Page 1149 – RTO Insider

January 21, 2020

California PUC to Examine Gas Safety, Reliability

By Hudson Sangree

The California Public Utilities Commission launched an examination Thursday of the state’s natural gas infrastructure and the rules governing it for the first time in 16 years, citing accidents and declining demand as threats to the system’s safety and reliability.

“California’s energy system is undergoing a period of profound change,” Commissioner Liane Randolph said. “We have committed to the goals of 100% clean energy, doubling of energy efficiency, widespread transportation electrification and a carbon neutral economy by 2045. Given these adopted objectives and policies we should anticipate and plan for the long-term changes in California’s gas distribution system as well.”

The dozen companies named as respondents by the CPUC include Pacific Gas and Electric, San Diego Gas & Electric and Southern California Gas.

“Since the commission’s last decision in [January 2004], several events, such as greenhouse gas legislation, operational issues and constraints, and gas pipeline and storage safety-related incidents, require the commission to re-evaluate the policies, processes and rules that govern gas utilities,” the commission said in its order instituting rulemaking (OIR).

California PUC — The Aliso Canyon natural gas storage facility experienced a massive leak in 2015. | *California Governor’s Office of Emergency Services*

It noted that PG&E was found responsible for the explosion of a 30-inch gas pipeline in 2010 that killed eight people in San Bruno, south of San Francisco. Afterward, the commission adopted a safety plan requiring operators to outline how they would replace or pressure test all intrastate gas pipelines that hadn’t been tested recently at a cost of more than $2.3 billion.

Then in October 2015, SoCalGas identified a leak at its Aliso Canyon natural gas storage facility, which spilled 120,000 metric tons of methane before it was capped nearly four months later. Gov. Jerry Brown ordered a halt to gas injections at Aliso Canyon.

State regulators, including the CPUC, allowed limited injections to resume at Aliso Canyon in July 2017. The continuing limitations have constrained gas supply in Southern California, leading to higher wholesale electricity prices and reliability concerns. (See CPUC OKs Temporary Increase in Aliso Canyon Injections.)

Problems with interstate pipelines have also impacted supply. About 30% of the state’s electric supply comes from gas-fired generators.

Meanwhile, the state has enacted stringent GHG emission laws and required decarbonization of the grid by midcentury. Cities, including Los Angeles and San Francisco, have introduced rules and incentives to eliminate gas heating and appliances from certain classes of buildings. (See West Coast Pushes for Building Electrification.)

Falling Demand, Rising Costs

The demand for natural gas is expected to decline significantly over the next 25 years, leaving those still dependent on gas to pay the costs, the commission said in its OIR.

“Ratepayers who remain on the system the longest will likely be customers who may not be able to afford to switch from gas to electric home heating and cooling systems; yet, these customers would be required to cover the revenue requirement of the remaining pipeline system at higher rates,” it said.

In an October 2019 report titled “Natural Gas Distribution in California’s Low-Carbon Future,” the California Energy Commission discussed the “feedback effect” of building electrification and declining gas use.

“If demand for natural gas in California falls dramatically because of some combination of policy and economically driven electrification, the fixed costs to maintain and operate the gas system will be spread over a smaller number of gas sales and, ultimately, will increase costs for remaining gas customers,” the commission said.

“This outcome raises the possibility of a feedback effect where rising gas rates caused by electrification spur additional electrification,” it said. “Such a feedback effect would threaten the financial viability of the gas system, as well as raise substantial equity concerns over the costs that remaining gas system customers would face.”

The CPUC said the goal of its OIR is to ensure reliable gas service to customers at just and reasonable rates going forward.

The “proceeding will examine how industry-related events that have occurred since the last OIR require the commission to change the rules, processes and regulations governing gas utilities, including, but not limited to, reliability standards, long-term contracting, regulatory accounting, reporting and tariff changes for operational flow orders,” the commission said.

The OIR outlines a three-phased approach, starting immediately.

The first phase will examine reliability standards for the gas transmission system to determine if design changes are needed to account for a changing climate and the service capacity of current and future gas system infrastructure.

The second will consider proposals for mitigating the negative effects that “operational issues with gas transmission systems have on wholesale and local gas prices, and gas system and electric grid reliability.”

Phase three will weigh regulatory solutions and strategies the commission should implement “to ensure that, as the demand for natural gas declines, gas utilities maintain safe and reliable gas systems at just and reasonable rates, and with minimal or no stranded costs,” the CPUC said.

January 21, 2020

Texas PUC Approves LP&L Integration Project

The Texas Public Utility Commission last week approved modifications to proposed transmission lines necessary to integrate Lubbock Power & Light load into ERCOT (48909).

The approval came during the PUC’s open meeting Thursday, following a quick sidebar agreement between Oncor and the city of Lubbock over the project’s dividing point. The project will connect a 345-kV Oncor line with a 115-kV switchyard and line being built by LP&L.

LP&L Integration Project — Oncor counsel Jaren Taylor (left) and LP&L counsel Lambeth Townsend describe their companies’ agreement.

Oncor’s portion of the project could cost as much as $84 million and LP&L’s portion $61.5 million. The municipality is on the hook for $30.2 million in switchyard costs.

The project is one of several needed to move 470 MW of Lubbock’s load from SPP to ERCOT. (See “LP&L Lines for ERCOT Integration near Final Approval,” Texas PUC Briefs: Sept. 12, 2019.)

In other actions, the PUC:

approved Entergy’s request to amend its transmission cost recovery factor and recover $19.4 million (49874).
was notified by Commissioner Arthur D’Andrea that he has directed outside counsel to intervene in a MISO docket at FERC related to the treatment of energy storage facilities as transmission assets (ER20-588). (See Despite Pushback, MISO Pursuing TO-only SATA.)

— Tom Kleckner

January 21, 2020

Disasters Prompt California Rate Case Change

By Hudson Sangree

The effort to prevent utility equipment from causing disasters was a major reason the California Public Utilities Commission decided Thursday to extend the general rate case cycle for the state’s investor-owned utilities from three years to four.

After the 2010 San Bruno gas pipeline explosion and years of catastrophic wildfires starting in 2007, the commission opened its general rate case (GRC) rulemaking in 2013 “out of concern that the energy utilities were not explicitly or adequately addressing safety and reliability issues in their GRC funding requests.”

In December 2014, the commission added a Risk Assessment Mitigation Phase and the related Safety Model Assessment Proceeding to the IOUs’ rate cases. The protocols require IOUs to examine the risks they face and propose strategies to mitigate those risks, which the commissioners must then approve. (See CPUC Adds RAMP Costs to Rate Case for 1st Time.)

California Rate Case — | *California governor’s office*

In its latest decision, the commission said moving to a four-year GRC cycle would bolster disaster-prevention efforts.

“The longer cycle will allow the utilities and stakeholders to dedicate more time to implementing the new risk-mitigation and accountability structures that this commission established earlier in this rulemaking, and less time litigating GRC applications,” it said.

The longer cycle also will let the commission monitor “utility spending in something closer to real time, especially when the utility decides to reprioritize authorized funding for another purpose.”

With circumstances changing quickly because of wildfires, utilities have had to redirect money to fire prevention efforts such as tree trimming, line inspections and repairs. (See California Regulators OK Utility Wildfire Plans.)

In addition, the commission said it hoped the four-year cycle would improve efficiency in the GRC process, which can be delay-prone, by providing more time to work through difficulties.

“General rate cases are the bread and butter of what we do,” Commissioner Clifford Rechtschaffen said at Thursday’s meeting. “They’re very complex, very time consuming,” and at least one rate case is always pending, he said.

In a GRC, the commission authorizes a utility to recover capital investments and annual operations and maintenance expenses through rates charged to customers. Fundamental principles include balancing the needs of investors and ratepayers and providing safe and reliable service at a reasonable cost.

The commission’s unanimous decision said the “task we face is how to adhere to these principles in a world where — as all stakeholders can surely agree — events are moving much more quickly than can be accommodated by the existing GRC process.”

“In such circumstances, the importance of commission oversight in the midst of a utility’s GRC cycle increases,” it said. “It is no longer sufficient for the commission to authorize a multiyear GRC revenue requirement for the utility and then sit back and wait for the utility and intervenors to report back three years later regarding whether the utility spent the authorized amounts, for specifically authorized purposes, or found it necessary to use the funds elsewhere.”

The move to a four-year cycle was supported by two of the state’s large IOUs, Pacific Gas and Electric and San Diego Gas & Electric, and by the commission’s Public Advocates Office.

PG&E said the four-year cycle would allow for adjustments to the revenue requirement to address unusual circumstances and give the commission more time to weigh “the extraordinary amount of evidence” in GRCs.

CPUC staff, Southern California Edison, the state’s second largest IOU, and The Utility Reform Network, a consumer advocacy group, objected to the move.

Staff expressed concerns about switching to a four-year cycle, citing potential problems such as increased uncertainty about forecasted expenditures in the additional fourth year.

SCE did not oppose a four-year cycle outright but said it worried the longer cycle would lead to shortfalls in authorized spending. It asked for “greater tolerance on the part of the commission and parties with respect to errors and variances in forecasting.”

The new four-year cycle and other provisions incorporated into the order take effect June 30. A series of workshops to deal with implementing the changes and increasing efficiency in the GRC process will take place over the next year, the commission said.

January 21, 2020

MISO Gauging Aftershocks of TO Self-fund Order

By Amanda Durish Cook

CARMEL, Ind. — MISO is still assessing the impact of FERC’s recent order reinstating transmission owners’ rights to self-fund network upgrades while renewable proponents express worry the decision could significantly increase the cost of new generation.

The RTO is currently sorting through generator interconnection agreements struck over a three-year period to determine which need to be revised to allow TOs the opportunity to fund network upgrades, MISO counsel Mike Blackwell told stakeholders at a Jan. 14 Interconnection Process Working Group (IPWG) meeting.

MISO previously reinstated TOs’ right to self-fund starting Aug. 31, 2018, anticipating FERC’s final December order on the matter. (See Ruling Reinstates MISO TO Funding of Upgrades.) That leaves contracts signed between June 24, 2015, and Aug. 31, 2018, open to alterations.

MISO Self-fund — MISO counsel Mike Blackwell | © *RTO Insider*

“We are working to determine which of those interconnection agreements would need amendments,” Blackwell said.

He said MISO would also create “companion facility service agreements” to work out refunds to interconnection customers on network upgrades that are already being constructed.

Those agreements would vary based on how far along construction is, Blackwell said. “We are working to determine the full breadth of filings that will need to be made.”

MISO’s renewable generation proponents remain unhappy with FERC’s decision, with some arguing that the ability of TOs’ to both bill for the cost of upgrades and charge rates to use them stands to increase costs for interconnection customers, as TOs will essentially issue them loans with interest for the network upgrades. Some fear that the prospect of accruing interest could add millions to the cost of new generation, making agreement amendments attractive to TOs.

Clean Grid Alliance’s Rhonda Peters asked how MISO would guarantee its responsibility under its Tariff to provide the least-cost solution to solving transmission constraints.

“There may be multiple approaches to solving a constraint,” Peters warned at the IPWG, suggesting that MISO may need to supervise TOs’ construction decisions.

Repeat Protests Under Facilities Service Agreement

The RTO also continues work on developing a standardized pro forma facilities service agreement (FSA) to reflect the self-fund option, recently the subject of a deficiency notice at FERC.

MISO filed separately in November to standardize the TO self-fund option with a new pro forma FSA that establishes interconnection customers’ terms of repayment (ER20-359). In late December, the commission said the agreement needed more specifics on, among other things, how MISO would calculate tax benefits TOs receive on network upgrades, whether TOs would use projected or actual formula rates in their monthly revenue requirement for the network upgrade, and why the RTO included expanded liability provisions not included in its generator interconnection agreement.

The American Wind Energy Association, CGA and the Solar Council — an ad hoc group of companies that are members of AWEA’s RTO Advisory Council — used the issue to again register displeasure with the reinstatement of TO self-funding, arguing that interconnection customers bear a lopsided amount of risk in funding network upgrades versus TOs.

“Under MISO’s proposal, the [interconnection customer] must take on 100% of the risk, in addition to paying the full cost and rate of return for any network upgrade. If a TO elects to self-fund the upgrade, and seeks to earn a rate of return on its investment, then it is appropriate that the TO should also bear the risks and costs associated with the upgrade. However, under MISO’s proposal, the TO bears no risk whatsoever,” the three groups wrote in a December protest of the new FSA.

“In contrast, the [interconnection customer] is required to post security that is reduced over the payment term of the network upgrade charge, effectively requiring the [interconnection customer] to tie up its own capital for upgrades that will ultimately belong to the TO, and which the TO receives a rate of return on.”

MISO officials maintain the protests are misplaced under the FSA proceeding. FERC has already made its decision, they said, and it likely won’t permit relitigating under a filing that merely serves to streamline a process for what’s already been decided.

“They should not be considered by the commission,” Blackwell said of arguments in an interview with RTO Insider. He added that MISO is drafting a response to the deficiency letter.

Moreover, Blackwell emphasized, TOs’ option to self-fund has been a reality in MISO since Aug. 31, 2018. Based on TOs’ current rates of exercising the self-fund option, he said he anticipates only a “small fraction” of the 2015-2018 agreements will need revisions.

Blackwell said he realized TOs’ scant participation in self-funding seems counterintuitive considering the prospect of earning a rate of return.

“You would think everyone would elect to self-fund,” but they don’t, he said.

MISO officials declined to speculate further on how many interconnection agreements might need amendments.

AWEA, CGA and the Solar Council have also protested the FSA’s proposed term of 20 years’ repayment for self-funded network upgrades, arguing that MISO also provide interconnection customers the options of upfront repayment and the more standard 10-year repayment term.

Deadline to Declare TO Self-fund

MISO is simultaneously considering imposing deadlines on TOs’ decisions to self-fund upgrades, possibly requiring them to definitively elect to self-fund “at some point in time” in the definitive planning phase process of the interconnection queue, Blackwell said. The proposal is the RTO’s own and not a result of a FERC directive.

The RTO is so far considering a requirement that TOs make a “general indication” of their intent to self-fund network upgrades, Blackwell said. However, that commitment would be “nonbinding and subject to change,” he added.

MISO is also contemplating making TOs declare their intention to self-fund before it publishes the results of its system impact studies.

Some stakeholders urged MISO to make sure it has an answer from TOs on self-funding before it begins system impact studies.

“I feel very concerned about the looseness of this proposal,” CGA’s Peters said.

Stakeholders also asked if creating deadlines might be discriminatory to TOs.

Blackwell said he didn’t think deadlines would impede a TO’s ability to decide to self-fund, pointing out that it could elect to fund one network upgrade and decline to fund another. He reiterated that the proposal was merely a first draft.

“We will definitely work to find a balance,” he told stakeholders. “We invite feedback from all stakeholders on the design … and how the deadline should be structured.”

He said MISO would likely file this year to implement a self-fund deadline.

January 19, 2020

MISO Seeks Ideas for Streamlined Tx Planning

By Amanda Durish Cook

CARMEL, Ind. — A special task team convened to examine the cause of an apparent shortfall in MISO transmission capacity is seeking stakeholder input on what measures the RTO could undertake to support renewable generation.

During a Coordinated Planning Process Task Team meeting Thursday, MISO Senior Manager of Economic Planning Neil Shah said the RTO is compiling a list of ways to increase consistency between its generator interconnection and annual Transmission Expansion Plan (MTEP) planning processes. (See MISO Mulls Linking Interconnection, MTEP Planning.)

Stakeholders have suggested MISO better align the timelines of interconnection, MTEP and reliability planning and ensure the studies draw on more similar data, including dispatch assumptions.

The list will go before MISO’s Planning Advisory Committee for further consideration in March. The PAC could assign the issue to one of its subgroups, such as the Planning Subcommittee or Interconnection Process Working Group, for solution development.

Stakeholders — especially renewable proponents and state regulators — have repeatedly said MISO is unfairly relying on interconnection customers to finance new transmission capacity under the pretext of network upgrades. They contend the RTO may be neglecting a responsibility to get major transmission projects approved.

Many stakeholders have questioned why interconnection studies show the need for expensive transmission upgrades when MTEP studies do not. (See Renewables Group Calls for MISO West Tx Construction.)

“Under the current process, MISO economic planning assumes significant expansion of renewable generation but does not necessarily include projects likely to be required to accommodate the interconnection of such generation,” WPPI Energy said in comments to the RTO.

Transmission owners also recently asked the RTO to address the disparity between its generation interconnection and MTEP planning processes.

Clean Grid Alliance’s Rhonda Peters has characterized the situation as a “stalemate” where generation developers are saddled with major transmission upgrades they can’t afford, while MISO has not initiated another multi-value project portfolio since its first one in 2011. The 17-project, $6.7 billion multi-value transmission expansion in northern and central states is nearly complete. MISO has estimated that the portfolio can enable about 26 GW of new wind generation by 2031.

In early January, Ameren Transmission Company of Illinois reported it energized the $267 million, 96-mile Mark Twain 345 kV transmission project in northeast Missouri. The development leaves the 100-mile Cardinal-Hickory Creek line across southwest Wisconsin to Iowa the last of the MVPs in line for a groundbreaking ceremony.

During the task team meeting, ITC Holdings’ David Grover asked if market efficiency projects and generator interconnections could be examined in unison so projects with multiple benefits can be put forward.

“I think that one thing that we’re hearing that’s clear … is our different planning processes are siloed,” MISO Director of Planning Jeff Webb said.

Reducing the Delay

The 521 projects in MISO’s current interconnection queue represent nearly 82 GW of capacity. The Central region (parts of Missouri, Illinois and Indiana) contains the most capacity at nearly 28 GW spread over 160 projects, while MISO West (Minnesota, Iowa, parts of the Dakotas and western Wisconsin) contains 23.4 GW at 154 projects. The RTO processed about 70 generation interconnection agreements in 2019.

Renewable energy developers and advocates have argued that it’s MISO West that could use fresh transmission capacity to facilitate new wind generation. Possible regional projects, including those categorized under reliability, interconnection and MTEP, will be the subject of a West s ubregional p lanning m eeting this Thursday.

MISO is currently experiencing about a four-month delay in its affected-system studies with SPP, affecting the West region. Staff said they were looking into hiring outside consultants to speed up the process.

“We’re trying to lessen this delay in any way we can,” Resource Utilization Project Manager Jesse Phillips said at the Interconnection Process Working Group’s meeting Jan. 14.

In responding to criticisms at stakeholder meetings, MISO officials have repeatedly pointed out that historically, only about 20% of generation projects clear the interconnection queue.

Last year, a possible market efficiency project that could have paved the way for more wind to flourish in the Upper Midwest was removed from the yearly transmission package.

MTEP 19 excluded the Helena-to-Hampton Corners 345-kV second-circuit project that could have alleviated congestion in southern Minnesota, at an initial 4.22:1 benefit-to-cost ratio based on MISO estimates. However, MISO’s study process assumed that yet-to-be-built network upgrades would alleviate the congestion. Additionally, once the RTO removed forecasted wind generation from robustness testing, the project lost value.

EDF Renewable Energy’s Alex Borden said MISO’s MTEP 33 modeling significantly underestimated wind expansion. He questioned why wind siting was included in the front end of MTEP 19 modeling, then “effectively discarded in the robustness test scenarios.”

“If nothing else, MISO should open the robustness testing to a more vetted process and discussion,” he wrote in August, as more wind generation developers withdrew projects from the queue.

MISO planning staff have said the development of new 15-year MTEP futures featuring more aggressive renewable predictions — paired with its proposal to lower the cost allocation threshold on market efficiency projects from 345 kV to 230 kV — should give rise to approval of more major lines in the footprint.

The RTO will host another retooling session on the futures Feb. 13.

Meanwhile, the 10 utilities reunited for CapX2050 will next month release first results from a study examining Minnesota, eastern North Dakota and South Dakota, and western Wisconsin. The study may result in some transmission projects being built in the area. (See Minnesota Utilities Reunite for CapX2050 Study.)

January 19, 2020

PJM MRC/MC Preview: Jan. 23, 2020

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committee meetings Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Valley Forge, Pa., covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

Consent Agenda (9:10-9:15)

B. Manual 38: Operations Planning — updates from the periodic cover-to-cover review and updated procedures.

1. Modeling Generation Senior Task Force (9:15-9:30)

After deferring on the issue in December, the MRC will consider a rule change that would implement “soak time” modeling of resources. (See “Modeling Generation Senior Task Force Recommendations,” PJM MRC Briefs: Dec. 19, 2019.)

The MRC endorsed recommendations from the task force last month that can be implemented in the near term while PJM focuses on completion of its next generation energy market (nGEM). But stakeholders requested more time to investigate the soak time recommendation after expressing concerns about the time and energy it would require.

Soak time refers to the minimum period a unit must run from the generator breaker closure until it is dispatchable.

The Modeling Generation Senior Task Force (MGSTF), assembled in 2017, developed the solutions to improve resource modeling for “complex resources” in PJM’s market clearing engines, including combined cycle units, coal units with multiple mills and pumped hydro.

2. Primary Frequency Response Task Force Update (9:30-9:40)

The committee will decide whether to keep the Primary Frequency Response Task Force on hiatus through the first half of 2020.

Primary frequency response (PFR) is the ability of generators to automatically change their output in five to 15 seconds when the grid’s frequency strays above or below 60 Hz. As more renewables enter the resource mix and coal plants retire, the grid can become more susceptible to these frequency swings, threatening system reliability.

In October, PJM said 583 units with capacities of 50 MW or greater were evaluated for PFR across 10 events between March and September. The selected events for analysis met one of three qualifications: frequency goes outside the +/- 40-MHz deadband, frequency stays outside the +/- 40-MHz deadband for 60 continuous seconds or minimum/maximum frequency reaches +/- 53 MHz.

No more than 28 units provided PFR during any of the selected events. In some cases, no units responded. PJM said most critical load and black start units evaluated did not provide PFR because many were offline, operating at maximum capacity or had inconclusive results.

The task force would continue to update the Operating Committee on a quarterly basis of PFR results across the RTO.

Members Committee

Consent Agenda (11:05-11:10)

The MC will be asked to endorse:

B. r evisions to the Operating Agreement endorsed by the Financial Risk Mitigation Senior Task Force and MRC to hold five long-term financial transmission rights auctions a year, instead of three, to increase oversight and visibility into portfolio conditions so that more collateral can be collected if necessary. The revisions also would alter the structure of Balancing of Planning Period auctions so that participants can buy and sell in any month of the year, rather than being limited to a specific quarter. (See “FTR Credit Rules Endorsed,” PJM MRC Briefs: Dec. 19, 2019.)

C. r evisions to the OA to implement changes to the competitive transmission proposal fee structure. PJM will charge a $5,000 nonrefundable flat fee to all developers who submit competitive proposals. Itemized study costs will be added as necessary. RTO officials said the current tiered approach doesn’t account for the increased cost of the new comparison framework that involves an independent consultant’s review and legal and financial analyses. (See “Competitive Transmission Proposal Fee,” PJM MRC Briefs: Dec. 19, 2019.)

D. r evisions to the Tariff and OA related to the hourly differentiated ramp rate changes originating from the MGSTF. The changes will increase the number of segments on the energy offer curve (2020); introduce hourly differentiated segmented ramp rates (late 2020) and implement the soak time parameter referenced in MRC item 1 above (2022).

E. r evisions to the Tariff and OA to align them with PJM’s actual implementation of market-based parameter-limited schedules. (See “Parameter-limited Scheduling Fix,” PJM MRC Briefs: Dec. 19, 2019.)

F. r evisions to the OA clarifying the requirements for sharing forecasted unit commitment data to transmission owners for reliability studies, to ensure consistency with NERC standards and PJM manuals.

1. Members Committee Resolution (11:10-11:35)

The MC could approve an advisory against TOs’ proposal for a new Tariff Attachment M creating a new, confidential process for projects to address NERC critical infrastructure protection standard CIP-014.

LS Power drafted the document and presented it at the Dec. 5 MC meeting as tensions over the TO proposal grow increasingly fraught. (See “Critical Infrastructure Resolution,” PJM MRC/MC Briefs: Dec. 5, 2019.)

The company said the attachment conflicts with the OA because it will move forward without any vetting from the MC. At the heart of company’s argument is a belief that incumbent TOs don’t get exclusive rights to handling critical infrastructure on NERC’s CIP-014 list. Because the projects could carry significant regional implications, LS Power believes PJM should plan their mitigation. (See PJM TO Filing Stirs Up Transparency Concerns.)

Incumbent TOs argue that NERC’s confidentiality standards — and their rights under PJM’s Attachment M-4 process — support their intention to file the mitigation plan at FERC without input from other sectors.

PJM maintained its neutrality in the debate and urged all stakeholders agree about mitigating critical assets so they are no longer vulnerable to attack. (See PJM Remains Neutral in CIP-014 Debate.)

January 19, 2020

NYPSC Expands Energy Efficiency, Indexes RECs

By Michael Kuser

The New York Public Service Commission on Thursday performed some heavy regulatory lifting intended to help the state achieve its ambitious clean energy goals, committing an additional $2 billion to energy efficiency and building-electrification programs. It also created an index renewable energy credit that pays for the environmental attributes of a solar or wind farm (18-M-0084, 15-E-0302).

The energy efficiency order “puts us on a path as a state to save at meaningful levels, and saving is the way of going after the resource we don’t use, which is always the best resource,” PSC Chair John B. Rhodes said. “It leans into the [Climate Leadership and Community Protection Act], taking action now at high levels of achievement, at high levels of distributing that achievement equitably.”

Among other targets, the CLCPA (A8429) signed into law last July aims to raise the state’s energy efficiency savings to 185 trillion BTU by 2025 and greenhouse gas emission reductions by 85% by 2050. (See Cuomo Sets New York’s Green Goals for 2020.)

Various state agencies will coordinate the investments to achieve the new energy efficiency and electric heat pump targets for investor-owned utilities, investments estimated at $6.8 billion from now through 2025.

Commissioner Diane Burman stood alone on the five-member commission in voting against the energy efficiency measure. She urged fiscal and fiduciary prudence and recalled that at the PSC’s November 2019 session, she voted against reallocating uncommitted funds to the New York State Energy Research and Development Authority to administer clean energy programs. (See “CES Budget for 2020,” NYPSC OKs Rebuilding Upstate Tx Lines.)

“I have been a consistent ‘no’ when we are looking to repurpose and reallocate uncommitted funds,” Burman said. “It really begs the question to me: Why not reduce those surcharges or at least be more mindful of those programs in total from the beginning?”

A wide coalition of environmental groups endorsed the move, led by the Natural Resources Defense Council.

“Speed is of the essence when it comes to bending the curve on climate pollution,” Samantha Wilt, NRDC senior policy analyst for climate and clean energy, said in a statement. “There is no cheaper or faster way to do that than investing in energy efficiency. This order also has massive job-creating potential and will improve New Yorkers’ homes and businesses, making them more comfortable, healthier and less polluting.”

Enhancing Tier I RECs

In its order modifying Tier 1 renewable procurements, the commission directed NYSERDA to include an additional option for bidders to offer an indexed REC price in future Renewable Energy Standard (RES) solicitations, beginning with this year’s.

The American Wind Energy Association and the Alliance for Clean Energy New York last March filed a petition asserting that an indexed REC — based on a reference market index that will change monthly over the life of a RES contract — would serve as a hedge against market volatility, lower the financing costs for renewable generators, and provide lower costs and less volatile prices for ratepayers.

“Our decision today will benefit renewable energy developers by reducing their risks while also lowering customer costs,” Rhodes said.

The commission noted that adopting an indexed REC structure will require changes to the RES program, including revisions to the methodology for calculation of its annual Tier 1 REC price associated with sales to load-serving entities for both fixed-price and indexed REC payments.

The order directs NYSERDA and Department of Public Service staff to file an implementation plan within 90 days but notes that approval of the plan is not required prior to issuance of an index REC solicitation.

The Advanced Energy Economy (AEE) Institute commented that an indexed REC could cause more volatility in computing the environmental value because the calculation method is tied to the Tier 1 REC price. It suggested that environmental value might vary by zone and that the social cost of carbon could factor into setting the environmental value if the state implements the NYISO carbon pricing proposal.

The commission found “appropriate” AEE’s suggestion to hold a stakeholder process within the Value of Distributed Energy Resources proceeding to consider the issues (17-01277). (See NYPSC Refines Value Stack, Boosts Community DG.)

Burman, again the only commissioner in opposition, said she voted against the measure “because we already have had experience in these solicitations, in 2018 and 2019, that were robust. We got a lot, we were oversubscribed, so I don’t fear that somehow we need to do this to make the developers be a part of the solicitation.

“My biggest fear is, when I look to NYSERDA, I don’t see enough analysis, and I’m persuaded by New York City’s comments that there should be more substantive, quantitative analysis done to ensure that we are carefully evaluating the risk.”

Susanne DesRoches, of the New York City Mayor’s Office of Recovery and Resiliency, argued in an Oct. 2, 2019, filing that it “is essential to ensure that the potential benefits of lower REC prices are substantial enough to mitigate the added risks to customers that result from moving to an indexed pricing procurement mechanism which shifts project risk away from the developer and onto customers.”

“Given that there are nearly half a million low-income families in New York City who are over the state’s target for spending on energy bills today, it is imperative that customers do not become even more energy cost-burdened as a result of a switch in REC procurement methodologies,” DesRoches said.

January 17, 2020

California PUC Devoting $1.2B to Self-generation

By Hudson Sangree

The California Public Utilities Commission on Thursday approved $830 million in incentives for self-generation with the goal of benefiting disadvantaged customers who live in fire-prone areas and have been subject to public safety power shutoffs (PSPS) by utilities trying to avoid starting wildfires.

When added to unspent funds from prior years, that brings the total for the CPUC’s Self-Generation Incentive Program (SGIP) to $1.2 billion.

“Broadly, it shifts the focus of SGIP towards promoting resiliency,” Commissioner Clifford Rechtschaffen said at the commission’s Thursday meeting.

Ninety percent of the new funding will be available to utility customers in communities impacted by wildfires and the threat of wildfires, Rechtschaffen said. It “substantially expands the universe of customers” eligible for incentives to those whose electricity has been shut off at least twice in fire-prevention blackouts, he said.

The unanimous decision orders the state’s largest investor-owned utilities — Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — to collect a total of $166 million from ratepayers annually during each of the next five years. The changes were authorized by last year’s Senate Bill 700.

The largest category of potential beneficiaries fall under the category of “equity resilience,” Rechtschaffen said.

The efforts could provide full funding for home electricity storage systems for ratepayers in high fire-risk areas, such as the Sierra Nevada foothills and the state’s coastal ranges. Of particular concern, the commission said, are customers who are economically disadvantaged but need constant electricity to run medical devices.

About $400 million of the funds will be available to nonresidential customers in disadvantaged communities that provide critical services such as police and fire. Large-scale storage and renewable generation projects can qualify.

The utilities’ PSPS, allowed under state law and CPUC regulations, have caused tremendous controversy in California since last fall, when PG&E instituted widespread blackouts to prevent the outbreak of wildfires during dry, windy conditions.

PG&E said the shutoffs worked, though it’s trying to narrow the scope of the events going forward. The utility is in bankruptcy following two years of massive wildfires that killed nearly 100 people and destroyed at least 22,000 structures, according to the California Department of Forestry and Fire Protection.

Customers and lawmakers, however, were outraged by the size of the blackouts, which left roughly 2.4 million customers in the dark last October. (See California Officials Hammer PG&E over Power Shutoffs.) PG&E was widely accused of being ill prepared for the shutoffs, especially after the utility’s websites crashed and the state had to step in to help on an emergency basis.

“Although the utilities are ultimately responsible for managing their electric systems, the CPUC cannot and should not stop demanding better ways to reduce the scope and impacts of power shutoffs without compromising public safety,” commission President Marybel Batjer told lawmakers in November. “This cannot and should not be repeated.”

January 17, 2020

Texas PUC Approves EPE’s $4.3B Sale

J.P. Morgan’s proposed $4.3 billion purchase of El Paso Electric cleared a major regulatory hurdle Thursday when the Texas Public Utility Commission approved a modified stipulated settlement (49849).

Commission staff suggested a revision to the order to ensure that no more than two disinterested directors — those board members without direct or indirect financial interest in the transaction — will have their terms expire in the same year as part of the PUC’s ring-fencing measures.

Staff were to file the final order within the next few days.

“Congratulations,” PUC Chair DeAnn Walker told the parties after the commission’s approval.

El Paso Electric — IIF’s Lino Mendiola (left) agrees with Texas PUC Director of Customer Protection Stephen Journeay’s proposed language on disinterested directors.

J.P. Morgan’s Infrastructure Investments Fund (IIF), Sun Jupiter Holdings and EPE reached an agreement in December with PUC staff, the Office of Public Utility Counsel, the city of El Paso, and various consumer and labor groups. (See Parties to EPE Acquisition Reach Settlement Agreement.)

The Rate 41 Group, a coalition of school districts and other public entities, withdrew an earlier motion for continuance on Jan. 3 and indicated it wouldn’t oppose the settlement.

The transaction must still be approved by FERC, the Nuclear Regulatory Commission and the New Mexico Public Regulation Commission, which held a hearing Thursday on a settlement agreement between IIF, EPE and eight intervenors.

PRC Hearing Examiner Carolyn Glick will finalize her recommendations and forward them to the full commission for its final ruling, spokesman Deswood Tome said. “The hearing examiner did not specify a time of when her recommendation will be concluded,” Tome said.

The PRC’s website has been offline since a Jan. 9 ransomware attack. (See Ransomware Attack Hits New Mexico Commission.)

— Tom Kleckner

January 17, 2020

MWEX Study Could Elicit New Tx Planning for MISO

By Amanda Durish Cook

CARMEL, Ind. — MISO’s special analysis into the Minnesota-Wisconsin export interface constraint could inspire similar studies to solve non-thermal operating limits in other parts of its system.

“We are expecting several non-thermal constraints in the future, including voltage issues [and] stability issues that will limit the delivery of energy from high renewable energy penetration to load centers,” MISO Resource Interconnection Planning Manager Neil Shah told stakeholders at the Planning Advisory Committee’s Wednesday meeting.

The constraint, known as MWEX, is the subject of a special study this year as part of the 2020 MISO Transmission Expansion Plan (MTEP 20), dubbed the North Region Economic Transfer Study. (See “MTEP 20 Gains Unique Study,” MTEP 19 Advances to MISO Board Committee.)

MISO said the study will evaluate non-thermal constraints between high renewable areas in the northwestern portion of its footprint and load centers. The RTO said it’s especially expecting “bottlenecks” in its North Region, which already contains high wind penetration.

MISO MWEX study — Neil Shah, MISO | © *RTO Insider*

Shah said the RTO will project the area’s transmission needs 15 years into the future. The study may identify transmission solutions that would be subject to further studies.

He said MWEX has a “long history” in MISO.

“It’s not only being monitored in real time but in other planning studies,” Shah said. “It appears very often in interconnection [studies], especially in MISO North and West.”

Some stakeholders have expressed doubt that an actual project to assist the area will materialize, pointing out that MWEX’s transfer limits are hard-coded as constraints in MISO economic planning models.

Entergy’s Yarrow Etheredge said transmission owners support the study because typical economic studies don’t consider non-thermal operational limits.

Shah said the study would serve as an introduction to MISO evaluating the impact of expected non-thermal system operation limits in other areas of the grid.

“How do we go from informational [study] to project approval?” Clean Grid Alliance’s Natalie McIntire asked, with others echoing the question.

“We’re going to keep our options and use this information in any planning studies open next year or later this year,” Shah said of study results, adding that they may also “feed into” MTEP 21 efforts.

MISO plans to reveal a final study scope by the Feb. 12 PAC meeting. It expects to wrap up the study and announce potential recommendations in September.