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November 5, 2024

CAISO Charts Course for External Resource Participation in EIM

By Robert Mullin

CAISO last week began work on a plan to extend participation in the western Energy Imbalance Market to resources located outside the market’s footprint.

Mark Rothleder
Rothleder

The move comes a month after FERC rejected CAISO’s proposal to indefinitely prohibit EIM participants from implementing economic bidding at the market’s interties until the ISO could develop procedures to manage the practice. (See FERC Order Prods CAISO to Allow EIM Intertie Bidding.)

In its June 30 decision, the commission found the ISO’s open-ended timeframe for producing a bidding solution to be “inappropriate” and directed FERC staff to convene a technical conference to explore the issue.

At an Aug. 4 Regional Issues Forum held at Idaho Power’s headquarters in Boise, CAISO Vice President for Market Quality and Renewable Integration Mark Rothleder floated a set of principles for allowing external resources to bid into the EIM.

Rothleder first laid out what CAISO considers to be the challenges in managing bids at the market’s seams. “It’s important to understand how resources participate in the EIM,” he said.

The EIM requires the ISO to accurately model physical flows across the market for every five- and15-minute interval, Rothleder said. The model factors in variables such as EIM demand, expected output from internal and pseudo-tied resources (including short-term forecasts from renewables); and dynamic import schedules.

“Accurate flow-based modeling means we can do accurate congestion management,” which helps minimize the ISO’s uplift costs, Rothleder said.

Less Granularity

Fifteen-minute scheduling of imports at the EIM’s interties doesn’t provide the same granularity. The ISO doesn’t know the exact source of imports, which “can have an impact when something changes at the source level.”

Rock_Island_spill_(Chelan_County_Public_Utility_District)-alt-fi
External participation in the EIM could enable the Northwest’s ample hydroelectric resources to bid into the market. Photo of the Rock Island Spill Source: Chelan County Public Utility District

And Rothleder pointed out the distinction between bidding and scheduling at the EIM’s interties.

Bidding is “an offering into the market. That means the market is determining when [the generation is] dispatched,” he said. “The expectation is that, if it’s dispatched, it delivers.”

Still, even a “generic” — or system — bid at the seams “does not have the same type of accuracy as an internal market bid,” Rothleder said.

“Frankly speaking, if it were up to us, we’d want to know where those [external] sources are coming from and accurately model them,” Rothleder said. “Uplift costs can be significant. We don’t want to extend that inefficiency to the EIM without knowing what we’re doing.”

Fifteen-minute “generic” bids at the seams have another shortcoming. That’s because the EIM dispatches beyond that interval down to the five-minute level, where resources can provide services other than just energy, such as flexible ramping capability to account for uncertainty from renewable output forecasts.

“The point is, generic bidding at a 15-minute level might not be offering all the services we need,” Rothleder said.

Economic intertie bidding poses additional challenges for the market:

  • Intertie bids are currently not subject to market power mitigation, but mitigation and default energy bids — which reflect a unit’s marginal operating costs — are required by the EIM.
  • Uncertainties regarding the transmission policy and compensation scheme required to facilitate EIM participation by external resources.
  • Lack of metering, greenhouse gas accounting, responsiveness monitoring and control of external resources.

The first step in addressing those challenges: stakeholder agreement on the principles underpinning a solution.

“If everyone agrees to discuss the principles, we think we can find a way to extend EIM participation to other areas,” Rothleder said.

Participation Voluntary

He emphasized that any solution must first recognize that participation in the EIM is voluntary — external resources are not subject to a must-offer obligation. Balancing authorities outside the market must retain their ability to dispatch resources, serve load and balance their own areas.

The proposal must also address the transmission requirements for external resources to participate in the market. And while compatibility with the region’s existing system of bilateral trades is considered another key principle, so is compatibility with the EIM’s current process — which would entail the kind of flow-based modeling of resources necessary to manage congestion.

CAISO also wants external resources to be comparable to those already participating in the EIM. That would require those resources having 15-minute scheduling and five-minute dispatch capability, as well as meeting data exchange, settlements and metering requirements in order to verify delivery.

External resource participation must also avoid “undue operational risks, administrative burden and implementation costs” for both source non-EIM balancing authority areas and sink EIM BAAs.

That last principle was a key concern for Brad Albert, general manager of resource management at Arizona Public Service.

“I didn’t sign up to be a market operator; I signed up to be a market participant,” Albert said. “I want to know if this is going to present another burden on us and [if we’ll] be compensated for it. This is something we’re going to pay close attention to.”

‘Free Riders’

Albert also expressed concern about “free riders” on the EIM system but said CAISO had “caught the high-level principles” needed to formulate a proposal.

Clay MacArthur, assistant vice president for power marketing and contracts at Deseret Power, wondered whether “both the positive and negative effect” of intertie bidding could be modeled in the EIM’s current market construct.

“In my mind, it’s volume and frequency,” Rothleder replied. “If there were a large volume of intertie bids, you’re faced with managing it. We feel a lot more comfortable if we have the physical location [of the resource] right. Then we have metering.”

“You’re going to need a significant amount of information from that resource that’s going to get bid,” said Tony Braun, a consultant and member of the EIM transitional committee. “How much would be required?”

“I think the level of information is probably comparable to a participating resource” in the EIM, Rothleder replied. “I don’t see that as a technical hurdle here.” Policy issues are more of a concern, he added.

Kahn
Kahn

“I don’t see anything that isn’t workable,” said Bob Kahn, executive director of the Northwest & Intermountain Power Producers Coalition, which supports increased regionalization of the western electricity market. “There’s clearly a responsibility for those of us who’d like to effectuate this.”

While FERC’s June ruling leaves open the option for each EIM BAA to develop its own plan for external participation, CAISO is seeking uniformity.

“We thought that this would be something that could be adopted by all EIM entities,” Rothleder said. “That’s why what we’re proposing would be a generic solution.”

With or Without Support, Texas Customer Advocate Remains Undaunted

By Rory Sweeney

AUSTIN, Texas — In a meeting with Carol Biedrzycki, you will know two things without question:

  1. If she isn’t talking, she has nothing to say.
  2. If she is talking, she will not stop until she has nothing else to say.

Candor and steadfastness are qualities that Biedrzycki, the consumer advocate in charge of Texas Ratepayers Organization to Save Energy (ROSE), developed over 24 years of engagement with the electricity industry. They’ve made “Carol B” a “storied figure” in state industry regulatory circles, said Ned Ross, who oversees government affairs for energy supplier Direct Energy.

Carol-Bierdrzycki-(copyright-Gene-Chavez)-web
Bierdrzycki © Gene Chavez

“You can’t question her stamina and her tenacity at any point,” he said. “Interestingly, she finds herself on both sides of the table depending on the issues. Sometimes, she’ll be joined at the hip with industrial customers. Sometimes, she’ll be aligned with us. … She has an interesting job where she’s advocating for things that are consistent for her constituencies, but her constituencies are often aligned with different parties.”

She came to Texas ROSE as its executive director in 1992 after working at the Public Utility Commission of Texas for most of the 1980s. She is the organization’s first, and still only, employee. “When I took the job, all I had was the [organization’s] charter,” she said. “I had no office. Even the [tax] paperwork wasn’t finished for the IRS.”

In the ensuing two-plus decades, she has built the organization up enough to take the state’s electricity industry head on and found some success. From suspicious billing charges to questionable customer service practices, she campaigns to maintain the balance for consumer interests in a system that she feels is heavily weighted toward the industry.

The Regulator Experience

“It was amazing to me the amount of hold the industry had on what happened at the agency,” Biedrzycki said of her time at the PUC.

In fact, she found herself at one point in charge of a meeting to explain rules to industry representatives who she felt were actively trying to not understand them. As the person responsible for reviewing utilities’ energy efficiency programs, she kept hearing from the industry that they didn’t understand the rules. So she called a meeting of the stakeholders to hash out the misunderstandings.

The meeting was well attended, but completely silent.

“They wouldn’t ask a question, they wouldn’t say a word,” Biedrzycki remembers. “I managed to … provide them with what I thought the rule meant, and then the meeting was over. … If they would have been cooperative, then they would have had to submit something that made sense and fulfilled what we thought the requirements of the rule were.”

Instead, she felt, they wanted to maintain their plausible ignorance. “They really didn’t want to ever admit to understanding what the rule meant because they had no intention of complying with it,” she said.

The experience was one that molded Biedrzycki’s persistence. “I just stood in front of that room, and I thought, ‘It’s a good thing I’ve got three brothers who have given me a hard time my whole life’ because I was not really intimidated by them.”

The Story of Texas ROSE

In 1987, the PUC’s energy efficiency division was moved by the state legislature to the governor’s office and renamed the Energy Management Center. Biedrzycki moved with it to continue her work on increasing energy efficiency in the state, but she eventually left and ended up doing consulting work for federal energy efficiency programs.

The legislature earmarked funds for a consumer representation program to be administered through the Office of Public Utility Counsel, but the office thought it should be handled by a nonprofit. Texas ROSE was formed by a group of Austin insiders, who hired Biedrzycki as its executive director.

“The original purpose of the organization was to be a party at cases at the PUC, and I knew a lot of about that because I had direct involvement with it,” Biedrzycki said. “I also knew that it was a worthwhile endeavor because my experience is if you participate as a formal party at the commission … you always got something as a result of it.”

When ROSE’s state funding was eliminated, Biedrzycki scrambled to keep it afloat. The organization is now funded completely by grants, some of which come through Biedrzycki’s collaboration with the Texas Legal Services Center.

“The industry came after me,” she said. “I knew exactly what was going on, and I think they were kind of surprised when I showed up after” the funding was cut.

Staying the course is the first rule of winning regulatory battles, she said. “It’s a game of attrition. They just wait for people to become sick of it and get tired of it and drop off,” she said. “I always tell people: don’t start a utility issue unless you are prepared to carry it all the way through, because it’s the only way that you will see benefit and succeed. … As soon as you don’t show up, they think that you don’t care anymore and that you’re done with it.”

For all of her commitment, Biedrzycki appreciates that it’s mirrored by her organizations’ dedication in her.

“It’s just kinda nice to have people on your side,” she explains about why she took the position at Texas ROSE. “It was a wonderful thing to have people speak to you, ‘We think that what you’re doing is really important.’ How great is that? It doesn’t get much better than that.”

Bringing Back the Regulation

Biedrzycki’s biggest complaint about the industry is what she sees as the failure of power deregulation. Even before it arrived in Texas in 2002, she had been fighting for years to derail the deregulation movement and has spent the subsequent 14 years trying to get the price of power generation regulated again. She points out that several other states have done so and others, including Ohio, are considering it as well.

She believes deregulation was a mistake that hasn’t gotten better, Biedrzycki said. She regularly hears stories of consumers with bills that are hundreds of dollars a month. “I don’t have a background in economics,” she said, “but they took a business that had no middleman and inserted multiple middlemen. Just from a practical standpoint, that never made any sense to me.”

The Power to Choose

In the meantime, she’s remained focused on what she can do for consumers by recommending improvements to the PUC’s retail choice website, on which electric providers list their offers. While the site has received many improvements over the years, it can get better, she said. More than anything, she feels it needs to be simplified. There are too many plans, too much fine print and too much research required by consumers who were fine with just paying the bill when it arrived every month, she said.

“My own personal opinion is [companies] should not be permitted to charge fees for anything that they are required to do under the PUC’s rules because then that way everybody just has to include that cost in their rates and it makes it better for the consumer from a cost comparison perspective,” Biedrzycki said. “I’m really tired of everybody blaming everything on the consumer. You should be able to pay your bill and be left alone, and you should be able to be happy.”

Her opinions are backed up by nearly 100 comments from consumers on the issue filed with the PUC in May. Short and to the point, nearly each comment riffs on the same theme: buying electricity is too complicated. Biedrzycki would like to see the site have a way to calculate estimated monthly bills, along with requiring each retail electric provider to offer a plan that fits a standardized, PUC-approved model so consumers can make easy comparisons.

A recent workshop on the issue with PUC Chairman Donna Nelson produced another of Texas ROSE’s sometimes strange alliances.

“We found ourselves aligning on the vast majority of issues,” Direct Energy’s Ross said, “because we both were trying to find ways to reduce consumer confusion and make shopping easier.”

Respecting the Process

Despite her contentious positions, Biedrzycki’s years of dedication have afforded her respect. It was more than 10 years ago when she was working for the governor’s office that Nelson met Biedrzycki.

“She’s always struck me as someone who wanted to make a change. She wasn’t there for a paycheck,” Nelson said. “Carol does a really good job of representing her client base, which is low-income customers, but she really represents all residential customers — people who often don’t have a voice.”

Nelson also acknowledges that some companies have been “shysters” and “in many cases,” Texas ROSE has provided the information needed to heavily fine them or revoke their certifications. Biedrzycki has also engaged the PUC on several other projects, including revamping rules for company disclosures and ensuring the commercial viability of natural gas retailers.

“I don’t always agree with her, but I usually come to modify the position I went in with originally,” Nelson said. “You always want that counterbalance to what the utility or what the competitors in the competitive market want. … I’ve found that when I get everybody in a room, sometimes the [retail electric providers] will learn something from Carol.”

Building on her past success, Biedrzycki envisions a way for customers to import their actual usage data from the Smart Meter Texas website so they can quickly see how their monthly bills under each plan are likely to look. (See PUCT to Look at Smart Meter Web Portal.)

Aside from those future goals, Biedrzycki continues to advocate for billing assistance, weatherization programs and rate discounts for low-income consumers.

Nelson said it’s hard to have personal relationships while trying to be unbiased, but it’s also impossible not to become familiar because the same people present before the PUC so often that it’s “a small family.” She and Biedrzycki have shared similar medical experiences, and Nelson has noticed some of Biedrzycki’s quirks.

“Sometimes when she testifies, she puts her comments on pink paper so they stand out,” Nelson said. “She’s reasonable, but she’s passionate. Here you lose your credibility if you’re difficult.”

Richard Sedano, a principle at the Regulatory Assistance Project, met Biedrzycki when his organization convened meetings to bring consumer and environmental advocates together. He found out exactly what folks in Austin already knew.

“She is certainly not a shy person. She stepped up and said things she felt needed to be said,” he remembered. “Carol is her own person. … I thought she was really terrific.”

Outside the Office

Expecting to retire in perhaps a year and a half, Biedrzycki is already planning her next moves. Never married and an avid patron of the theater, she plans to spend her summers with family in Pittsburgh, Pa., and return to Austin when the theater season starts up in the fall. She volunteers at several theaters in town.

She is also planning to find a successor to groom. “That’s one thing that I have on the back burner,” she said.

While Biedrzycki has so many changes she’d like to see, she knows to take the long view. Just keep asking the questions, and eventually someone will answer.

“I think her presence [at meetings] — although maybe it’s uncomfortable at times for those who are on the other side — I think people take comfort that she’s there so that [her] interests are represented,” Ross said.

FERC Calls for Post-Conference Comments on Order 1000

FERC is giving respondents until Sept. 2 to provide comments on recommended changes to Order 1000 following a June technical conference at which some participants suggested complete overhauls of the landmark rule and others said it’s too early to tell if changes are necessary (AD16-18). (See Five Years Later, FERC Takes Another Look at Order 1000.)

FERC Order 1000 Tech Conference Overview

The order, which sought to increase transmission development by eliminating incumbent utilities’ right of first refusal and creating incentives for more innovative, cost-effective and efficient projects, has been slow to produce results.

PJM’s Artificial Island project has been a magnet for controversy and was canceled last week. (See PJM Board Halts Artificial Island Project, Orders Staff Analysis.) SPP canceled its first Order 1000 project because of falling load projections. (See SPP Cancels First Competitive Tx Project, Citing Falling Demand Projections.) MISO and NYISO have yet to award any Order 1000 projects.

FERC asked for comments on “the use of cost containment provisions, the relationship of competitive transmission development to transmission incentives, and other ratemaking and transmission planning and development issues.”

— Rory D. Sweeney

OPSI Urges PJM to Preserve Role for Demand Response

The Organization of PJM States Inc. has adopted a resolution urging the PJM Board of Managers to instruct staff to develop market rules “which optimize the participation and value of demand response” in the wholesale markets.

The resolution, sent to CEO Andy Ott on July 29, notes that 10,348 MW of the 12,000 MW in DR offered into the 2019/20 Base Residual Auction cleared. For the following delivery year, PJM will only purchase Capacity Performance products.

Consumer-Advocates---PJM-Board-Meeting-Overview-web-(slider)
OPSI members and the PJM Board Meet at the PJM 2016 Annual Meeting © RTO Insider

DR, which is mostly seasonal, has been a reliable resource that adds value to competitive markets, OPSI said.

“PJM’s planning process for the Base Residual Auction does not provide explicit recognition of the benefits from demand response except for those megawatts of demand response which clear in a PJM capacity auction,” the resolution said.

PJM’s Seasonal Capacity Resource Senior Task Force, whose charter was approved by the Markets and Reliability Committee in May, is studying rule changes to better allow for the participation of seasonal resources into the market once the base capacity product is eliminated. (See MRC Approves Charter for Seasonal Capacity Effort.)

Those resources now may offer in aggregate, but only one such offer was made during PJM’s transition auctions.

Proposals include allowing aggregate offers across locational delivery areas and permitting a seasonal product.

State consumer advocates pushed the PJM board at the RTO’s annual meeting in May to change Capacity Performance rules to encourage the participation of DR, energy efficiency and solar resources. (See Consumer Advocates, Enviros Press PJM on Seasonal Capacity.)

In order for new rules to be in place for the 2020/21 BRA, held next year, PJM must file them with FERC by late fall.

— Suzanne Herel

MISO Study Undercuts IMM Proposal on Expanding ELMP Pricing

By Amanda Durish Cook

MISO said last week that it is leaning against the Independent Market Monitor’s proposal to restrict the ability of offline resources to set prices based on the results of a simulation study.

Congcong Wang, market design engineer, told the Market Subcommittee on Aug. 2 that MISO “continues to recognize the value of offline pricing” and is developing alternative solutions to the Monitor’s recommendation in the second phase of the extended LMP rollout.

ELMP-Phase-II-Progress-(MISO)---content-web

Using simulations, MISO found that the Monitor’s proposed expansion of price setting doesn’t result in the most efficient prices, Wang said.  “It does not mean the recommendation isn’t a good one; it just means that our current software … may not maximize price efficiency,” she added.

In the State of the Market report, the Monitor said offline resources should only set prices when they are economic and can be started quickly to address a shortage.

Monitor David Patton’s ELMP recommendation was two-pronged: He also advised expanding the share of online peaking resources eligible to set prices to include those with start times of one hour or less and minimum run times of two hours or less, regardless of whether they are scheduled in the day-ahead market. (See Monitor’s State of the Market Report Seeks Changes to MISO ELMP.)

Wang said MISO ran four days of simulations: Jan. 18, 2016, with no fast-start resource participation; Jan. 4, 2016, with low participation of fast-start resources; July 17, 2015, with high participation of fast-start resources; and July 12, 2015, with scarcity conditions with offline resource participation and heavy online participation.

MISO found the Monitor’s recommended price-setting expansion resulted in price increases from $1.52/MWh to $9.42/MWh. Expanding ELMP price-setting to units with 30-minute start times resulted in price increases of $0.34/MWh to $3.50/MWh. The Monitor’s recommendation causes price divergence between day-ahead and real-time prices in as much as 85% of intervals, but the 30-minute unit expansion doesn’t affect price convergence, the RTO said.

The recommendation results in online fast-start participation in more than 99% of intervals and the amount of pricing intervals impacted by ELMP rose from 0-7% to 35-74%, according to the RTO.

Patton responded that two of the test days MISO used were already under-scheduled by as much as 6 GW. “The convergence was naturally bad to begin with,” he said.

“I think it’s important to note that this high, it’s true that ELMP will affect more intervals, but many of these intervals are moving by a few cents,” Patton said. “To me, these results suggest that the expansion is necessary.”

Patton said he discovered that offline units setting prices were actually used only 8% of the time, and a diesel unit in Michigan was allowed to set prices 50 to70 times during the period he studied for the State of the Market report without ever being started.

“I’m not sure offline pricing has a strong benefit to begin with,” said Patton, who argued to FERC in the creation of Order 825 that offline pricing can “artificially lower energy prices and obscure shortages.”

Wang pointed out that in Order 825, the commission noted that offline pricing can result in efficient prices.

She said one of the alternatives to dropping offline price setting in ELMP is shortening cost amortization intervals. MISO currently amortizes the commitment costs of offline fast start resources over four real-time intervals, or 20 minutes.

The RTO is planning a September workshop and would come back with more results at the October MSC meeting. Until then, Wang said MISO will continue to run simulations and investigate the impacts of offline price setting. MISO wants to test the second phase of ELMP in the second quarter of next year.

CenterPoint Abandons REIT Plan; Offers Stake in Gas Partnership to OGE

By Tom Kleckner

CenterPoint Energy said Friday it is no longer considering transforming itself into a real estate investment trust.

“Given a broad range of assumptions, we have determined that the potential to create long-term shareholder value by forming a REIT is very limited and does not justify exposure to the associated risks,” CEO Scott Prochazka said in a statement. “We continue to focus on increasing shareholder value by investing in our growing utility businesses.”

CenterPoint executives did not elaborate on the decision during their quarterly earnings call. The company had said in February that it was considering the use of a REIT for all or part of its utility business.

The decision may have been influenced by Hunt Consolidated’s unsuccessful plan to use a REIT structure to acquire Oncor. In March, the Public Utility Commission of Texas approved Hunt’s proposal to split Oncor into two companies, one of which would operate as a REIT. But the commission ordered the REIT’s tax savings be shared with Oncor customers, effectively scuttling Hunt’s plan to acquire the utility.

CenterPoint officials spent much of their earnings call discussing plans to divest the company’s stake in Enable Midstream Partners, a gas gathering and processing limited partnership with OGE Energy.

CenterPoint Abandons REIT Plan; Offers Stake in Gas Partnership to OGE

OGE said during its Aug. 4 earnings call that CenterPoint offered to sell OGE its 55.4% stake in Enable. Under the partnership agreement, OGE has the right of first offer and the right of first refusal on any sales of CenterPoint’s share of Enable, which went public in 2014.

“Our options are essentially the same as they’ve been in the past. We’re looking at a sale or a spin,” Prochazka said. “The timing is such [that] we’re continuing to step through the process. Providing notice to OG&E was one part of [the] process.”

Prochazka said Enable’s performance helped weigh down CenterPoint’s second-quarter results. The company reported a loss of $2 million for the quarter ($0.01/share), after registering a $77 million profit ($0.18/share) for the period in 2015. It had operating income of $182 million, compared to $186 million a year ago.

The company said the losses could be attributed to “changes in the fair market value of commodity derivatives.” Investors reacted Friday by sending CenterPoint’s stock down 3.9%, closing at $22.67.

Houston-based CenterPoint serves more than 5 million metered electric and gas customers, mostly in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas.

Federal Judge Upholds Imperial Irrigation District Suit Against CAISO

By Robert Mullin

A federal judge in Southern California declined to dismiss a lawsuit alleging that CAISO unjustly deprived the Imperial Irrigation District (IID) of its full export rights on a transmission line linking the utility’s balancing authority area (BAA) with the ISO.

U.S. District Court Judge Anthony Battaglia on Monday ruled that IID’s suit had “sufficiently alleged monopolistic conduct that threatens competition” and directed the utility to file an amended claim addressing deficiencies within three weeks.

Salton-Sea-(Imperial-Irrigation-District), CAISO
Salton Sea Source: Imperial Irrigation District

“Specifically, by depriving IID of its expanded [maximum import capability], generators of renewable energy located within IID’s BAA who cannot interconnect directly with the CAISO grid cannot compete with other generators for the business of load-serving entities located in or through the CAISO grid,” Battaglia wrote.

IID’s suit contends that — through a series of memos and public statements from 2011 to 2014 — CAISO “induced” the publicly owned utility to perform $30 million in upgrades to Path 42, one of two transmission lines connecting IID with the ISO. CAISO estimated that the improvements would increase IID’s maximum import capability (MIC) into the ISO from 462 MW to 1,400 MW. The upgrades were put in service in January 2015.

In July 2014, CAISO downgraded IID’s future “expanded MIC” to its previous level, citing the closure of the San Onofre nuclear generating station as the reason for the decision. That move came after IID had already begun work on the upgrades. At the same time, the ISO said that other network additions — although not IID’s upgrades — would restore future flows out of the IID area by up to 1,000 MW, extra capacity that CAISO reserved for itself.

Skeptical of the claim that San Onofre’s closure was the basis for downgrading IID’s MIC, the utility initiated an investigation revealing that CAISO had miscalculated the flows on one of its own transmission lines — a misstep that IID alleges stemmed from the ISO violating its own operating procedures. A correct calculation would have restored the utility’s expanded MIC to 1,400 MW, IID argued.

IID contends that elimination of the expanded MIC prompted renewable energy developers to bypass the utility’s system to directly connect with the ISO, denying IID “significant revenue” from transmission services. IID further alleged that CAISO’s action was part of broader strategy to “further its monopolistic position” by forcing the utility to join the ISO.

While the court dismissed IID’s breach of tariff and federal antitrust claims, it let stand claims against CAISO for breach of contract, conversion, unjust enrichment and restitution.

“The court finds CAISO’s multiple public statements from 2011 through 2013 acknowledging the Path 42 project and the expected increase to IID’s MIC are sufficient to support, at this stage of the litigation, an inference that CAISO implicitly assented to the alleged contract, namely, that CAISO would increase IID’s MIC in exchange for IID’s upgrades to its side of Path 42,” Battaglia wrote.

The court also affirmed its jurisdiction over the proceeding.

“While it is true that transmission of electric energy in interstate commerce is generally a matter of federal concern, FERC simply has no jurisdiction over the transmission facilities at issue here, namely, IID’s facilities, because FERC’s jurisdiction extends only to ‘public utilities,’” Battaglia wrote — noting that, as a municipal utility, IID did not fit the definition of the term.

“IID is pleased that the case against CAISO can now move forward,” IID General Manager Kevin Kelley said. “There is no doubt that the district, its renewable energy generators and ultimately its ratepayers have been harmed by the state’s grid operator in denying transmission access to IID’s balancing area.”

CAISO said it disagreed with the court’s ruling that it has jurisdiction over IID’s remaining claims. “We believe these claims are likewise completely without merit, and we expect that they will be dismissed by the court as further proceedings unfold,” CAISO said in a statement.

Arizona Public Service, Puget Sound Energy Enter EIM Testing Phase

By Robert Mullin

Arizona Public Service and Puget Sound Energy have moved a step closer to linking up with CAISO’s Energy Imbalance Market.

The ISO on Aug. 1 commenced the operations testing phase to prepare the companies for full entry into the real-time market this fall. Over the next two months, the two utilities will operate in the market under real conditions, although their transactions will not become financially binding until Oct. 1.

Energy Imbalance Market (CAISO), EIM, Arizona Public Service, Puget Sound Energy

The testing period will enable grid operators, system engineers and market managers to verify that systems are working as planned, CAISO said.

Unlike an RTO, the EIM does not require transmission-owning members to turn over operational control of their balancing authority areas (BAAs). Generator participants are also allowed to bid real-time energy into the market on a voluntary basis; there is no must-offer rule.

A recent CAISO report said the EIM has accrued $88.2 million in benefits to its participants since the market commenced operation in November 2014. (See EIM Report Shows Continued Growth in CAISO Exports.) Berkshire Hathaway Energy’s NV Energy and PacifiCorp are currently the only utilities participating in the market. Portland General Electric is scheduled to join in October 2018, followed by Idaho Power in spring 2019.

“The addition of APS and PSE will create more opportunities to produce additional benefits, including improved integration of renewable energy,” CAISO CEO Steve Berberich said in a statement.

APS serves about 1.2 million customers in Arizona and operates nearly 6,000 miles of transmission. A 2015 EIM benefits study by consulting firm Energy and Environmental Economics (E3) assumed the utility would maintain about 2,500 MW of transfer capacity with CAISO and another 600 MW with the PacifiCorp East BAA. The utility has no direct links with NV Energy.

The E3 study also determined that EIM membership would help APS lower costs by $7 million to $18.1 million, including $1 million to $3.2 million from the reduced need to maintain flexibility reserves — the type of capacity required to quickly firm up variable output from renewable resources. Implementation costs were estimated at $13 million to $19 million.

PSE serves about 1.1 million electricity customers in Washington state and operates about 2,600 miles of transmission, with a 1,600-MW import capability to compensate for a shortage of generation resources.

But the utility also has a surplus of flexible capacity, “which is probably why we’re joining the EIM,” Phillip Popoff, PSE manager of resource planning, told the Infocast California Energy Summit in May. The utility expects to realize annual benefits of $18 million to $30 million, with start-up costs estimated at about $14 million.

EIM start-up costs include metering upgrades to enable generating plants to capture data at five-minute increments, new market software, business process changes and Open Access Transmission Tariff revisions.

Both utilities will additionally incur ongoing costs of $3.5 million to $4 million a year, which includes fees paid to the ISO to manage the market.

Xcel Seeks OM Cuts, More Wind

By Tom Kleckner

Xcel Energy CEO Ben Fowke said last week that executives are sharpening their pencils after the company failed to meet analysts’ second-quarter expectations.

“We have taken action to reduce [operations and maintenance] expenses,” Fowke told analysts Aug. 3. “As a result, we are confident in our ability to deliver ongoing earnings solidly within our 2016 guidance range” of $2.12 to $2.27/share.

Xcel reported second-quarter earnings of $196.8 million ($0.39/share), compared with $197 million ($0.39/share) a year ago. Analysts surveyed by Thomson Reuters were expecting a penny more ($0.40/share).

Sales were $2.5 billion, lower than the $2.53 billion forecast because of what the company called “some unfavorable weather.” Xcel’s sales for the same period last year were $2.52 billion.

Xcel reported several positive regulatory developments in the eight states in which it operates and touted the proposed 600-MW Rush Creek wind farm in Colorado as an affordable step toward decarbonizing its generating fleet.

“You basically are buying wind at a price point less than you can lock in natural gas reserves,” Fowke said. “So, that’s a pretty compelling story for customers and, I think, investors alike.”

According to the American Wind Energy Association, Xcel is the country’s top-ranked utility wind provider, with 6,545 MW of wind capacity owned or under contract as of the end of 2015. The company has reduced coal’s share of its fuel mix from 56% to 43% since 2005, while wind increased from 3% to 17%.

Xcel Fuel Mix (Xcel) - Xcel Seeks O&M Cuts, More Wind

Fowke said the company expects to add more wind.

MISO is a big footprint and so, I mean, I certainly think from a reliability standpoint … you can handle more wind … and it’s pretty economically compelling right now,” he said, according to a transcript by Seeking Alpha. “In Colorado, where we’re not part of an RTO, we have experienced wind as high as I think 65% of our load in any particular time, and we’ve managed to integrate it very well. And part of that is we’ve developed some of the most sophisticated wind forecasting software in the business, and it’s helping us be more efficient with wind. So [there are] very little curtailments in our wind portfolio; we’re pretty proud of that.”

The company’s shares closed Friday at $42.66, down $1.07 (2.51%) since the earnings announcement.

Minneapolis-based Xcel has operations in the Dakotas, New Mexico, Texas, Wisconsin and Michigan.

ATC Plan Could Eliminate White Pine SSR; Refunds Coming on Presque Isle?

By Amanda Durish Cook

MISO promised last week to review a plan that could end the system support resource agreement for White Pine Unit 1 in Michigan’s Upper Peninsula.

American Transmission Co. said MISO could eliminate the need for the 40-MW generator by revising ATC’s system operating guide and making a temporary two-radial reconfiguration of its transmission system, returning it to pre-1998 conditions. ATC said its solution — details of which haven’t yet been made public — could remain in place until either new generation or new transmission are built.

Source: P.M. Power Group, atc, white pine, presque isle
White Pine Source: P.M. Power Group

The Michigan Agency for Energy supported ATC’s plan, saying it would save Upper Peninsula ratepayers $7.3 million annually in SSR payments.

“I applaud the problem-solving that led to this solution. I wished all stakeholders had gotten more warning early on so there would have been time to develop and implement this solution before costs started to go up and litigation was needed,” said Valerie Brader, executive director of the agency.

Brader also sent a letter to MISO, urging that the grid operator accept ATC’s proposal “without delay,” as it would not result in Tariff revisions. Bader also criticized the “poor condition” of White Pine Unit 1 and noted its six- to 12-hour cold start time.

ATC spokeswoman Anne Spaltholz said the company is working with MISO on the details of the proposals. The RTO has committed to reviewing ATC’s plan during the Aug. 9 meeting of the West Technical Study Task Force.

FERC has final say in the termination of SSR agreements. If an alternate solution isn’t identified, the 60-year-old White Pine plant will continue SSR operations until 2020.

ALJ Orders Refunds for Presque Isle SSR

In a related case, FERC Administrative Law Judge Michael Haubner issued a 37-page initial decision on July 25 (ER14-1242-006, et al.) concluding that Michigan ratepayers were overcharged by Wisconsin Electric Power Co. (WEPCo) for SSR payments on the 344-MW Presque Isle coal plant in Marquette, Mich., in 2014 and early 2015. The judge says $17 million in refunds plus interest are in order; final say rests with the commission.

The ruling came three months after FERC decided that the SSR rate schedules for the Presque Isle, Escanaba and White Pines power plants were appropriate. (See FERC Upholds 3 MISO SSR Cost Allocations in Upper Peninsula.) The Presque Isle and Escanaba SSRs were terminated in 2015.

Brader blamed MISO for the overages, saying the RTO failed to perform due diligence. “MISO blindly accepted numbers without reviewing their reasonableness, resulting in the state and other interested parties having to challenge the expenses through costly proceedings at FERC,” she said.

In May, MISO asked FERC for permission to revise its SSR procedure to require generation owners to provide 26 weeks’ notice of plant suspensions or retirements. The RTO also wants to relax some confidentiality provisions around SSR agreements. (See “MISO Planning Confidentiality, Notification Changes to Attachment Y Procedure,” MISO Planning Advisory Committee Briefs.)

Cloverland Electric Cooperative, a Sault Ste. Marie, Mich.-based nonprofit that has the highest Presque Isle surcharge at $11.7 million, welcomed the ruling, but said it doesn’t fix the larger SSR problem.

“The judge proposed a refund, but for Cloverland members, this just reduces the costs we will have to pay over the next several months. The judge’s decision is one positive step in the legal process that allows the case to continue,” Cloverland CEO Dan Dasho said in a statement.

Dasho also criticized a 2008 exemption to Michigan’s 10% retail choice cap that allows Upper Peninsula iron ore mines to choose their power suppliers. The decision by iron ore provider Cliffs to leave the Presque Isle plant for another generator is the reason WEPCo decided to close the plant in 2014. Dasho said if the law is not changed, the mines could “leave again,” leaving Upper Peninsula ratepayers responsible for a new $300 million natural gas cogeneration plant planned by Chicago-based Invenergy on the Cliffs mining site.

“Our senators and representative supports our position on this, but the governor’s administration is refusing to have this exemption removed and finally protect all the ratepayers in the Upper Peninsula,” Dasho said.