Page 1466 – RTO Insider

October 24, 2017

RTOs Reject NOPR; Say Fuel Risks Exaggerated

By Michael Kuser, Tom Kleckner, Rory D. Sweeney, Amanda Durish Cook

RTO officials and their Market Monitors on Monday unilaterally rejected Energy Secretary Rick Perry’s proposal to provide price supports to coal and nuclear plants, calling it expensive, inefficient and counterproductive.

The ISO/RTO Council (IRC) led the opposition, with CAISO, PJM, MISO, ISO-NE and NYISO also filing comments in opposition. Also filing statements opposing the proposal were PJM Market Monitor Joe Bowring; David Patton, Market Monitor for MISO, NYISO and ISO-NE; and Keith Collins, head of SPP’s Market Monitoring Unit.

In a joint filing supporting the rule, the American Coalition for Clean Coal Electricity (ACCCE) and the National Mining Association criticized the RTOs for failing to address trends threatening coal and nuclear generators. (See related story, FERC Flooded with Comments on DOE NOPR.)

They said NERC’s and RTOs’ “confidence in the current state of electric reliability … are based, in large measure, on existing conditions and short-term forecasts, largely ignoring the trend toward premature retirements of baseload coal-fired generating capacity currently available to address reliability and resiliency needs.”

market monitor coal nuclear NOPR FERC ISO-NE — | © *ISO-NE*

The coal groups acknowledged that some RTOs “have tried to explore measures intended to maintain traditional baseload capacity in the market, and have even taken some halting and less-than-full steps in that direction, a tacit recognition that existing market rules and structures are not properly valuing the reliability, resiliency and long-term price stability benefits that traditional baseload capacity provides.”

But it said “the few revisions to existing RTO/ISO tariffs and related market structures and rules have so far been much too little and far too late. Without action by the commission to remedy these tariffs and market structures, the electric system will devolve to lose the value of fuel diversity and end up overwhelmingly dependent on intermittent renewable and natural gas generation.”

Rebuttal

Patton recommended FERC define the contingencies the Department of Energy seeks to address. “Without first identifying in detail the contingencies and associated reliability risks to the system, there is no way to quantify a resilience requirement,” he said.

He said MISO and ISO-NE have already conducted fuel-security studies.

“MISO’s evaluations of the adequacy of the gas pipeline infrastructure found the MISO North and Central regions to be ‘favorably located at the crossroads of pipeline corridors extending from many supply basins … with more than 20 interstate pipelines and significant gas storage resources.’ Hence, MISO’s potential exposure to natural gas supply contingencies is relatively low, and the need for the payments called for under the [Notice of Proposed Rulemaking] is similarly low.”

Patton acknowledged New York and New England are more vulnerable to natural gas system contingencies than MISO. But, he said, “it is highly unlikely that the proposal in the NOPR is a feasible or reasonable means to address these vulnerabilities,” saying dual-fuel capability “has been the most effective and cost-effective means” to address them.

“This illustrates the problems that arise when one starts with a very specific answer, rather than starting with a clearly defined issue or objective and allowing the markets to provide the most efficient answer,” he said.

ISO-NE

ISO-NE found fault with what it called the NOPR’s “one-size-fits-all” approach to the region’s risks and said its stakeholder processes were preferable to the NOPR to “develop market-based solutions, if any are needed.”

“The NOPR does not address these risks, and ISO-NE proposes to instead use the time the region has in 2018 and beyond to quantify its fuel-security risks,” the RTO said.

The grid operator said the NOPR would “significantly undermine the efficient and effective wholesale electricity markets,” and that moreover, “New England has no urgent need to rush to a solution, given that the three-year Forward Capacity Market has ensured resource adequacy until at least 2021, and the region has already taken steps to improve operating procedures and generator incentives to secure firm fuel supplies.”

Commenting on the proposed rule’s estimated burden of $291,042 per respondent RTO/ISO to develop and implement new market rules as proposed, including potential software upgrades, ISO-NE said such efforts would “be in the millions of dollars for each RTO.”

The NOPR would undermine New England’s wholesale electricity markets in two ways, the RTO said: “First, these resources may have no incentive to bid their appropriate fuel and operating costs in the energy market … [and] could profitably bid zero. While there are admittedly few coal resources remaining in the region, if these costly units bid zero, it will undermine price formation in the day-ahead and real-time energy market and increase emissions.”

Second, the RTO said, its FCM enables resources to offer to retire if the market does not clear at or above a specific price: “Normally, as units age and their costs rise, new resources will be more economic than retaining aging units that require a higher price. With full cost recovery guaranteed, however, these aging resources will remain, deterring the development of newer, more efficient and more cost-effective generating units.”

ISO-NE also said it has developed new operating procedures to improve information on generator availability during cold weather conditions, such as requiring generators to report their anticipated availability to the grid, including details on their ability to procure fuel.

The RTO said it also has increased market-side efficiency and improved gas-electric coordination to mitigate the supply problems arising from natural gas pipeline constraints.

“For example, the ISO has shifted the day-ahead energy market timeline to better align the electricity and natural gas markets to give generators more time to procure the gas they need to run,” it said.

NYISO

NYISO asked FERC not to adopt the proposal but said if it deemed action necessary, it should give the RTOs at least 180 days from the effective date of any final rule to submit compliance filings.

“[The] deadlines are simply not realistic and attempting to impose them would not be reasoned decision-making,” the ISO said. “The NOPR’s approach would distort, if not destroy, wholesale market signals needed to attract and retain resources required for reliability.”

The ISO called the proposed grid resiliency pricing rule “flawed” for being premised on inaccurate assumptions and statements as they relate to New York.

“The NOPR does not establish that its proposal is appropriate or that ‘grid resiliency’ issues should be addressed the same way in different regions,” said the filing, adding that the grid operator “is not aware of any imminent emergency likely to develop on the wholesale electric system that necessitates drastic and immediate action.”

All resource adequacy criteria have been satisfied in New York and are expected to continue to be satisfied for the foreseeable future, said the ISO. For example, on Jan. 7, 2014, New York set a new record winter peak load of 25,738 MW during the polar vortex, and “NYISO met all reliability criteria and reserves requirements without activating emergency procedures at any time during the winter operating period. It did so despite significant generator capacity derates on some of the coldest days, including generation resources that would appear to qualify under the NOPR as ‘eligible grid and reliability resources.’”

The ISO said it has made improvements to its energy and ancillary service markets and incorporated features into its capacity market rules “that reflect the importance of resiliency to withstand severe weather events,” including basing the downstate installed capacity demand curves on peaking plant designs that include dual-fuel capability.

PJM

PJM agrees there is an issue with maintaining reliability, but not the one suggested by the department.

“The DOE didn’t exactly get it right in the way it attempted to articulate the problem,” Stu Bresler, PJM senior vice president of operations and markets, said Thursday.

During a special conference call to preview the RTO’s plan for responding to FERC’s request for comments on the NOPR, Bresler said that the real issue is energy price formation. PJM has been working on that topic for more than a year to respond to concerns over public-policy initiatives impacting market prices.

CEO Andy Ott made similar observations during a media call on Monday, calling it “a tall order” to implement the proposal “and then expect the competitive market to continue to function effectively.”

“The DOE proposal, which essentially is the cost-of-service type of mechanism, we don’t believe is workable. We don’t believe that that is an appropriate response,” Ott said. “We believe [it] is contrary to law and will not really solve any problems. … A better and least-cost solution would be to do proper valuation of resource attributes through a market construct.”

Ott said the proposal is discriminatory because it is exclusive to certain technologies, rather than the service provided to the grid, and only in RTOs with capacity markets — such as PJM.

“PJM does have an abundance of coal and nuclear plants that are in the merchant category, so … it does look like this is certainly targeted at the PJM region,” he said. “We do say that in our comments that this proposal does seem to be focused on this region.”

Bresler said that the NOPR — which cited natural disasters and the 2014 polar vortex to argue that units with large on-site fuel stockpiles should be subsidized to save them from retirement — misses the mark. (See FERC’s Independence to be Tested by DOE NOPR.)

“The point is that just maintaining a whole lot of resources with a 90-day fuel supply on site would not have relieved the problems with a majority of the outages during the polar vortex,” Bresler said. “While the polar vortex did highlight the need for the markets to ensure that we are signaling the need for resources to be able to operate on peak days, just resources with long-term fuel supplies on site was not the majority of the issue.”

During natural disasters, Bresler said, the main challenge is downed power lines, not generating plants being unable to run.

“Events like that … primarily affect the delivery system from supply to demand, not the supply resources themselves,” he said, noting that some coal plants impacted by Hurricane Harvey this summer weren’t able to run at full capacity because their coal piles were soaked.

“In the interest of framing the right problem, we will point out these things that we feel sort of led DOE down the wrong path as far as what the actual problem is,” he said. “We will say, however, that there is an issue that we do need to address, specifically to the PJM region. And that is the fact that there are some instances in PJM where not all resources are valued appropriately for the fact that they are relied upon to reliably meet the demand. … We are concerned that resources right now may not be offering as much flexibility as they could provide because they don’t have incentive to do it.”

Using competitive markets to “transparently” price needs is “superior” to providing cost-of-service payments to certain unit types, he said.

“One concern we have with the DOE approach is it seems to imply that while we may need to keep some of these resources around to ensure reliability and resilience, so therefore let’s keep them all,” Bresler explained. “That again is, from our standpoint, inefficient from the standpoint of the cost to load. Whereas the markets, we believe, have done a very good job to provide the discipline for what really is necessary and what’s not necessary and thereby not just provide efficient signals for entry, but also provide efficient signals for exit.”

PJM’s comments to FERC included a version of a proposal staff presented at its August meeting of the Markets and Reliability Committee. Bresler said the proposal will be revised and presented again at the Dec. 7 MRC meeting.

Ott acknowledged that PJM’s comments don’t reflect the perspectives of all its members.

“There really was no full vetting of these comments with stakeholders,” he said. “One, there isn’t sufficient time, and second is … PJM’s comments are PJM’s and we do not vet those through stakeholders.”

In his comments to FERC, Monitor Bowring said approving the DOE proposal “would replace regulation through competition with an unworkable hybrid of competitive markets and cost of service regulation. The eventual result would be the demise of competitive markets in the PJM region.”

“If the reliability rules need enhancement,” he continued, “the reliability rules should be enhanced. The DOE proposal should be rejected. The PJM region needs more competition, not less.”

MISO

MISO’s comments urged FERC not to adopt the proposal, saying it fails to identify imminent reliability or resilience issues, and said its footprint currently doesn’t have any such issues that would warrant immediate action “beyond the application of ongoing processes and existing tools that address resource availability and retirement in the MISO region.” [Editor’s Note: An earlier version of this article incorrectly reported that MISO did not file its own response.]

“Instead of proceeding in haste with material changes that could have broad-ranging and potentially adverse impacts, MISO urges the commission to move at a deliberate pace, to work through its existing dockets and to leverage its established processes to initiate a full, thorough and public vetting of the issues raised by the proposal,” the RTO wrote.

The RTO told stakeholders earlier this month that they would insist FERC respect the RTO’s existing reliability process, and would study frequency control, ramping, voltage support, inertia and inertial response to identify the features of a “resilient” generator. (See MISO Ready to Define, Study ‘Resiliency’ for DOE.)

SPP

SPP told stakeholders Thursday it would will join the IRC filing, pointing to what staff called “some pretty strong comments.”

“The council does a really good job of laying out why this doesn’t work from an RTO perspective,” SPP General Counsel Paul Suskie told the Strategic Planning Committee.

“If you’re a plant under the rule, your costs are totally covered,” Suskie said. “Why would you do anything but bid zero into the market? It will drive costs down further and distort markets further.”

Some stakeholders expressed discomfort with signing onto the IRC comments without seeing the language.

“The basic issue here is the subsidy,” countered SPP Board Chair Jim Eckelberger, saying renewable energy tax credits had led to oversupply. “We don’t want to screw up the market even more. We should take a strong stand here.”

In its call for comments, FERC said the NOPR’s scope applies to commission-approved ISOs and RTOs with capacity markets and day-ahead and real-time energy markets. Noting SPP’s lack of a capacity market, Suskie said while it “appears this rule is not applicable to SPP,” staff will work under the assumption that a final FERC rule could apply to the RTO.

Suskie said the proposed timeline for action is “impractical.”

“Staff would recommend additional time to implement if the final rule applies to SPP,” Suskie said, noting staff would have to compile a list of eligible facilities. “Staff is very concerned. … If you read what the intent appears to be, basically any coal or nuclear plant not [rate-based] within an RTO would have to be fully compensated.”

Suskie asked who would determine a plant’s rate of return and cost of capital.

“Traditionally, those things are decided at the commissions, not RTOs,” he said. “How do you enforce a 90-day coal supply? How do you enforce whether a plant complies with environmental regulations?

“If this is applicable to SPP, it would be a big sea change,” Suskie said.

Keith Collins, executive director of SPP’s MMU, said his group agrees with much of what Suskie said, saying the NOPR is “proposing a solution to a problem that’s not well defined.”

The NOPR “doesn’t define the problem well in a way that’s actionable and measurable,” Collins said. “When you actually read the [recent DOE grid study], it says more work needs to be done to value and define resiliency before you come up with solutions. What’s included, what’s excluded … it’s hard to say.”

Like Suskie, Collins said the 90-day timeline does not allow sufficient time to properly consider the NOPR.

“If there’s a question to be raised, it can be answered over time, but we don’t support what’s going on,” he said. “Competitive forces have been part of policy in the energy and electricity markets over the last 25 years. It will provide new technologies, batteries and the like, that will improve the resiliency for the grid in ways we’re not aware of today.

“What the Energy Policy Act of 1992 did was promote competitive markets and open access,” Collins said. “If someone can provide power cheaper than someone else, they should be able to do that. If I built a plant a while ago that’s unprofitable, that’s a signal. Resources are indicating they are not being able to recover their costs. We see the consequences of a policy like this with our negative pricing.”

In his filing, Collins said “the SPP markets provide insight into the adverse consequences of policies designed to preserve capacity that would otherwise be uneconomic in typical ISO/RTO markets.

“The SPP market, which is dominated by vertically integrated utilities, provides an example of the potential difficulties that will be faced if the Proposed Rule is implemented,” he wrote. “The SPP market has a considerably high capacity margin, currently trending above 40% compared to the 12% minimum requirement in the SPP Tariff. The excess capacity distorts price formation in the competitive market by encouraging price insensitive offer/bid behavior and mutes price signals for others type of generating technologies.”

CAISO

CAISO said the rule would not apply to it because it does not have a capacity market or coal or nuclear resources that would be eligible for the proposed compensation. But it opposed the rule nonetheless, saying “there is no basis for a universal finding that having a 90-day, on-site fuel supply is essential for ISOs and RTOs to maintain grid reliability or resilience.”

Rich Heidorn Jr. contributed to this article.

October 23, 2017

New York PSC Adopts DER Rules, Sanctions ESCOs

By Michael Kuser

The New York Public Service Commission on Thursday enacted consumer protection standards for distributed energy resource suppliers.

The PSC’s order also created a manual of uniform business practices, the first rule of which stipulates that “a DER supplier shall obtain a customer’s consent to a sales agreement prior to billing a customer or enrolling a customer” in any program.

NYPSC DER distributed energy resources ESCO ESCOs — Kelly | *NY DPS*

At the commission’s monthly meeting in Albany on Thursday, Ted Kelly, assistant counsel for the state’s Department of Public Safety, testified that “as DERs become an increasingly common and significant part of electric and gas service to customers, [the commission] has both the authority and the responsibility to ensure that customers participating in DER markets and programs understand the costs and benefits of their investments and are protected from confusion, fraud and abusive marketing.” (See Comprehensive DER Oversight Best, NYDPS Hears.)

DERs take a broad range of forms, Kelly said, “from rooftop solar panels to smart thermostats, to energy-efficient and demand-responsive industrial equipment, to bio-digesters making energy from farm waste, to community-scale distributed generation projects.”

The order requires residential customers be able to cancel a contract within three business days after its receipt without charge or penalty, and that the contract include essential information about pricing, cancellation rules, tax incentives, and details of the product or service provided.

PSC Chair John Rhodes said the order “provides a thoughtful and protective balance for New Yorkers and the timing is right. We are facing important and welcome growth in these resources, and we need to be in a position to provide protection for customers against untoward practices while pragmatically not burdening developers. I also find the initial focus on [community distributed generation] and mass market [distributed generation] makes all the sense in the world.”

Penalties for a violation of the rules can range from a warning up to a ban from participation in any programs or markets authorized by the commission.

Reining in ESCOs

The PSC also said Brooklyn-based energy service company (ESCO) MPower Energy could be barred from operating in New York following more than 100 customer allegations of deceptive sales and marketing practices.

After investigating complaints dating back to 2015, the commission said MPower must justify within 30 days why it should be allowed to continue operating in the state. The PSC also gave the firm seven days to show why it should be permitted to serve low-income customers, whom the commission said are frequently the victims of aggressive and misleading sales practices by ESCOs. (See NYPSC Limits ESCO Service, Sets New DER Compensation.)

The commission also determined that three ESCOs — Just Energy NY, National Fuel Resources and Zone One Energy — can continue serving low-income customers, while it denied waiver requests for four others: Agway Energy Services, Stream Energy, South Bay Energy and New Wave Energy.

The PSC in December 2016 banned most ESCOs from serving low-income customers but said it would consider waivers for any company that promised to offer bill savings or that could guarantee benefits to those customers. A state court earlier this year issued a temporary restraining order on the ESCO ban, which has been since lifted. (See Court Blocks NYPSC Order Barring ESCO Contracts.)

‘Yes’ to Community Choice Aggregation

The PSC approved the nonprofit Municipal Electric and Gas Alliance (MEGA) to implement a community choice aggregation (CCA) program for several Upstate New York municipalities.

Under the order, additional municipalities will be allowed to form such programs in the future, which “enable communities to take greater control of their energy choices through a transparent and competitive process driven by the consumers themselves,” Rhodes said.

Commissioner Diane Burman asked whether CCAs were subject to the just-issued rules for DER. Kelly said they would be if they included a DER component.

Utilities Prepped for Winter

The state’s major energy utilities expect to have adequate fuel supplies on hand for the coming winter, the commission heard.

“Each utility has a unique mix of assets to serve a unique mix of customers,” said Cynthia McCarran, PSC deputy director for natural gas and water. In her winter preparedness report, McCarran highlighted the efforts by some utilities, notably Consolidated Edison and New York State Electric and Gas, to focus on using demand response programs and so-called “non-pipes alternatives” to meet growing space and water heating needs.

“We anticipate energy consumers will benefit from adequate capacity and supply if we see a harsher-than-expected season,” Rhodes said.

The report said that natural gas bills in general are projected to be slightly higher this winter than historical averages and compared to last winter, which was warmer than normal. On the electric side, this winter’s commodity prices statewide are projected to be slightly higher than last winter, but significantly lower than the historical average.

Commission staff reported that major dual-fuel generation owners are continuing to follow the lessons learned from the harsh 2013-14 winter, including topping off fuel oil storage tanks ahead of the season, making firm arrangements for fuel oil replenishment, and ensuring that plant equipment has been prepared for winter operations.

“The electric utilities have continued to perform well in reducing the electric supply price volatility of their full service residential customers,” McCarran said. “The utilities have hedged approximately 70% of their estimated statewide full service residential energy needs to protect against unexpected electric market price swings that could occur this winter.”

October 23, 2017

FERC Sees Discrepancies in MISO GIA Rules

By Amanda Durish Cook

FERC last week opened a Section 206 investigation into inconsistencies in MISO’s Tariff after re-examining the 2016 termination of a North Dakota wind farm’s generator interconnection agreement (GIA).

MISO FERC GIAs Section 206 — | *EDF Renewables*

The commission on Thursday said MISO’s rules may not be just and reasonable because of discrepancies between the generator interconnection procedures outlined in the RTO’s Tariff and its pro forma GIA. It required MISO and interested parties to file briefs for a paper hearing (EL17-18). FERC expects to render a final decision in June and issued an Oct. 19 refund date.

The commission’s concern centers on a pre-2012 provision in the generator interconnection procedures that allowed an interconnection customer to extend its commercial operation date by up to three years without losing its position in the interconnection queue if MISO found that the extension would not adversely impact lower-queued customers. The provision was narrowed in 2012 so that once entering the definitive planning phase, MISO only allowed the three-year extension if it was caused by a change in milestones by another party to the GIA or a change in a higher-queued interconnection request.

MISO added a third provision for study delays in 2016. At the time, FERC said, “MISO’s proposal to limit the types of changes permissible in the definitive planning phase is consistent with the need to ensure that a project that enters the definitive planning phase is ‘definitive.’”

However, MISO’s GIA was never edited to add the three conditions for a three-year extension and “effectively provides interconnection customers an ability to extend their [commercial operation date] by three years before MISO can seek to terminate a GIA,” according to the commission.

FERC pointed out that MISO has cited the three-year limit in its generator interconnection procedures when terminating GIAs and said the RTO’s latitude to terminate GIAs is “permissive in nature.” The commission also said MISO’s outright termination of GIAs based on the three-year condition ignores its material modification analysis process, which is triggered when an interconnection project experiences changes that affect cost or in-service timing.

FERC said MISO’s interconnection procedures should be revised to reference its GIA and “allow that once a GIA is executed or filed unexecuted, a three-year period from the [commercial operation date] should lapse before MISO seeks to terminate the GIA.”

The issue was initially raised by EDF Renewables subsidiary and wind developer Merricourt Power Partners, which contested FERC’s acceptance of a MISO notice of termination of a GIA entered into by enXco Development and subsequently assigned to Merricourt. (See FERC Upholds MISO Cancellation of GIA.) At that point, the 75-turbine, 150-MW Merricourt wind project in North Dakota had missed its Dec. 1, 2012, commercial operation date by more than three years.

In seeking rehearing of the decision, Merricourt had argued that the commission erred by relying on MISO’s generator interconnection procedures alone and not considering language in the GIA.

FERC ultimately denied Merricourt’s request for rehearing of the termination, saying that MISO’s generator interconnection procedures don’t allow the three-year-plus commercial operation date extension the company sought, even considering “factors beyond the plain language” (ER16-471-001). The commission also said that it could not consider MISO’s study delay provision for Merricourt because it wasn’t yet active at the time the company missed its operating date.

FERC Commissioner Cheryl LaFleur issued a concurring statement, saying the investigation would provide “needed clarity to MISO and interconnection customers regarding their respective obligations going forward.” LaFleur was the sole dissent in FERC’s first decision to cancel the GIA, saying it could create barriers for other wind projects.

“I concur in the decision to deny Merricourt’s requested relief at this time. While I would have granted that relief in March 2016, it is now over a year and a half later, past even the Sept. 30, 2017, [commercial operation date] extension date sought by Merricourt. I do not see a basis to grant rehearing at this point,” LaFleur said.

EDF is still working to secure permitting from the North Dakota Public Service Commission for the project.

October 23, 2017

$23 Million Owed to Ratepayers in Presque Isle SSR Case

By Amanda Durish Cook

FERC ruled Thursday that Wisconsin Electric Power Co. overcharged ratepayers on Michigan’s Upper Peninsula by almost $23 million under MISO-ordered system support resource agreements.

The commission largely agreed with an administrative law judge’s initial decision on refunds under two SSR agreements that kept the 344-MW Presque Isle coal plant in Marquette, Mich., running in 2014 and early 2015 for reliability (ER14-1242-006, et al.).

FERC SSR Presque Isle Michigan Lower Peninsula — Presque Isle power plant | *WEPCo*

Judge Michael Haubner issued an initial decision in July, saying WEPCo had overcharged ratepayers over the SSR agreements. (See Upper Peninsula Ratepayers to Seek FERC Probe of Billing Fraud.)

WEPCo had argued that the commission should accept its simple three-year average of historical costs from 2011 to 2013 as basis for compensation in the SSR agreements, but FERC took the judge’s view, agreeing that SSR compensation should be limited to actual costs. FERC said the plant’s compensation “must be limited to Wisconsin Electric’s going-forward costs, and the record shows that the negotiated amount was not shown to be a reasonable estimate of Wisconsin Electric’s going-forward costs. In fact, the negotiated amount greatly exceeded Wisconsin Electric’s actual going-forward costs.” The commission also rejected the company’s portrayal of the order as “retroactively implementing a new standard for SSR compensation without providing fair notice.”

Under MISO’s first SSR agreement (Feb. 1 through Oct. 14, 2014), WEPCo collected almost $37 million in fixed-cost compensation, but FERC said the utility should have only gotten about $23 million, resulting in a refund of about $14 million.

FERC said ratepayers were due an $8.6 million refund from MISO’s second SSR agreement (Oct. 15, 2014, through Jan. 31, 2015) because the agreement contained an excessive cost of capital and ineligible capital expenditures. FERC agreed with Haubner’s view that MISO didn’t adequately support its proposed 11.5% long-term cost of capital during the second SSR, saying 9.68% was more appropriate.

The refunds include a $2.4 million charge collected under the first SSR agreement to overhaul a generator turbine. FERC ruled the charge must be refunded to avoid WEPCo taking advantage of upgrade costs and then planning a return to service.

FERC gave MISO 45 days to make a refund report, brushing aside the RTO’s complaints that Haubner’s initial order did not provide clear guidance on how to calculate refunds.

The commission also agreed with the judge that WEPCo must refund a $1.4 million consulting services invoice relating to upgrades to bring the 61-year-old coal plant into compliance with EPA’s Mercury and Air Toxics Standards. But it stopped short of determining whether changed dates on the invoices constituted fraud.

Last year, Cloverland Electric Cooperative accused WEPCo of backdating the consulting contract after the plant operator learned that the second version of its SSR agreement would cover costs incurred from MATS upgrades under a revised fixed-cost component. MATS upgrades were ineligible for recovery under the previous SSR agreement.

“We make no findings at this time regarding whether Wisconsin Electric committed fraud or engaged in manipulation when a date was changed on an invoice for MATS compliance related costs, but we have referred the matter to the commission’s Office of Enforcement for further examination and inquiry as may be appropriate,” FERC said.

October 23, 2017

ERCOT OKs Plant Retirement; TAC Meeting Canceled

ERCOT’s Technical Advisory Committee has canceled its Oct. 26 meeting because of a limited number of items for consideration. The TAC will instead hold a one-hour web information session Monday to prepare for an email vote on the load distribution factor (LDF) library.

Staff will discuss the methodology behind generating and maintaining LDFs used in the congestion revenue rights (CRRs) and day-ahead market clearing activities. LDFs are developed using historical state estimator or supervisory control and data acquisition (SCADA).

ERCOT protocols require the ISO to maintain the appropriate LDF libraries for use in the day-ahead and CRR auctions. Staff updates the libraries by maintaining the existing LDF sets and generating new LDF sets when required, based on significant changes in systemwide load patterns.

TAC Vice Chair Bob Helton has yet to set a date for the email vote.

ERCOT Approves Barney Davis Gas Unit’s Retirement

ERCOT on Thursday approved the retirement of a 330-MW gas unit at the Barney Davis plant near Corpus Christi, saying it is not needed to support system reliability and can now be decommissioned.

ERCOT TAC technical advisory committee — Barney Davis Power Plant | *Terry Ross/Flikr*

Talen Energy announced on Sept. 27 its intention to retire the unit, triggering ERCOT’s reliability review. The unit went into service in 1974.

—Tom Kleckner

October 23, 2017

FERC Again Rejects SPP Rules on ARRs, LTCRs

By Rich Heidorn Jr.

FERC on Thursday again ordered SPP to rewrite its rules on auction revenue rights (ARRs) and long-term congestion rights (LTCRs), saying the RTO’s proposed grandfathering provisions would “inappropriately extend practices that the commission finds unjust and unreasonable” (ER17-1575).

SPP FERC ARRs auction revenue rights — Inside SPP’s control room | *SPP*

In a related order, the commission also rejected SPP’s proposal to provide ARRs and LTCRs to network service customers subject to redispatch on the same basis it provides them to customers not subject to redispatch (EL16-110). The commission ordered SPP to revise its Tariff to apply to network service customers subject to redispatch the same limitation on ARR and LTCR eligibility that the RTO currently applies to point-to-point service customers subject to redispatch.

SPP had drafted the Tariff language after the commission ordered a Section 206 inquiry in September 2016 in response to complaints by Southern Co., the American Wind Energy Association and the Wind Coalition. (See SPP Hopes Congestion Rights Rule Change Wins FERC OK.)

In Thursday’s orders, FERC approved SPP’s proposal to grandfather ARRs and LTCRs that have already been granted to network customers with service subject to redispatch. But the commission said it was not reasonable to extend the grandfathering provisions through July 15, 2017, as SPP had proposed as a transition to new ARR/LTCR eligibility rules.

SPP said it wanted to ensure that customers that contracted for network service subject to redispatch — service that is “confirmed” but has not commenced — remain eligible for ARRs for the full term of their service agreement.

The commission said that proposed revisions to section 34.6 of SPP’s Tariff were unjust and unreasonable because they would allow the RTO to provide ARRs and LTCRs to network service customers subject to redispatch while necessary transmission upgrades are constructed on the same basis it provides ARRs and LTCRs to firm transmission customers not subject to redispatch.

FERC said SPP must not allocate ARRs to customers with network service subject to redispatch on the same basis as firm transmission customers not subject to redispatch, “except for those times and amounts not subject to redispatch.” LTCRs also are barred for network customers subject to redispatch.

But the commission approved grandfathering ARRs and LTCRs already granted for network service subject to redispatch under the current language of section 34.6. “Allowing customers with network service subject to redispatch to retain their already-granted ARRs for the periods of time and the amounts of service subject to redispatch obligation and to retain their already-granted LTCRs, while preventing the future allocation of ARRs and LTCRs to such service on the same basis as firm transmission customers not subject to redispatch, appropriately balances the interests of network customers with service subject to redispatch who were granted ARRs and LTCRs based on SPP’s interpretation of its Tariff with the need to prevent ARRs and LTCRs from continuing to be awarded in an unjust and unreasonable and unduly discriminatory or preferential manner,” the commission said.

In related orders, FERC also:

Clarified that its Sept. 23, 2016, order did not prevent customers from seeking relief or address any retroactive relief (ER16-1286-002, EL16-110-001);
Rejected Southern Co. unit Alabama Power’s allegation that SPP violated its Tariff by treating customers with network service subject to redispatch as eligible to receive ARRs and LTCRs (EL17-11); and
Rejected a complaint by Buffalo Dunes Wind Project asking the commission to order SPP not to allocate new ARRs or LTCRs to network service customers subject to redispatch for the 2017-2018 allocation year (EL17-69).

October 23, 2017

SPP to Consider Tx Planning Policy for Energy-Only Resources

By Tom Kleckner

LITTLE ROCK, Ark. — SPP staff agreed last week to bring stakeholders a strawman proposal addressing concerns over the RTO’s transmission planning policy for energy-only resources.

Under current rules, capacity resources must go through transmission-service study (TSS) processes, while wind farms and other energy resources can bypass the TSS process and participate in the market, often creating transmission congestion. Stakeholders said the discrepancy creates uncertainty regarding future resource development as well as concerns over the fairness of cost allocation.

“It will take some time … to bring you something that will be a good strawman for you to start poking holes at,” COO Carl Monroe told the Strategic Planning Committee on Thursday, offering to deliver an update at its January meeting.

Staff will attempt to define the treatment of capacity and energy-only resources in the long-term planning process, taking into consideration reliability, public policy and economic concerns. It may also work to create incentives to generation-interconnection customers to proactively pursue upgrades needed to improve the deliverability of energy-only resources, and possibly develop a mechanism to treat all resources as firm capacity.

Antoine Lucas, SPP’s director of transmission planning, said things changed when tax incentives led to a rush of wind energy on the RTO’s system.

“Once the markets developed, we started running into blurred lines between what’s firm and what’s non-firm capacity,” he said. “It used to be black and white. If it’s a capacity resources, it was a firm service. You issued physical curtailments, with priority going to those firm resources. That’s not the most economical way to handle resources.”

Dogwood Energy’s Rob Janssen agreed with the need for a strategic vision, saying cost-allocation problems that have cropped up in recent years are “issues of [SPP’s] success.”

“We had a goal to build a robust transmission system, and we built it out to accommodate 12 to 15 GW of wind,” he said. “We made it work, but we haven’t stopped to re-evaluate our goals and needs now, and we’re seeing the cracks in the system. We need to step back and clearly identify our goals. How much more renewables do we need? Do we want to pay for those?”

SPC Chair Mike Wise, of Golden Spread Electric Cooperative, thanked the committee for the robust discussion, saying it was “pulling the scabs off several issues.”

“Little things can be dealt with here and there, but we need to keep the overall strategic picture in mind,” he said. “Let’s not just resolve this issue, but let it take us into the next world.”

October 23, 2017

CAISO Expands Attendee Roster for Stakeholder Symposium

By Jason Fordney

SACRAMENTO, Calif. — The rapidly changing energy landscape in the Western U.S. was the recurring theme at CAISO’s 2017 Stakeholder Symposium last week. About 1,000 attendees from the industry, its disruptors and other counterparts gathered at the Sacramento Convention Center.

caiso stakeholder symposium energy storage — CAISO for the first time held a panel with other industries. | © *RTO Insider*

This year, the ISO expanded the scope of the conference by inviting representatives from agriculture, Western oil and gas companies, and the commercial development industry to present fresh perspectives. The discussions revealed that policymakers, those responsible for grid reliability and large energy-using industries have accepted California’s legislative, regulatory and public commitment to renewables.

But there are many questions about what lies on the road ahead. California’s evolving mix of technologies and complex policymaking structure has placed much attention on a state that would boast the sixth largest economy in the world if it were an independent country.

A wide range of stakeholders, particularly those from neighboring states, are grappling with the questions of creating an RTO and a changing model for electricity delivery and consumption that is moving toward storage and distributed energy resources. Rising consumer costs and other impacts on the public were themes interwoven into the talks, and memories of the 2000-2001 Western Energy Crisis linger like ghosts among California policymakers.

Renewable Interests Discuss Storage

Participants on an Oct. 18 panel discussion of energy storage focused on the reliability and cost considerations of renewables and how energy storage can be used to better balance variable wind and solar output.

Storage is seen as the next wave in California energy development because of the large amount of photovoltaic and thermal solar coming online, panelists said. Concerns center on replacing the ramping ability of traditional generation, a role that would be suitable for responsive energy storage devices.

High-volume, bulk storage allows solar thermal plants to act like a traditional generating station, SolarReserve CEO Kevin Smith said. The California market is headed toward 50% renewables and beyond, but there are problems related to the “duck curve” and negative energy prices due to overgeneration. To reach the goal of reaching even 50% zero-carbon sources, “you are going to have to have thousands of megawatts of energy storage,” Smith said.

“Largely, renewable generation is going to have to go towards energy storage,” he said. Solar PV plus batteries can provide short-term ramping capability of up to an hour, but longer ramping capability will be needed to meet system needs.

First Solar CEO Mark Widmar said “Solar 1.0” was about attaining as much solar energy as possible, while “Solar 2.0” will be “incorporating flexibility and controllability.”

“Solar 3.0” will be about integration of storage. Other countries and states are looking to California to see how it is handling such a large influx of renewables, he said.

“Everyone is looking at California, particularly in the States,” Widmar said. “Everyone wants to know how California is going to create a sustainable market.”

The conversation around renewables often revolves around subsidies, but “maybe the market just needs to get the values right without overriding policies that skew that,” Ormat Technologies Executive Director Paul Thomsen said.

California utilities have procured a great volume of low-cost renewable compliance solar, “and now they are struggling with the best fit, and that is where we are today,” said Thomsen, a former member of the Nevada Public Utilities Commission. The market will provide the needed products, he said. “But we are not going to do it unless you give us a price signal.”

Other Sectors Weigh in

To bring new voices into the conversation, CAISO invited representatives from the New Buildings Institute (NBI), California Farm Bureau Federation (CFBF) and Western States Petroleum Association (WSPA) to discuss how they are managing the changing electric grid.

WSPA President Catherine Reheis-Boyd said that big changes are also happening rapidly in the petroleum industry: “It is not just the electricity industry; it is ours as well.”

Despite California’s moves to electrify the transportation sector, there are still 26 million internal combustion engines in the state, compared with about 200,000 to 250,000 electric vehicles. California is the third largest consumer of transportation fuels in the world, she said, and the industry produces 3 million gallons of gasoline and diesel every hour.

“We are going to be with you in this conversation for a while, at least for the foreseeable future,” Reheis-Boyd said, and “very much a part of this mix.” The magnitude and timing of electrification is extremely important, she added.

NBI CEO Ralph DiNola said the group is committed to energy efficiency research in design and construction. “It is clear that California policy is driving toward electrification, and I think the building sector is front and center.” Buildings serve as the nexus to the grid, he said, and can be designed and built as grid assets that can be managed and implemented.

A large percentage of energy is used by agricultural producers to pump water to irrigate crops and other after-harvest applications, CFBF attorney Karen Norene Mills said. Many have made investments to adjust to the existing time-of-use rate structure and the incentives matched their practices.

“Our members are struggling with what is happening with the changing landscape,” she said, particularly changing rate structures. “We are finding as we talk to them that there are some real challenges with that.” In the past they have been able to manage their systems and set up operations so they could pump off-peak, and if that is changing, their investments will not be as effective as they have been.

October 23, 2017May 20, 2025

CAISO Symposium Panelists Talk Grid of the Future, Western RTO

By Jason Fordney

SACRAMENTO, Calif. — CAISO’s Board of Governors last week provided insight into a new 2030 energy “vision” for California and the region, one of many discussions at the ISO’s 2017 Stakeholder Symposium.

Governor David Olsen said the “Electricity 2030” paper examines the “the sustained, orderly retirement of gas turbines.” It also discusses the importance of states working together and collaboration among agencies and the public.

CAISO is taking comments on the document, which says a decarbonized, decentralized and more regional electric grid is driving the transition in California. The paper calls for a grid powered by two-thirds non-fossil fuel — and no nuclear — generation by 2030, and lists economic benefits from clean energy jobs and better public health.

But operational dispatch to meet locational capacity needs will be different on a decentralized grid, and “there are engineering challenges along the way” to incorporate the combined capabilities of new resources such as solar and distributed generation, Olsen said.

“It is very important for all of us to take these challenges seriously,” he said, “because nothing will stop movement toward a modernized grid faster than a blackout.”

Challenge and Opportunity

NRG Energy last week took steps to withdraw its application for a new natural gas plant in Ventura County to replace 2,000 MW of generation retiring because of the state’s once-through cooling rules. (See NRG Signals Pull-out on Proposed Puente Plant.) The Ventura/Moorpark load pocket is one example of how locational needs require massive capital investment, as costs for the three distributed energy options to replace the capacity range from $309 million to $1.1 billion.

Governor Angelina Galiteva said the shift to a new type of grid is inevitable and discussed what she called the “financial justice” of the transition. Managing renewable integration “is a challenge, but it is also an opportunity,” she said.

Left to right: moderator John Danner, UC Berkeley-Haas & Princeton University; CAISO Board Members Richard Maullin, Chair; Angelina Galiteva; Mark Ferron; David Olsen | © RTO Insider

“We tend to agree that moving towards a much more decarbonized grid is where everybody is moving,” Galiteva said. A diversity of resources is important to optimize the system, meaning that interstate cooperation to optimize resources “becomes increasingly important.”

She added that climate change is a global issue, and developing countries will benefit from successful efforts in the U.S. “They can leapfrog technologies; they can build microgrids,” she said.

Governor Mark Ferron called for an “optimistic” attitude toward the emerging technology and new communications and called for a “forward-looking approach.”

“I kind of turn it around and say, ‘What’s the alternative?’” he said. “It is not a long-term winning strategy to try to restrict consumer choice or roll back new technology.” He also mentioned the “sea change” of integrating electric vehicles, which must become a grid asset and not a liability.

Regulators Discuss Regionalization

Montana Public Service Commission Vice Chair Travis Kavulla moderated a panel of state regulators who discussed regional differences and the effort to regionalize the Western electricity grid, which is expected to be resumed by the California State Legislature next January.

Left to right: David Danner, Chair, Washington UTC; Libby Jacobs, President, The Jacobs Group and former Iowa Utilities Board Chair; Michael Picker, President, California PUC; Dr. Laura Nelson, Energy Advisor, State of Utah; Travis Kavulla, Vice-Chair, Montana Public Service Commission | © RTO Insider

“There are a variety of cultural issues these days,” California Public Utilities Commission President Michael Picker said, adding that, aside from political differences in California, “we have a long-standing fear of FERC.” He predicted there will be some flexibility in terms of governance of an RTO.

“We have this enormous advantage of having this great diversity of resources in the West,” Picker said, which makes electricity planning easier than planning in other sectors, such as water rights.

Giving the inland West perspective, Laura Nelson, energy adviser to the Utah Public Service Commission, said: “Regionalization is inevitable, but it is a very, very slow-moving ship.” There are political differences to contend with, she noted.

Left to right: Martha Guzman Aceves, Member, California PUC; Judith Schwartz, President, To the Point; Geof Syphers, CEO, Sonoma Clean Power; Dr. Felicia Federico, Executive Director, California Center for Sustainable Communities, UCLA | © RTO Insider

“In parts of the Rocky Mountain West, we really do have a different view of our resources,” she said, but “Utah has been engaged in those conversations.” Utah has traditionally used a lot of coal for generation but also has natural gas and is on track to increase its renewable penetration to 8%.

Most panelists agreed that the trend toward regionalization will increase with time, with the large and dynamic gathering in Sacramento perhaps representing a step toward that end, if all parties can be brought into sufficient alignment while keeping electricity affordable and reliable.

October 23, 2017

FERC Upholds Cost Allocation on Va. Tx Undergrounding

By Rory D. Sweeney

FERC last week decided a seven-year-old dispute over the cost allocation for three Virginia Electric Power Co. transmission undergrounding projects, ruling the costs should be shared by all VEPCO network integration transmission service customers with loads in the state.

FERC cost allocation undergrounding — FERC Headquarters | © *RTO Insider*

The commission reversed some findings from an administrative law judge’s 2016 initial decision while upholding the remainder (EL10-49-005). The commission also denied requests for rehearing of its March 2014 order that said VEPCO loads outside Virginia could not be allocated the incremental costs of the undergrounding, which was ordered by the state (EL10-49-004).

At issue was whether Old Dominion Electric Cooperative and North Carolina Electric Membership Corp. should be required to pay the additional costs of undergrounding VEPCO’s Pleasant View, DuPont Fabros and Garrisonville projects.

“The cost impact of the state’s actions is stark: Approximately 64% of the collective total costs of the projects — almost $150 million — was incurred to place the lines underground,” the commission said. “Considering the three projects together, placing the lines underground nearly tripled construction costs.”

The commission reversed Administrative Law Judge Michael Haubner’s determination on calculating the costs to be allocated to the two utilities for the projects, ruling that it should only include depreciation, return on capital investment, income taxes, accumulated deferred income taxes and property taxes.

It also reversed the judge’s determination that the methodology used to allocate the underground component of project costs should be used for future capital expenditures that don’t increase the projects’ capacity. FERC affirmed, however, its 2014 ruling on cost allocation, the ALJ’s determination that future capital expenditures that increase the projects’ capacity are beyond the scope of the proceeding and its determination of refunds, which are dated to March 17, 2010.

VEPCO must submit tariff revisions and rebill customers within 30 days, and file a refund report within 60 days.

The commission rejected challenges to its March 2014 order, which concluded that the undergrounding costs could not be collected from out-of-state loads because the additional cost was necessitated by state requirements, not reliability needs. The projects created “systemwide benefits,” so the costs should be allocated among wholesale customers rather than just retail, the commission said.

“The commission is not limited to adopting only a remedy put forward in the complaint or in briefing, as the rehearing applicants allege,” FERC said. “The commission has considerable discretion in fashioning remedies and can base that remedy on the record developed.”