.

Left to right: PG&E Senior Program Manager Morgan Metcalf, PG&E Principal Mike Della Penna and PG&E Senior Manager Daniel Ohlendorf | © *RTO Insider*

“Figuring out how to use all these resources is an important next step,” Metcalf said. “It’s not just policy that is driving this, it is our customers as well.” She added that PG&E customers are increasingly exploring solar, electric vehicles and energy efficiency.

Southern California Edison, Lawrence Berkeley National Laboratory, the University of California Berkeley and a diverse group of companies and energy organizations also held panel discussions at the symposium, with a strong focus on engineering issues, new technologies and applications such as food production.

Feb. 20 Deadline

The EPIC program is actively soliciting applications for a $15 million “Bringing Rapid Deployment to Green Energy” grant, which includes $10 million in applied research and development and $5 million for technology demonstration and deployment. Open until Feb. 20, the CEC developed the solicitation to provide follow-on funding for “the most promising energy technologies” that have previously received an award from an eligible state or federal agency for research, technology demonstration and deployment.

“The purpose of this solicitation is to fund applied research and technology demonstration and deployment energy efficiency projects that will allow researchers to continue their technology development without losing momentum or pausing to fundraise from private sources,” the CEC said. The grant is focused on advancing technology to commercialization, and is not open to public and private universities, national laboratories, utilities, private nonprofit research organizations and technology end users.