Page 1368 – RTO Insider

June 5, 2018

No Details from Perry

Perry commented favorably on Trump’s directive in a speech at a DOE cybersecurity conference in Austin, Texas, Monday but did not elaborate. “Fuel-secure units are retiring at an alarming rate that — if unchecked — will threaten our ability to recover from intentional attacks or from natural disasters,” Perry said. “The president is right to view grid resilience as a serious national security issue, and he’s directed me to prepare immediate steps to stop the loss of these critical resources.”

PJM and MISO officials said Monday they were caught off guard by President Trump’s directive Friday and said they had received no information since then.

“At this time, we have seen no official communication from DOE,” said Shawna Lake, MISO’s senior director of communications and stakeholder affairs.

“I saw it when it flew in my inbox Friday,” Craig Glazer, PJM’s vice president of federal government policy, said before speaking at the EIA conference Monday.

FirstEnergy’s Lobbying Bill Revealed

Perhaps the most interesting development in the story Monday came from the Energy and Policy Institute, which published a blog post on a new filing in the bankruptcy case for FirstEnergy Solutions. The 174-page report shows Akin Gump billing FES $3.8 million in fees and expenses during April, including more than $753,000 in fees for “Energy Regulatory Issues” and federal and state “Government Affairs” work.

Akin Gump billed FirstEnergy Solutions $3.8 million in fees and expenses during April, including more than $753,000 in fees for work on “Energy Regulatory Issues” and federal and state “Government Affairs” work. | *Energy Policy Institute*

Including the $230,000 Akin Gump disclosed in a federal lobbying report for January-March, it has billed FES almost $1 million in lobbying expenses since January.

On April 13, for example, lobbyist James Romney Tucker, a former aide to Newt Gingrich, reported a “call to DOE re potential 202c determination” and a “call with White House staff re 202 status.” Tucker alone billed FES $54,312 at $930/hour for his “Public Law & Policy” work during April.

The institute is a self-described watchdog “exposing the attacks on renewable energy and countering misinformation by fossil fuel interests.” Akin Gump is D.C.’s top-earning lobbying firm.

Lifeboat Revived?

One RTO official who asked not to be identified suggested the administration’s plan may be like the “lifeboat” then-acting FERC Chairman Neil Chatterjee suggested last November in response to DOE’s Notice of Proposed Rulemaking, which the commission rejected in January. Chatterjee had contemplated a “show cause” order requiring grid operators to compensate at-risk resources that provide resilience benefits as an interim measure while the commission conducted a longer-term rulemaking. (See Chatterjee to Push Interim ‘Lifeboat’ for Coal, Nukes.)

Chatterjee had said his plan would not alter RTO dispatch practices or distort markets, though he acknowledged a lot of details remained undetermined. The idea was apparently forgotten after Kevin McIntyre joined the commission in December, replacing Chatterjee as chairman.

RTOs Caught in the Dark

RTO/ISO executives speaking at the Mid-America Regulatory Conference in Kansas City, Mo., Monday had similar reactions to the memo, with all offering assurances that reliability is well under control in their footprints.

Panel moderator and Missouri Public Service Commission Chairman Daniel Hall characterized the memo as a “possible intrusion into the markets” and asked executives for their reactions.

MISO President and Chief Operating Officer Clair Moeller said he thinks an order is unnecessary but added that the RTO keeps out of retirement decisions. He said the decision whether to close a plant in MISO is between the plant owner and the state in the mostly vertically integrated footprint. “We like to say we’re policy takers, not policymakers,” Moeller said.

However, he offered that the proposed 90 days of on-site fuel supply is not a historical standard. “We’ve never had 90 days of coal on site in the 40 years I’ve been in the industry,” Moeller said. He offered that resilience is “how you take the stuff you have and make it work to keep people safe.”

SPP Executive Vice President and Chief Operating Officer Carl Monroe also said his mostly vertically integrated RTO likely won’t see plants directly impacted, though an order could cause energy prices to rise in its footprint.

“I don’t think I get to say that it won’t affect us,” laughed Suzanne Daugherty, PJM’s chief financial officer and treasurer, noting that most states in the RTO’s territory have adopted retail choice.

But she said PJM will exceed its current resource adequacy standards in the foreseeable future. “We’ve done the planning studies, and we’re going to hit targets well above what we were trying to reach.”

FERC DOE AKIN GUMP CHERYL LAFLEUR — Left to right at MARC’s 2018 Annual Conference: Carl Monroe, SPP; Suzanne Daugherty, PJM; and Bill Magness, ERCOT | © *RTO Insider*

The move is a “drastic step” that could become a financial burden for ratepayers, Daugherty said. “Each type of resource, whether it’s intermittent, hydro, coal, nuclear, all have [fuel supply] issues.”

She also said it would be a “challenge” for independent power producers to make queue investment decisions if generators expected to retire instead begin receiving revenue streams. She pointed out that PJM has already initiated a fuel security study to examine how efficiently fuel is delivered to all plant types during times of peak demand.

ERCOT CEO Bill Magness said he is waiting on the full order to understand the possible impacts. “We’re not sure if this is applicable to ERCOT,” Magness said. “The Defense Production Act is not something I’m that familiar with, but I’m learning about it now,” he added, smiling.

“We’re trained to run security-constrained economic dispatch,” Magness said. “And if this [order] fits into security-constrained economic dispatch, well, we can do that.” But he cautioned that fuel security issues — like ensuring rail cars arrive on time — is outside of ISO/RTO control.

TRUMP Rick Perry FERC DOE AKIN GUMP CHERYL LAFLEUR — Glazer | © *RTO Insider*

PJM’s Glazer told the EIA conference Trump’s directive will “probably complicate” his RTO’s struggle to deal with state nuclear subsidies.

He said he fears a “half slave/half free” industry in which generators dependent on market revenues increasingly compete with those receiving cost-of-service payments or subsidies.

“I’m not sure that’s sustainable, to be honest,” he said. “I worry as we move down this path that we’re ignoring the lessons of the past” — the 1970s, before electric restructuring.

June 3, 2018

Calif. Senate OKs Utility Wildfire Cost Recovery

By Jason Fordney

The California State Senate passed legislation Wednesday that would allow the state’s investor-owned utilities to pass through the costs of wildfires to ratepayers if they conform with safety plans approved by the Public Utilities Commission.

Wildfire Cost Recovery CPUC California Senate — Dodd | *U.S. Army Corp. of Engineers*

SB 1088, introduced by Sen. Bill Dodd (D), would require electric and gas utilities beginning in 2019 to submit annual safety, reliability and resilience plans, which the commission could approve “with or without modification” within 18 months.

If a utility is in compliance with its plan, “the utility’s performance, operations, management and investments addressed in the plan may be deemed reasonable and prudent for purposes of any subsequent CPUC proceeding and are prohibited from affecting any civil action and any previous events.”

Dodd said that “by mandating that utilities meet new safety, reliability and resiliency requirements, we can avoid these catastrophic fires before they start.” He introduced the legislation in April. (See Calif. Legislation Shields Utilities from Wildfire Costs.)

The bill passed the Senate on Wednesday on a 34-2 vote with three legislators not voting, including U.S. Senate candidate Kevin de Leon (D). Friday was the deadline for bills to pass out of their house of origin. The deadline for bills to be passed this year is Aug. 31, and the last day for the governor to sign or veto them is Sept. 30.

The measure comes amid a decade-long debate over utility liability for wildfires, which heightened last year as more than 170 fires swept across California. The Department of Forestry and Fire Protection recently found that Pacific Gas and Electric had caused four Northern California fires, and investigations continue into much larger fires that hit the state last year. (See CalFire Says PG&E Caused 4 Wildfires Last Year.)

Utilities argue that climate change and drought are compounding the effects of the fires. Some observers also blame forest management practices for exacerbating the problem. Last November, the CPUC rejected San Diego Gas & Electric’s request to recover $379 million in wildfire-related costs for fires in 2007, drawing swift reaction from all three of the state’s investor-owned utilities. (See Besieged CPUC Denies SDG&E Wildfire Recovery.) In addition to their concerns over recovering fire costs, utilities also face civil suits by property owners blaming the power companies for fire losses.

The bill would require the state Office of Emergency Services to adopt standards and model policies that utilities and local governments should employ for reducing fire risks, including defining “defensible space.”

The Utility Reform Network had opposed the bill, saying that “rather than enhancing safety, SB 1088 would reduce current energy utility incentives to operate their systems safely and prudently and would effectively grant the utilities a blank check,” according to a May 29 bill analysis.

The Consumer Federation of California said that the 18-month CPUC timeline “undermines the possibility for a review that is fully vetted by the regulator and the public” and that the legislation “leaves almost no room for the regulator to reject a utility plan.”

Another Dodd bill passed by the Senate on Thursday, SB 901, requires utility wildfire mitigation plans to include a description of the factors the companies use to determine when they should de-energize distribution lines and procedures for notifying customers and first responders, who could encounter live lines.

Dodd’s two proposals were part of a seven-bill package approved by the Senate last week, which also dealt with homeowner insurance coverage, controlled burns and landslides. President Pro Tempore Toni Atkins (D) said the Senate has also proposed a budget that includes $483 million for fire-prevention efforts and $551 million for wildfire mitigation.

June 3, 2018

DC Circuit Rejects Ark. PSC Review of FERC-Entergy Order

By Tom Kleckner

The D.C. Circuit Court of Appeals on Friday denied the Arkansas Public Service Commission’s request that it review a 2016 FERC order directing Entergy Arkansas to continue sharing settlement proceeds under the Entergy System Agreement (16-1305).

FERC approved Entergy Arkansas’ withdrawal from the agreement in 2009. In 2016, FERC held that the utility must continue to share the proceeds of its predeparture settlement with Union Pacific with the system’s other member companies (ER13-432).

The PSC contended that the commission’s order to share the settlement benefits and its method of allocating the benefits was unlawful and unsupported by substantial evidence.

The D.C. Circuit concluded that FERC had a lawful basis to order the sharing of the benefits and was “reasoned” in its allocation methodology.

The PSC pointed to Entergy Arkansas’ withdrawal proceeding in arguing that FERC’s order “essentially amounts to the imposition of an unlawful exit fee or post-withdrawal continuing obligation.”

Writing for the three-judge panel, Senior Circuit Judge David Sentelle rejected the argument, saying FERC was right to conclude “that sharing the Union Pacific settlement benefits was necessary under the principles of equity and was not a penalty or recompense for the company’s exit from the system.”

The court also disagreed with the PSC’s contention that FERC violated the filed rate doctrine by ordering Entergy Arkansas to share the settlement benefits. Under that doctrine, public utilities may only charge rates filed with FERC.

Sentelle said FERC had determined it was not overriding a filed rate, “but merely effectuating the purpose of a non-jurisdictional contract.” He noted Entergy Services was a party to the settlement, and that “FERC found [Services] entered into the settlement on behalf of all the operating companies while they were under FERC’s jurisdiction through the system agreement.”

The court also agreed with FERC’s use of its allocation method, noting the commission found it likely “Entergy Arkansas would have entered into a multiyear transportation contract in 2011 and not benefited from [a] price dip in 2012” without the Union Pacific settlement.

“There was no evidence that Entergy Arkansas could have anticipated the 2012 drop in coal transportation prices and made different contracting decisions,” Sentelle said.

The proceeding stemmed from a 2008 settlement in Arkansas state court between Entergy Arkansas, Entergy Services and other parties against Union Pacific. The settlement locked in a below-market rate for rail delivery of coal by extending an Entergy Arkansas contract with Union Pacific to a three-year period ending June 30, 2015.

Under Entergy’s system agreement, which expired in 2016, its operating companies purchased excess energy from their sister companies at cost, incorporating coal transportation as a component. Union Pacific failed to make coal deliveries at one point, leading to the settlement.

Entergy Arkansas passed a portion of the increased coal costs to the other operating companies under the agreement’s service schedule, and also shared its beneficial coal transportation costs under the Union Pacific settlement.

However, the settlement did not address Entergy Arkansas’ impending withdrawal from the agreement, which FERC approved in 2009.

The Louisiana Public Service Commission filed a Section 206 complaint with the commission, arguing that FERC should allocate the Union Pacific settlement benefits as part of the case. The D.C. Circuit eventually upheld the commission’s decision, but it held FERC “must still review the post-withdrawal arrangements.”

The Louisiana commission again raised the Union Pacific issue when Entergy Services filed a post-withdrawal successor plan with FERC. In response, the Arkansas commission and Entergy Services challenged FERC’s authority to order Entergy Arkansas to share the settlement benefits, because the utility was no longer participating in the system agreement.

Following settlement discussions and a hearing, an administrative law judge determined that the settlement benefits should be allocated among the operating companies and adopted an allocation methodology. FERC affirmed the findings in 2016 and ordered Entergy Arkansas to make a compliance filing refunding the settlement benefits to its sister companies.

June 3, 2018

Analyst: FERC Asserts Role in Handling Nuke Subsidies

By Rory D. Sweeney

FERC and the U.S. Department of Justice struck a blow against opponents of state subsidies for nuclear plants on Tuesday when they jointly filed a brief urging the 7th U.S. Circuit Court of Appeals to reject the argument that Illinois’ zero-emission credit program is pre-empted by the Federal Power Act.

But an analyst for an industry law firm believes the brief, which was quickly cross-filed by Exelon in a similar case in New York before the 2nd Circuit, has a deeper meaning: Leave this to us.

“FERC made clear that ‘we have jurisdiction under the Federal Power Act to deal with what we view as states subsidizing these generation facilities,’” Jennifer Mersing of Stoel Rives told RTO Insider. “I think FERC was saying essentially, ‘We are handling this. … Let us be the forum where this gets worked out.’ They didn’t tip their hand about how they would rule … but I think that FERC is trying to keep within its court how it’s going to deal with states subsidizing certain nuclear facilities.”

The Electric Power Supply Association and retail ratepayers asked the courts to overturn district court rulings last year that dismissed challenges to the states’ ZEC programs. They argued that the state laws were stripping FERC of its authority over the sale of wholesale energy. (See Ill. ZECs Defenders Face Harsh Questioning on Appeal.)

“The Illinois program is not pre-empted,” FERC and the Justice Department said. “It does not require participation in FERC-jurisdictional wholesale auctions as a precondition to receive ZECs. Rather, the Illinois ZEC is ‘targeted’ at an attribute of generation resources over which Illinois has regulatory authority. … The object of the subsidy is the ‘participant,’ not the ‘actual wholesale transaction.’ The district court thus properly concluded that the ZEC program ‘falls within Illinois’ reserved authority over generation facilities.’”

Exelon, which owns five nuclear facilities that stand to benefit from the laws, joined the states in their defense and lauded the brief’s filing.

ferc zero emission credits zecs federal power act — Exelon’s Clinton nuclear facility, which benefits from Illinois’ zero-emissions credit program. | *Nuclear Regulatory Commission*

“The U.S. Department of Justice and Federal Energy Regulatory Commission told the courts that states are free to favor clean nuclear energy over pollution-emitting energy from coal, oil and natural gas power plants,” the company said in a statement. “We remain confident that the courts will uphold the view of policymakers and regulators who support the continued operation of Illinois’ nuclear plants and the environmental benefits they provide for consumers.”

Mersing agreed the brief would likely tip the court’s decision in favor of the states and leave FERC to address the issue. Judges in the Illinois case had previously questioned why EPSA was bringing the issue to them when they were simultaneously pleading their case with FERC, which noted in its brief that it will address complaints pending on the issue.

“It’s hard to quantify … but I think that if you have the agency in charge of regulating wholesale power sales [saying it] doesn’t view this law as being pre-empted by the statute it’s in charge of enforcing, I think that’s going to weigh heavily,” Mersing said. “I think the court was probably waiting for FERC to weigh in, so I would expect a decision would come sooner, but we can’t predict when the court will act.”

She predicted the courts will likely uphold the laws, making it unlikely the Supreme Court would take up the case if EPSA were to continue its appeal. The decisions will likely signal other states to pursue similar nuclear subsidies but keep them funneled through FERC, she said.

“You’ll see more states following the path because it removes some legal challenges, but it also depends on how FERC decides to handle the programs,” she said. “I think you’re going to see more complaints at the FERC level versus the federal court level.”

EPSA has requested permission to respond to the brief by June 9, which Exelon has opposed.

June 3, 2018

PJM Experiences First Load Shed in the CP Era

By Rory D. Sweeney

PJM ordered its first load-shed event since implementing Capacity Performance in 2015 after a transmission line in Indiana tripped offline on May 29.

It was also the RTO’s first trigger for the significant performance-related bonuses and penalties introduced with CP.

pjm capacity performance load shedding — PJM’s Adam Keech | © *RTO Insider*

The 30-minute event occurred at the Jackson Road substation in American Electric Power’s transmission zone, west of South Bend, Ind. PJM’s Adam Keech explained that a transformer and a transmission line unexpectedly tripped out of service about 1:20 p.m., creating a load on the facility above its ratings.

As part of its response procedures, PJM simulated the effect on the system of losing that facility. The RTO’s procedures call for continuing that analysis for facilities that subsequently would become overloaded and simulating their loss as well. If that continues for five steps without mitigation, or if it hits a larger issue and can’t be resolved, PJM pre-emptively sheds load “before anything else tripped that would potentially create a cascading outage,” Keech said during a special Markets Implementation Committee meeting Friday on updating the variable resource requirement curve.

For this situation, grid operators ordered a reduction of 71 MW of load, he said. However, the transformer kicked back into service, “so the total requested amount was never actually shed … because the equipment came back that quickly.”

No demand response was called, Keech said. PJM later confirmed the actual load shed was 21 MW.

The situation triggered the first performance assessment interval (PAI) under the CP capacity construct, which analyzes the performance of generators that were paid for a capacity commitment to supply power in that region. Units that outperformed their commitments are eligible to receive bonus payments, while those that underperform receive stiff financial penalties. The analysis compares the supply needed to the units that have commitments and only includes units that were able to help by raising their output, Keech said.

PJM is limited in how much information it can release, he said, because the event affected only a small number of generation owners. The RTO’s confidentiality rules restrict what information staff can release if fewer than four generation owners were affected, he said.

Keech noted that some stakeholders expressed concerns with how the incident was communicated and said staff plan to revise procedures to address them.

“I think when we envisioned PAIs, the discrete, very localized load-shed event wasn’t on everybody’s mind. But now that we’ve got it, we should learn to handle it a little bit better,” he said.

The event will have implications for several other markets and reliability calculations, including the balancing ratio and default market seller offer cap. (See “Balancing Ratio,” PJM Market Implementation Committee Briefs: May 2, 2018.)

June 3, 2018

CPUC Approves Utility EV Infrastructure Programs

By Jason Fordney

California regulators last week authorized the state’s investor-owned utilities to recover $738 million for electric vehicle charging infrastructure to help meet the state’s greenhouse gas reduction goals.

The California Public Utilities Commission’s Thursday order stemmed from its 2016 directive ordering the IOUs to propose projects that would advance the electrification of transportation. During the proceeding, the state’s Office of Ratepayer Advocates and The Utility Reform Network negotiated aspects of the program, originally proposed at $1 billion by the utilities.

CPUC electric vehicles charging infrastructure EV — Peterman | © *RTO Insider*

“The only way to get to a largely carbon-free California is by substantially electrifying the state’s vast transportation system,” Commissioner Carla Peterman said. “The decision made today aims to balance costs with benefits for all ratepayers, considers impacts on competition, and directs significant portions of the utility programs to disadvantaged communities often hit hardest by traffic and air pollution.”

The Natural Resources Defense Council supported the CPUC’s decision, saying it “marks the nation’s single largest investment by the electric industry to eat away at Big Oil’s longtime monopoly over transportation fuels.”

Each IOU had its own package approved by the commission.

San Diego Gas & Electric: A $137 million rebate program for 60,000 Level 2 home-based charging stations, and an EV-only variable hourly energy rate.
Pacific Gas and Electric: $22 million for a “Direct Current Fast Charging Make-Ready Program” supporting 234 fast-charging stations at 52 sites. Also approved was make-ready infrastructure at a minimum of 700 sites to support the electrification of at least 6,500 medium- or heavy-duty vehicles.
Southern California Edison: $343 million to install the make-ready infrastructure at a minimum of 870 sites to support the electrification of at least 8,490 medium- or heavy-duty vehicles, and three new time-of-use rates for commercial customers with electric vehicles.

Make-ready infrastructure includes service connection and supply infrastructure to support EV charging. It is composed of the electrical infrastructure from the distribution circuit to the stub of the EV charging station and can include equipment on the utility side, such as a transformer, or on the customer side, such as electrical paneling or wiring of the meter, the CPUC said.

The commission modified some of the budgets and terms of the program. For example, it rejected SDG&E’s proposal to include existing EV customers in its program. TURN had argued that existing EV customers would be free riders, pointing to a survey that indicated 76% of California EV drivers have income of $100,000 or more. The commission included provisions for disadvantaged communities, setting rebates and adoption targets for EVs in those areas.

California’s Clean Energy and Pollution Reduction Act of 2015 set new greenhouse gas reduction goals and directed the CPUC to work with other agencies to advance the electrification of transportation.

The CPUC began the proceeding in July 2017 and conducted 11 days of hearings last fall. Other parties included environmental groups, the California Transit Association, Union of Concerned Scientists, EV infrastructure companies and consumer groups.

The decision came just after the California Energy Commission issued a report saying the state will need between 229,000 and 279,000 EV chargers at locations other than single-family homes by 2025 to meet the state’s goals for adoption of zero-emission vehicles. (See California to Require Sharp EV Charger Growth by 2025.)

June 1, 2018

AEP Wind Catcher Project Notches Regulatory Wins

By Tom Kleckner

American Electric Power’s massive Wind Catcher Energy Connection project in the Oklahoma Panhandle continues to rack up regulatory wins.

On Wednesday, independent transmission company GridLiance and Tri-County Electric Cooperative announced they have joined a settlement agreement with AEP related to the company’s proposed 2-GW, $4.5 billion project.

Meanwhile, a Texas administrative law judge has issued a proposed decision approving AEP’s application before the state’s Public Utility Commission. The PUC will take up the proceeding at its July 12 open meeting (Docket No. 47461).

Under the settlement’s terms, GridLiance subsidiary South Central MCN will have the option to construct, own and operate any additional Wind Catcher interconnections in Tri-County’s panhandle service territory of Cimarron, Texas and Beaver counties. The agreement will also provide protections guaranteeing that AEP subsidiary Public Service Company of Oklahoma (PSO) will not provide retail service in Tri-County’s certified service territory for 25 years after the project begins commercial operation.

South Central and Tri-County, along with the Oklahoma Municipal Power Authority and Oneta Power, have now joined with Oklahoma Industrial Energy Consumers and Walmart in reaching settlement agreements with PSO on Wind Catcher.

wind catcher Gridliance Sri-County AEP — Tri-County Electric Co-Op’s Service Territory | *TCEC*

The parties are requesting that the Oklahoma Corporation Commission approve the terms of the agreements. PSO said the terms “collectively result in significant customer savings guarantees and increased use of natural gas power” generated in Oklahoma. (The recent agreements include a new power purchase agreement with Oneta for 300 MW of gas-fired energy and capacity beginning in 2022.)

Dallas-based GridLiance said agreeing to the settlement will allow it to “adequately plan and operate its existing transmission system and future interconnections for the benefit of its utility partners.” Those partners included Tri-County, which will also retain the right to serve retail electric load in its service area.

The co-op’s CEO, Zac Perkins, said the right to serve retail load will last for the life of the Wind Catcher project.

“By partnering with GridLiance on this settlement, we were able to secure the rights to defend the service territory of our retail customers,” Perkins said.

Wind Catcher AEP GridLiance Tri-County — Crowder | © *RTO Insider*

GridLiance CEO Calvin Crowder said the company was pleased with the settlement.

“The panhandle’s economic development depends on a reliable local transmission system that serves multiple needs, and GridLiance remains committed to serving those needs now and in the future,” he said.

GridLiance, which focuses on collaborating with public power entities, entered into an agreement with Tri-County in 2015 to plan, construct and operate transmission infrastructure projects in the panhandle. (See GridLiance Makes First Acquisitions.)

PSO CEO Stuart Solomon said in a release that the agreements further demonstrate that Wind Catcher is good for customers.

“The agreements guarantee customers will save money and allow us to move forward with our plan to increase use of Oklahoma-based renewable energy and natural gas generation to provide affordable, reliable service to our customers,” he said.

PSO is seeking regulatory preapproval to recover $1.36 billion in project costs. It has proposed to the OCC that it cap project costs at 103%, and it has guaranteed the project would qualify for 100% of federal production tax credits available when Invenergy began construction in 2016.

Wind Catcher would consist of an Invenergy-developed wind farm containing 800 2.5-MW turbines. A 360-mile, 765-kV line from the panhandle to Tulsa will connect the wind farm to PSO’s grid and that of sister company Southwestern Electric Power Co., which owns 70% of the project.

AEP says Wind Catcher will result in $7 billion in energy savings for its utility customers in Arkansas, Louisiana, Oklahoma and Texas. The Arkansas Public Service Commission has already approved the project, but it still awaits regulatory OKs in the other three states.

SWEPCO has filed an application before the Texas PUC to amend its certificate of convenience and necessity and authorize its interest in Wind Catcher, and for preapproval of various ratemaking treatments to recover the project costs. The utility estimates its share of the costs at approximately $3.2 billion, with $1.1 billion within Texas retail jurisdiction.

In recommending the project’s approval, Texas ALJ Henry Card relied on the precedent set by the commission’s recent approval of Southwestern Public Service’s wind farm in West Texas. In that proceeding, the commissioners overcame their concerns that SPS was requesting 478 MW of energy when it already had sufficient capacity on its system to meet demand. (See Texas PUC Issues Final Order for SPS Wind Farm.)

“Utilities may obtain a CCN for general economic purposes not just when there is an increase in demand necessitating additional generation,” Card said in his decision.

June 1, 2018May 8, 2025

CAISO Hits Reset on Backstop Procurement Overhaul

By Jason Fordney

FOLSOM, Calif. — CAISO is going back to the drawing board to overhaul its reliability-must-run program, switching to a “holistic” approach after a more narrowly crafted backstop procurement proposal was rejected by FERC last month.

The ISO said it will combine into one process what was previously two separate phases of RMR rule changes. It hopes to develop its new proposal and complete a stakeholder process in time for presentation to its Board of Governors in March 2019.

“We’re not really talking about phases any more; this is really one big initiative,” CAISO Infrastructure and Regulatory Policy Manager Keith Johnson said during a stakeholder meeting Wednesday. Many stakeholders had previously urged CAISO to combine the two phases and tackle what are perceived to be wider problems with the RMR construct, but the ISO had favored a more incremental approach.

As out-of-market payments, RMRs have stirred controversy among ISO participants and prompted a larger debate about resource adequacy in California and whether current policies are appropriately incentivizing needed generation. Most recently, CAISO issued a May 15 market notice saying it will seek RMR designations for NRG Energy’s Ellwood and Ormond Beach units, which the company in March said it planned to retire. (See CAISO: New 2019 RMR Contracts Possible.) Environmental groups had cheered the news of the retirements.

FERC last month rejected CAISO’s proposal to make substantive changes to the separate but related Capacity Procurement Mechanism, which is similar to RMR in that it functions as a backstop to financially support needed generation. In its decision, the commission said the ISO needs to propose a more comprehensive package of reform for CPM. (See FERC Rejects CAISO CPM Proposal.)

The RMR program is used as a reliability tool when a generating unit wants to retire but is still needed for reliability. RMR participation is mandatory, and units receive payments based on their cost of service, while those units designated under the CPM participate on a voluntary basis and receive a capped market-based price. The ISO said it is not currently planning to merge the two processes.

Among the items being considered in the newly crafted RMR reform package are:

Modifying compensation for both RMR and CPM;
Subjecting RMR units to a must-offer requirement in the wholesale market;
Providing flexible RA credits from RMR units; and
Modifying cost allocation of CPM to reflect load migration.

Other goals include lowering banking costs for RMR invoicing, streamlining and automating the RMR settlement process and making interim changes to the pro forma RMR agreement.

Whatever backstop procurement the ISO develops will have to conform to — and interact with — a package of RA reforms being developed by the California Public Utilities Commission. At the CPUC, the ISO is advocating enhancements to flexible RA capacity procurement requirements, establishing multiyear RA procurement and vetting appropriate load forecasting assumptions.

“The ISO does think the RA program could be refreshed,” Johnson said.

CAISO has said it is likely the RMR reforms will need to go to settlement. During Wednesday’s meeting, stakeholders discussed how to negotiate the terms of an agreement without having to go through a settlement process at FERC after the proposal is filed.

Mark Smith, vice president of government and regulatory affairs at Calpine, called for an increase in the scope of proceeding to include revising the RMR pro forma agreement, modifying transmission planning to prevent backstop procurement and other reforms.

“We have a difference of opinion from the ISO as to what defines holistic,” Smith said during a presentation.

Eric Little, manager of wholesale markets at Southern California Edison, said that RMR and CPM have become replacements for resources normally provided by RA. He also mentioned a must-offer requirement for RMR/CPM resources and said they should receive cost-based contracts plus a reasonable return.

“In addition, the compensation method that was once a trade-off of competitive market for capacity augmented by energy market rents will need to be made equivalent under a contract mechanism with the CAISO,” Little said during a presentation.

The ISO is also working on increasing transparency around retirements, saying it will drop confidentiality provisions around notices of retirement or mothballing of units to ensure market participants are aware. That change, which will only require a revision to the ISO’s generator management business practices manual rather than approval by the board, is due to be implemented by July 1.

CAISO plans to issue a new RMR straw proposal by June 26, with another stakeholder meeting July 11 to discuss the many complex issues around what will be a major change in its procurement policies.

June 1, 2018

FERC Examining Cleco Plant SSR Compensation

By Amanda Durish Cook

FERC on Tuesday opened an investigation to determine whether the cost recovery for a Cleco Power gas-fired plant that serves as a MISO system support resource unit in southern Louisiana is justifiable.

The commission accepted and suspended a Cleco rate schedule that allots a fixed monthly payment of $1.7 million for the continued operation of the 338-MW Teche Power Station Unit 3, and directed its chief administrative law judge to decide whether to initiate a hearing over the matter (ER18-1237).

MISO first won approval for the plant to operate under an SSR in mid-2017 after Cleco signaled that it intended to retire the unit. (See MISO Wins OK for Cleco Plant SSR.) At the time, the RTO said the Teche plant was needed to prevent severe thermal violations on its transmission system that could not be addressed until the Terrebonne-Bayou Vista 230-kV line could be put into service this year. Entergy now expects the line to be placed into service in early 2019.

Cleco Power Cost Recovery SSR MISO FERC — Cleco’s Teche Power Station in Baldwin, LA | *Google*

In May, FERC granted MISO approval to renew the SSR agreement through March 31, 2019. The agreement provides for both hourly compensation of the plant and the fixed monthly charge, which Cleco says covers costs not included in hourly compensation and fully reimburses it for the costs of operating and maintaining the unit. Cleco had already included the associated $1.7 million in monthly payments in its rate schedule filed with FERC in March.

Entergy protested the rate schedule, saying Cleco failed “to provide enough information to establish that the proposed monthly payments are just and reasonable.” Entergy contended that Cleco’s filing failed to contain “many of the details” required by FERC regulations to allow the commission and interested parties to assess the validity of the costs associated with the agreement.

Cleco has contended that the compensation for its second SSR agreement “is just and reasonable and is no more than necessary to maintain the availability of Teche 3.”

Entergy also contested Cleco’s request for a waiver of the 60-day notice requirement, which would allow the proposed rate schedule to become effective April 1. In its Tuesday ruling setting the Teche matter for hearing, the commission rejected Entergy’s argument, saying its previous rulings have held that nothing in the SSR program would require a generator to shoulder uncompensated costs.

“Here, the record indicates that Teche 3 has been providing reliability service pursuant to the second SSR agreement since April 1, 2017,” the commission said. “Thus, it is appropriate that Cleco be made whole for the costs that it incurs while providing SSR service.”

June 1, 2018

MISO, PJM Seek Incremental ARR Coordination

By Amanda Durish Cook

MISO and PJM plan to unveil rule changes late this summer that will better synchronize how they manage incremental auction revenue rights (IARRs) along their seam.

Speaking during a May 30 Joint and Common Market meeting, PJM Senior Market Simulation Analyst Brian Chmielewski said the RTOs are working to clarify and improve their current IARR coordination process, particularly where it concerns PJM’s customer-funded options.

Both RTOs offer IARRs, which represent additional auction revenue rights created by transmission upgrades that increase capability on their transmission facilities. IARR megawatts are awarded for the additional capability created for the life of the upgrade or 30 years, whichever is less, and valued each year based on annual financial transmission rights auction clearing prices.

However, PJM’s process provides an additional option that allows a specified IARR to be awarded when a customer agrees to fund transmission upgrades necessary to support the new ARR request.

MISO and PJM coordinate studies of IARR requests when there is a potential impact on flowgates operated by either RTO, but they say there are gaps in the current process designed to coordinate IARRs between them.

Chmielewski said the RTOs need to ensure they are properly transferring firm flow entitlements on the impacted flowgates of an IARR to make sure FTR revenue remains adequate. Because PJM is also obligated to guarantee at least 80% of IARR megawatts, the RTO may have to require “some guarantee” from MISO on future firm flow entitlement allocations, Chmielewski said.

Chmielewski also said all of PJM’s capabilities from upgrades might not be reflected in firm flow entitlement allocation between the two RTOs, and that current, non-active flowgates that could be activated in the future may impact the viability of IARRs.

The RTOs said they’ve met for several discussions on the issue since November and will present proposed revisions at the Aug. 29 JCM meeting.

Chmielewski said MISO and PJM could unveil joint operating agreement revisions by November, with a new process rolled out in the first quarter of 2019.