Page 1431 – RTO Insider

June 27, 2016

For Most States, Time-of-Use Rates Remain Elusive

By Rich Heidorn Jr.

WILLIAMSBURG, Va. — As of last year, 17 states had smart meter penetration of 50% or more. Yet only seven states — Maryland, Delaware, Arizona, Oklahoma, Ohio, Arkansas and Louisiana — have more than 5% of their residential customers enrolled in time-varying rate plans, according to the Energy Information Administration.

The reason for states’ halting progress was the subject of a session moderated by Maryland Public Service Commissioner Anne Hoskins at the Mid-Atlantic Conference of Regulatory Utilities Commissioners Education Conference last week.

time of use rates panel — Gibbons *© RTO Insider*

Leah Gibbons, director of regulatory affairs for NRG Retail Northeast, said consumers’ wariness of time-of-use rates and the speed of technological changes are arguments for retail competition.

“The real reason for relying on retail markets … is because consumer needs and desires are a very quickly evolving thing. People change their minds on what they want and what they need all the time. And the best way to meet those needs is through the innovation of competitive markets. … The regulated model simply is not equipped to deal with that pace and keep up.

“We still don’t know what are customers really going to want. What are they going to go for?” she asked, citing the experience in Texas and some experiments in the Northeast. “Customers really do not like big price spreads that you get in a time-of-use rate. … They’re kind of afraid of it. But you really need to have a decent price spread between on- and off-peak to get customers to change their behavior and actually shift their load. So … we’re going to have to figure out: How do you get customers to choose those kinds of products? Or does it make sense to think more about demand response products?”

Gladys Brown, chair of the Pennsylvania Public Utility Commission, said many of the state’s industrial customers are already on TOU rates and that the commission is now focused on expanding the option to residential ratepayers to take advantage of its 2008 law mandating smart meters. The PUC says about 40% of its 5.7 million residential customers now have advanced meters.

A PPL Energy pilot program that began in 2011 was suspended after less than a year after an unexpected increase in spot market prices resulted in both on-peak and off-peak prices being below the fixed-price default service, resulting in undercollections (P-2013-2389572). When prices rose above the default rate, customers fled the program.

“It started out slowly,” Brown said. But she said regulators hope that with “full deployment of smart meters that we’ll have a lot of different programs.”

Rich Sedano, director of U.S. programs for the Regulatory Assistance Project, said that in addition to reducing peak demand, TOU rates can influence customers’ willingness to add solar panels or a high-efficiency water heater. “The marginal costs of the system are something that customers are typically not aware of if they are in a flat-rate situation, but with time-varying rates they can be made aware of that. And their investments can actually be replacing utility investments,” he said.

William Fields, senior assistant for the Maryland Office of People’s Counsel, questioned whether TOU rates are compelling enough to motivate consumers, citing Pepco’s current TOU rates: 9.6 cents/kWh on-peak; 7.7 cents/kWh off-peak; and 8.2 cents/kWh intermediate.

“In this low-gas-cost, relatively high-capacity-cost … environment, is there really a big difference there?” he asked. “We just want to express some caution that we take a very close look at whether there’s value there to make it worth it.”

The first step is to obtain better data, he said. “One of the frustrations I’ve had … is the limited amount of really good customer data — usage for residential customers, different size houses, apartments,” he said. “I think the [advanced metering infrastructure] that we have should be looked at as an opportunity to collect some better data on things like how does overall usage correlate to [peak] demand? … Do smaller-usage customers have small demand and large-usage customers have large demand?”

June 27, 2016

Overheard at the MACRUC Annual Education Conference

WILLIAMSBURG, Va. — More than 300 regulators, PJM officials and industry stakeholders attended the Mid-Atlantic Conference of Regulatory Utilities Commissioners’ 21st Annual Education Conference last week. Here are some highlights.

Haque Reflects on Year as MACRUC President

Public Utilities Commission of Ohio Chairman Asim Haque reflected on his year as president of MACRUC as he prepared to hand the gavel to incoming president and New Jersey Board of Public Utilities Commissioner Mary-Anna Holden.

Haque acknowledged obstacles in executing his theme for the year: “lead together, lead now.”

His tenure coincided with a bruising battle in Ohio over FirstEnergy’s and American Electric Power’s requests for financial support for their merchant generation. At the same time, Exelon’s acquisition of Pepco Holdings Inc. split commission members in D.C. and Maryland.

“What I’ve come to find this past year is that each of our states’ challenges, while possibly common, are layered in so much subtext,” Haque said. “Most often that subtext can be unique to that particular state. The subtext can be existing law, the makeup and strength of various stakeholders in the state, the political tenor, varying financial interests…

“Finding the answers that are universally acceptable to each of our states is incredibly challenging,” he continued. “If you can’t find universally acceptable answers, then most certainly you won’t be able to lead now.”

‘CEO Panel’ Compares Notes

In the “CEO Panel,” executives from AEP, Pepco and NiSource discussed their challenges in response to questions from moderators Judith Jagdmann, of the Virginia State Corporation Commission, and Richard Mroz, president of the New Jersey BPU.

Robert Powers, COO of AEP, and David Velazquez, CEO of Pepco, shared their experiences operating in multiple jurisdictions. AEP has distribution utilities in seven states in SPP, ERCOT and PJM. In March, Pepco became part of Exelon, which now has distribution operations in five states and D.C. within PJM.

Powers said AEP’s geographical diversity gives the company “opportunities to experiment” on initiatives in one location before proposing them elsewhere. AEP’s philosophy is to “put strong people locally who don’t always have to come to [AEP headquarters in] Columbus for every decision,” he said.

Velazquez said dealing with multiple commissions prevents the company from rolling out initiatives such as smart meters and smart grids in all of its territories at once because of the need to “sell” them to state regulators individually.

On the other hand, he said, “As we get feedback, it helps us … refine and make better the product we’re offering. … So there’s pluses and minuses.”

Carl Levander, executive vice president for regulatory policy and corporate affairs for NiSource, said his company faces a challenge in maintaining institutional knowledge because 23% of its workforce is eligible for retirement and another 29% has at least 20 years’ experience — while a quarter of the employees have less than three years’ tenure.

Levander said that his company, the parent of Northern Indiana Public Service Co. and Columbia Gas, is not interested in expanding into services, such as home security, that other utilities have tried. “We’ve made a decision to be a very boring company — and we have the right people running it,” he said, prompting laughter.

─ Rich Heidorn Jr

June 27, 2016

Governance Plan Fails to Dispel Western RTO Concerns

By Robert Mullin

CAISO last week stepped up efforts to convert skeptics of a Western RTO, convening a forum in Denver to discuss a proposed set of governing principles and dispel concerns that California interests would dominate a West-wide entity.

“What we’re doing actually matters, and it has enormous upsides,” CAISO board member Ashutosh Bhagwat said of the effort.

CAISO is leading the push for an RTO in the West, in part driven by a 2015 California law requiring the grid operator and state energy agencies to explore ISO expansion to improve the state’s ability to meet its 50% renewable energy mandate.

The ISO also seeks to accommodate the timelines of PacifiCorp, which hopes to join the ISO in 2019 but must gain regulatory approval from five Western states before doing so.

Bhagwat said the diversity of resources in an expanded ISO would improve renewable integration and reduce costs for customers in California and the broader region.

EIM Experience

“Experience with the [Energy Imbalance Market] has proven this,” Bhagwat said. “We’re doing this because there is a lot to be gained.”

Contending that the West is “behind the rest of the country” in creating an RTO, Bhagwat also acknowledged “legitimate concerns” among Western industry stakeholders about how the organization would be governed.

“We’ve tried to address them,” he told the forum, referring to the ISO’s proposed principles for governance, which would seek to preserve state regulatory authority, provide all participating states the means to influence RTO policy and reshape the ISO into an entity no longer overly subject to the prerogatives of California.

Still, RTO skeptics — and some supporters — contended that an expanded ISO would be overly subject to California’s influence even with the principles in place.

They cited one major sticking point: the transition to an independent and regionally representative board of directors.

CAISO’s proposal calls for the RTO’s initial board to include the five members of the ISO’s current board and four new members selected by other RTO states through a process approved by those states. Initial board members would have terms staggered in such a way that California-appointed members would always hold a majority through a transition period.

That transition would conclude with the initial board selecting a final, independent board through a nominating process developed by a transitional committee of stakeholders. The nominating process — along with other governance elements proposed by the committee — would be subject to approval by the initial board.

A second sticking point: The transitional committee itself would be appointed by the ISO’s current board.

‘The Mother of all California-Centric Concerns’

“The proposal for the initial board is the mother of all California-centric concerns,” said Bryce Freeman, administrator of the Wyoming Office of Consumer Advocate.

Freeman pointed out that the proposal did not provide an explicit deadline for the transition period, meaning the current ISO board would constitute a majority for an unspecified amount of time. Any policies “hammered out under that arrangement would be accountable to the California political process,” he said.

Freeman also noted that the five PacifiCorp states would be forced to jockey for just four seats on the initial board.

caiso, western rto — Governing principles for a Western RTO will initially need buy-in from the five states containing PacifiCorp’s service territories.

“Whose ox gets gored in that process?” he asked.

“When we get to the final stage of things, California still gets what I’ve been calling a veto over everything anyway,” added Abby Briggerman, an attorney representing inland industrial energy consumers in the West.

Continued reliance on the ISO’s current board is also the American Wind Energy Association’s biggest concern, said Caitlin Liotiris, a consultant representing the organization, which is a strong supporter of the expansion.

Montana Public Service Commissioner Travis Kavulla echoed Freeman’s concerns about the open-ended nature of the initial board. He said it would have more influence on governance than the final board, as governance design would actually be developed and approved during the transition period.

Market-Oriented Board

Kavulla instead suggested the establishment of a market-oriented board populated by members with expertise in electricity market operations, while the “big questions” regarding tariff design and governance would be left to another body.

“That leaves the more complex matters of market design to the people actually running the ISO,” said Kavulla, the current president of the National Association of Regulatory Utility Commissioners.

While Kavulla didn’t specify what body should have authority over the tariff and governance issues, CAISO’s proposal calls for the formation of a body of state regulators “to provide policy direction and input on matters of collective state interest.”

That body would be funded by the RTO but incorporated as a separate entity, with one regulator from each state serving as a voting member. Publicly owned utilities (POUs) within the RTO footprint would appoint one nonvoting representative to act in an advisory capacity.

CAISO intends for the body of state regulators to have “primary authority” over RTO initiatives related to matters like transmission cost allocation and “aspects” of resource adequacy — meaning the RTO would be required to seek the body’s approval for any Section 205 filing with FERC.

“It has been noted that this body has a lot of reserve authority and power,” Kavulla said, adding that it should be staffed with experts to advise its members and support that authority.

Public Power Role

Mark Gendron, Bonneville Power Administration (BPA) senior vice president of power services, suggested a full voting role for the public power representatives.

“That might be a good home for BPA as a [federal power marketing agency],” said Gendron, whose organization operates 78% of the transmission in the Northwest and markets the output from 31 hydroelectric projects.

Gendron’s suggestion received support from Marshall Empey, COO of Utah Associated Municipal Power Systems, which represents community-owned utilities throughout the West.

“The reason we want this as public power is that regulators don’t represent us,” Empey said.

Steve Beuning, director of market operations at Xcel Energy, voiced a different perspective.

“I’m concerned to think of any stakeholder that might have more of a stake than me — such as public power getting a defined role,” Beuning said.

Kavulla noted that the interests of POUs are represented on the state committees of other RTOs. None of those committees set aside a seat for POUs.

“That level of trust might not exist in the West,” he added, referring to the fact that the region’s public utility districts are not subject to state oversight and maintain an arms-length relationship with utility commissions.

Briggerman spotlighted what she considered to be yet another flaw in the design of the state body: a provision that policy changes would require not just a majority vote, but approval by members representing a majority of load in the RTO footprint. California would hold a clear majority in an RTO that includes just PacifiCorp.

“This just sort of echoes my general theme that California has too much authority in this proposal,” Briggerman said.

“At the end of the day, [a Western RTO] is going to take mutual trust between California and non-California,” Kavulla said.

June 24, 2016

Hunt Reopens Oncor Bid in Lawsuit Against PUCT

By Tom Kleckner

Hunt Consolidated’s bid for Texas utility Oncor may not be over after all.

The Hunt group filed a lawsuit Thursday in state court against the Public Utility Commission of Texas, seeking a review of its March order that accepted the proposed acquisition but imposed restrictions that led to the deal’s unraveling.

The lawsuit says the PUC made a number of errors in its ruling on plans to split Oncor into two companies and incorporate a real estate investment trust (REIT) structure (Docket No. 45188).

The order approved the creation of Oncor AssetCo, which would own the transmission and distribution facilities, while Oncor Electric Delivery Co. (OEDC) would rent the facilities to provide electric delivery services. As a REIT, AssetCo would avoid paying federal income taxes if it derived at least 90% of its profits from property rents.

But the PUC’s order included conditions that made it less attractive to investors, including requiring federal tax savings be set aside for possible refunds to customers. The REIT structure would have allowed Hunt to funnel as much as $250 million a year in tax savings to shareholders.

According to the lawsuit, the PUC “prejudiced” the group’s rights by finding the leases between the Oncor companies would be tariffs subject to commission approval; by not treating AssetCo and OEDC on a consolidated basis for ratemaking purposes; by failing to give the restructured Oncor the standard income tax allowance; and by failing to vacate the final order and dismiss the docket.

The lawsuit says the PUC made “administrative findings, inferences, conclusions and decisions” in violation of the state Public Utility Regulatory Act and that were not “reasonably supported by substantial evidence in the record.”

“Because the merger agreement terminated, there was no longer a transaction for the PUCT to approve,” the lawsuit says. “At that time, the PUCT still had jurisdiction over the final order. … Therefore, the PUCT should have vacated the final order and dismissed the proceeding without prejudice. This would have avoided the errors.”

“It sounds like they want to reopen the case, which is confusing at best,” said PUC spokesman Terry Hadley when notified of the lawsuit Thursday evening. “This is unusual.”

“Businesses often file appeals within the court system to preserve their legal rights going forward,” Hunt spokesperson Jeanne Phillips said in a statement. “That is the intent here.”

The Hunt bid appeared to be dead in May, when the PUC rejected all motions for rehearing in the case and let its March order stand. The Hunt group and creditors of Oncor’s bankrupt parent, Energy Future Holdings, had asked the commission to vacate the order and dismiss the proceeding, thus leaving open the possibility of a new application. (See Texas PUC Denies Rehearing on Oncor Sale, Ends Hunt Bid.)

A litigation analyst for Bloomberg Intelligence, Julia Winters, told Bloomberg News that if the Dallas-based Hunt group’s lawsuit is successful, “there’s a chance they would get back to the negotiating table with the debtors and move forward on a deal to buy Oncor.”

“It would be a lot easier to move forward with the plan that was already on the table and approved by the bankruptcy court,” Winters said.

The Hunt group has been pursuing an acquisition of Oncor, the largest transmission and distribution utility in Texas, for several years. Oncor is widely seen as the key to EFH’s bid to restructure almost $50 billion in debt and emerge from two years of bankruptcy. (See EFH Files New Chapter 11 Plan.)

NextEra Energy is also thought to be a potential suitor.

The original plan EFH filed with a Delaware bankruptcy court included a Hunt-led purchase of Oncor for more than $17 billion.

Hadley said the PUC would have no additional response to the lawsuit. It will be represented in the proceeding by the Texas attorney general’s office.

June 23, 2016

PGE to Shut Down Diablo Canyon, California’s Last Nuclear Plant

By Robert Mullin

Pacific Gas and Electric said Tuesday it will shut down California’s last nuclear power plant in 2025 under an agreement reached with a coalition of environmental, labor and anti-nuclear groups.

The utility said it will develop a portfolio of renewable resources, energy efficiency and energy storage to replace output from its 2,240-MW Diablo Canyon facility, located on the state’s central coast near Avila Beach.

That condition was a victory for environmental groups that had opposed the plant on safety grounds but wanted to avoid an outcome in which gas-fired generation would replace the plant’s greenhouse gas-free output.

“It will be the first nuclear power plant retirement to be conditioned on full replacement with lower-cost, zero-carbon resources,” said the Natural Resources Defense Council, one of the parties that negotiated the agreement.

PG&E Diablo Canyon nuclear power — PG&E’s Diablo Canyon nuclear plant is the utility’s single largest source of energy production. *Source: PG&E*

Other parties included Friends of the Earth, Environment California, International Brotherhood of Electrical Workers Local 1245, the Coalition of California Utility Employees and the Alliance for Nuclear Responsibility.

Under the proposal, the company would also commit to serving 55% of its customer load with renewables by 2031.

The state’s revised renewable portfolio standard, enacted last year, calls for 50% renewables by 2030. PG&E cited the RPS, the recent doubling of state energy efficiency goals, growth of distributed energy resources and the potential loss of retail customers to alternative suppliers known as community choice aggregators as key factors in the decision to retire the facility.

Quake Risk

Environmentalists have long been concerned with the plant’s location near several earthquake fault lines, including one 3 miles from the plant that was discovered three years after construction began in 1968. Calls for its closure were renewed after the 2011 quake and tsunami that led to a meltdown at the Fukushima Daiichi nuclear plant in Japan.

Another major consideration: the inability of a baseload plant like Diablo Canyon — which cannot be quickly cycled up and down — to respond to the “overgeneration and intermittency conditions” stemming from increased penetration of solar and wind resources.

In response to the 50% RPS, CAISO will put a premium on the capability to respond to renewables’ variability. The ISO is currently developing a “flexible ramping” product to encourage the development of resources to fulfill that need.

Diablo Canyon accounts for about 20% of annual electricity production in PG&E’s service territory and 9% of production in the state. While the utility points out the plant is currently needed to help maintain system reliability, it said that its absence will reduce the need for solar curtailments during peak solar production and improve the integration of RPS resources.

“California’s energy landscape is changing dramatically with energy efficiency, renewables and storage being central to the state’s energy policy,” PG&E CEO Tony Earley said. “As we make this transition, Diablo Canyon’s full output will no longer be required.”

2025 Retirement Assumed

The California Public Utilities Commission has not yet asked CAISO to perform any special studies related to the retirement, ISO spokesman Steven Greenlee told RTO Insider.

CAISO’s 2016-17 transmission planning process — which looks 10 years into the future — already assumes Diablo Canyon will be retired by 2025 because of state restrictions on “once-through cooling,” the process of drawing coastal or river water to cool turbines. That water is then expelled back into the environment at higher temperatures, affecting marine life. State regulators required the plant to end the practice by 2024.

Any reliability issues stemming from retirement will be identified in the current transmission planning analysis, according to the ISO.

“We will not present a recommendation [on retirement], but PG&E’s decision allows the ISO to begin planning for a grid without Diablo Canyon and a grid that better integrates renewable resources in support of the state’s goals,” Greenlee said. In 2009, PG&E filed with the Nuclear Regulatory Commission to extend the licenses for Diablo Canyon’s two reactors for an additional 20 years. This week’s proposal stipulates that the company will ask to suspend that proceeding. In return, the other parties to the agreement promised not to seek the facility’s closure before the last license expires in August 2025.

They also agreed not to oppose PG&E’s efforts to fully recover costs for the shutdown from California ratepayers. That stipulation requires the parties “to not oppose amortization and cost recovery of Diablo Canyon’s costs in PG&E’s 2017 general rate case” submitted to the PUC.

The agreement is subject to approval by the PUC. PG&E has asked regulators to render a decision by Dec. 31, 2017.

June 21, 2016

FirstEnergy Foes Ask FERC to Step in Again in Ohio Dispute

By Ted Caddell and Suzanne Herel

Groups opposing FirstEnergy’s plan to win subsidies from Ohio regulators asked FERC last week to again intervene in the dispute (EL16-34, et al.).

The Electric Power Supply Association, Dynegy, NRG Energy and others filed a joint protest, asking FERC to block the company’s revised bid to win revenues from Ohio ratepayers for its merchant generation. The Sierra Club, the Environmental Defense Fund and the Ohio Consumers’ Counsel also filed protests.

FirstEnergy asked the Public Utilities Commission of Ohio in May to withdraw an eight-year power purchase agreement — in which the company’s regulated utilities would purchase output from the company’s merchant generators — after FERC ruled April 27 that the PPA, and one for American Electric Power, would be subject to its affiliate abuse review.

firstenergy ohio ppa ferc — FirstEnergy’s Davis Besse Nuclear Power Plant *Source: Wikipedia*

In its place, FirstEnergy wants Ohio regulators to approve a customer charge that it hopes would avoid triggering federal oversight (AEP, FirstEnergy Revise PPA Requests to Avoid FERC Review.)

The modified plan “would allow for the same transfer of captive customer money to market-regulated affiliates and shareholders, but without the affiliate PPA that initially triggered FERC jurisdiction,” the EPSA petitioners wrote last week. “In short, [First Energy Services] and the FirstEnergy [electric distribution utilities] are attempting to achieve the same result as their initial proposal, while evading the commission review mandated by the April 27 order.”

Dynegy and NRG also joined other independent power producers in a letter to the PJM Study Defends Markets, Warns State Policies Can Harm Competition.)

While they did not mention the Ohio situation specifically, the companies said PJM’s markets manage resource adequacy just fine on their own.

“What PJM’s markets have not done — and should not do — is provide protection for certain suppliers who want to be shielded from market risk,” the companies told the board. “Generators that are unable to compete because their facilities are inefficient or their operating costs are too high must make rational business decisions about their future operations, but PJM should not feel compelled to change its market rules to protect them.”

They further urged the RTO to educate policymakers about the negative effects their proposals can have when they interfere with the markets.

The Sierra Club urged FERC to “not allow this brazen end-run” around the commission’s review.

“With their latest gambit, FES and the FirstEnergy EDUs apparently think that they can achieve the same results as their initial plan while evading FERC review by simply eliminating the affiliate PPA,” the Sierra Club wrote. “The modified plan poses the same threat to the commission’s affiliate transaction rules as does the affiliate PPA.”

The Environmental Defense Fund filed similar arguments and spread the word through a blog post.

“It’s not usually a good idea to dis federal regulators,” wrote Dick Munson, EDF’s director of Midwest Clean Energy. “FirstEnergy doesn’t seem to care.

“The utility does deserve credit for persistence and creativity, yet its new proposal doesn’t even pass the laugh test,” Munson continued. “To avoid FERC jurisdiction, for instance, FirstEnergy now claims its subsidy will no longer guarantee the operation of its uneconomic power plants. Yet the utility’s new surcharge is contingent on the continued operation of virtually the same number of megawatts of its nuclear and fossil generation.”

Ohio Consumers’ Counsel Bruce Weston also weighed in, asking FERC to order FirstEnergy to “show cause why it should not be found to be in violation of the Federal Power Act, FERC’s [April 27] order and/or FERC’s affiliate restrictions regulations.”

FirstEnergy’s modified request “strictly involves adjustments to retail electric rates, which is designed to be solely under the jurisdiction of the PUCO,” company spokesman Doug Colafella said. “The objective of our plan — safeguarding our customers against long-term price increases and volatility — can still be achieved without a purchased power agreement.”

June 21, 2016

Del. Lawmakers Try to Block Artificial Island Plan; Project Still on Track

By Suzanne Herel

The Delaware House of Representatives last week unanimously passed a resolution aimed at blocking a proposed stability fix for New Jersey’s Artificial Island nuclear complex that could raise bills for the state’s ratepayers.

House Concurrent Resolution 89, sponsored by Energy Committee Chair Trey Paradee, directs the state Department of Natural Resources and Environmental Control to deny any easement request related to the project as long as the current cost allocation is in place.

That formula assigns $354 million of the $410.5 million project to customers in Delaware and on the Delmarva Peninsula, according to the resolution.

A number of agencies representing those customers, along with Delaware Gov. Jack Markell, have filed their opposition with Officials Urge PJM to Reject Artificial Island Proposal.)

Under the proposal, an average residential customer could expect to see an extra $1 to $3 on their monthly electric bill. The charge would be much higher for commercial customers.

“This could cost businesses thousands of dollars a month and burden local residents for something that will not benefit them,” Paradee said. “That’s the definition of a bad deal. We might not have been successful in appealing to FERC, but we have the final say when it comes to environmental permitting.”

The project calls for the construction of a transmission line that will be buried beneath the Delaware River connecting Artificial Island to Delaware with the goal of improving reliability on the grid.

“Under current project plans, an easement will be sought from the Department of Natural Resources and Environmental Control to connect the line on the Augustine Wildlife Area … and the Augustine Wildlife Area is a renowned deer and waterfowl habitat in Delaware,” the resolution states.

When asked if the resolution could kill the project, Sharon Segner of LS Power, which is constructing the marine crossing, responded, “Absolutely not. It is a nonbinding resolution that must be passed by both the House and Senate in Delaware. A Delaware resolution does not have the force of law. In addition, a resolution expires at the end of the legislative session, which is in two weeks in Delaware.

“We continue to support the Delaware Public Service Commission’s efforts in addressing the cost allocation for the Artificial Island project, as this is the real challenge for Delaware. We hope FERC grants both the rehearing request of the Delaware PSC and LS Power.” (See Stakeholders Ask FERC to Rehear Cost Allocation Order.)

PJM issued a statement urging policymakers not to delay the project. “We are sympathetic to the concerns about cost allocation, which must be resolved by the federal commission,” it said. “It would be unfortunate to delay this necessary project and its reliability benefits.”

Following complaints about the cost allocation for this project as well as the proposed Bergen-Linden Corridor upgrade, FERC held a technical conference in January. It asked: Is there a definable category of projects for which the DFAX method might not be appropriate, and could a fair approach be developed for those occasions? The commission on April 22 upheld the cost allocation for both projects. (See FERC Upholds Cost Allocation for Artificial Island, Bergen-Linden Projects.)

The Artificial Island project faces other hurdles. After Public Service Electric and Gas submitted estimates nearly doubling the cost of its scope of work to $272 million, PJM planners decided to consider alternate configurations. One is to terminate the new transmission line at Hope Creek instead of Salem. However, if the scope of the work is changed substantially, it could require PJM to solicit new bids under FERC Order 1000. (See Artificial Island Cost Increase Could Lead to Rebid.)

June 20, 2016

Company Briefs

The Omaha Public Power District’s board voted unanimously to close the 479-MW Fort Calhoun nuclear plant by the end of the year. The closure of the plant, the country’s smallest nuclear facility, affects 700 employees and will lead to a decommissioning effort expected to cost $1.2 billion.

The vote came after management reported that it cost the utility about $71/MWh to generate power at the plant, double the national industry average. The utility can purchase power on the open market for about $20/MWh.

The utility has sunk nearly $700 million into Fort Calhoun over the past decade for upgrades, flood repairs and to extend the plant’s license to 2033. The plant was commissioned in 1973.

More: Omaha World-Herald

Oil Firm Files Lawsuit Over Kemper Delay

Oil exploration firm Treetop Midstream Services sued Southern Co. over the tardy Kemper coal-gasification plant in eastern Mississippi, from which Treetop was committed to buy carbon dioxide to stimulate depleted oil fields.

Treetop is seeking $100 million and punitive damages from Southern, claiming that the utility committed fraud by misleading it on the construction timeline. The Kemper power plant is more than two years behind schedule and is now expected to be operational in the third quarter of this year.

Treetop had signed a contract for 30% of Kemper’s CO₂ output to pump into oil fields to tap supplies previously considered uneconomic. The company spent nearly $100 million to construct a CO₂ pipeline linking Kemper and its oil-producing area. The plant’s operator, Southern subsidiary Mississippi Power, canceled the Treetop contract earlier this month.

More: Watchdog.org

Consumers Opens 1st Solar Garden on Campus

Consumers Energy has opened its first solar power plant on the campus of Grand Valley State University in Western Michigan. The facility is a 3-MW array that is also the state’s largest community solar project.

The 17-acre Solar Gardens includes Michigan-made solar panels. “This new Solar Gardens location illustrates our commitment to finding new approaches that will sustain our state for generations to come,” Consumers CEO John Russell said.

The company is expecting to open a similar solar garden site about 60 miles away at Western Michigan University later this summer.

More: Consumers Energy

AEP Wins Award for Reconductor Project

American Electric Power won the Edison Electric Institute’s highest award for a project in Texas where it upgraded two 345-kV transmission lines without taking them out of service.

The Energized Reconductor Project in the Lower Rio Grande Valley of Texas incorporated robotic equipment and “energized barehand” work methods, in which the linemen wear conductive suits and come in contact with live wires. Working with contractors Quanta Services and CTC Global, AEP was able to replace 240 miles of line while they remained energized, negating the need for alternate generation during the project. AEP estimated it saved more than $43 million.

“Traditional construction methods would have required taking those lines out of service, but AEP developed an innovative technical solution that permitted the company to successfully upgrade the system while maintaining service and reliability,” said EEI President Tom Kuhn in presenting the company with its 2016 Edison Award.

More: Edison Electric Institute

Lincoln Rejects Request to Disclose Pricing Information

Lincoln Electric System says it will stop publishing breakdowns for the cost of generating electricity at specific facilities in the wake of demand by a wind energy producer to see its financial books.

Gary Aksamit, the head wind power developer Aksamit Resource Management, earlier this year demanded the state’s four largest public power entities disclose their generation costs. The utilities say they gave him thousands of pages of documentation but that revealing certain data would put them at a competitive disadvantage.

LES has historically sold power directly to end users and published details on its generation costs. With SPP’s 2014 implementation of the Integrated Marketplace, the utility now buys and sells electricity in competition with other regional power suppliers.

More: Lincoln Journal Star

Orion Renewable Eyes 250-MW Wind Farm in North Dakota

The Orion Renewable Energy Group says it is planning a 115-turbine wind farm in western North Dakota, capable of generating 250 MW.

The California company has not filed a conditional use permit with county officials, but it said it has completed most of its land leasing and environmental studies. If Orion receives county approval, it will file an application with the state’s Public Service Commission by the end of the year.

More: The Dickinson Press

LG&E-KU Begins Commercial Solar Building Program

Louisville Gas & Electric and Kentucky Utilities launched a new business solar service in which the utilities will construct, own and operate individual solar facilities for commercial and industrial customers.

The ground or rooftop solar arrays ranging from 30 kW to 5 MW will be built on customer property by Kentucky-based Solar Energy Solutions.

“Providing regulated distributed generation through this new customized business solar service will be a new venture for us, but we expect this to be responsive to our customers’ needs,” said John P. Malloy, vice president of LG&E and KU Energy customer service.

More: SurfKY News

Company Proposes 100-MW Solar Farm in Va. Tidewater

Community Energy Solar has filed preliminary applications to develop a 100-MW, 1,200-acre solar farm near the towns of Boykins and Newsoms in Virginia’s Tidewater region. The company said it plans to begin construction of the $175 million Southampton Solar project by the end of 2017.

The company has developed about 1,400 MW of solar in 13 states since 1999 and is building an 80-MW facility in Accomack County, Va., which is expected to come online by the end of this year.

The company’s latest plans were filed with Southampton County, and it will need approval from PJM, the state Department of Environmental Quality and various other regulatory agencies before going forward.

More: The Tidewater News

Seattle Company Applies to Build Floating Wind Farm

Trident Winds applied to build a wind farm off the coast of California in which the wind turbines will be mounted on tethered, floating pylons much like offshore oil drilling rigs, rather than bolted to the sea floor like other proposed offshore U.S. wind projects.

The company wants to construct 100 636-foot floating turbines about 15 miles off the coast of Morro Bay. When completed, the facility would generate up to 1 GW. If it is approved, it would be the largest offshore wind project in the nation.

Because of the technological challenges, the project isn’t expected to go online until 2025.

More: The San Diego Union Tribune; The Mercury News

June 20, 2016

CAISO Study Would ID Gas Generators Vulnerable to Early Retirement

By Robert Mullin

Concerned that large numbers of gas-fired generators will retire early because of competition from lower-cost renewables, CAISO last week proposed a study to identify the most vulnerable units in its balancing area.

The initiative to gauge the risk of “economically driven” retirements is a result of California’s 50% by 2030 renewable portfolio standard, enacted last year.

That mandate — along with other state and federal environmental measures — is expected to increasingly leave nonrenewable resources at the margins of the ISO’s wholesale markets, reducing the income stream for gas generators already dealing with depressed power prices.

Transmission planners would use the study’s findings to assess how potential gas retirements would affect reliability and congestion in ISO load pockets, including local capacity requirements (LCR) areas — regions with increased resource adequacy requirements based on limited import capability. The ISO’s largest metropolitan areas — the Los Angeles Basin, San Diego and the San Francisco Bay Area — are all LCR areas.

ISO staff said the study will not evaluate the impact of gas retirements on overall system resource adequacy, instead limiting its focus to local impacts.

“We’ll go through all the LCR areas one by one,” said Yi Zhang, CAISO regional transmission engineer lead, during a June 13 conference call to discuss the study with stakeholders.

The ISO will accept comments on the proposed study — including its necessity — until June 27.

Study results are intended to inform the ISO’s 2016-2017 transmission planning cycle and the long-term planning process.

The study would screen for potential gas retirements by first overlaying the ISO’s 2015-2016 production cost models — the framework for determining the most cost-efficient generation configuration for serving load — with expected portfolio changes stemming from the 50% renewables mandate. The latest LCR results would also be factored into the assessment.

Based on that information, CAISO would apply three criteria to identify whether a gas unit exhibits a high potential for early retirement:

A capacity factor below the typical value for the type of generator;
No revenue from ancillary services; and
Not required to meet LCR.

A unit meeting the first two criteria, but also needed to meet LCR in a designated area, would likely avoid retirement — except in LCRs with surplus generation.

“If one area has a surplus, there may be some risk of early retirement,” Zhang said.

Calpine Vice President Mark Smith questioned the soundness of CAISO’s criteria for determining the financial viability of units deemed vulnerable.

“You know retirement is fundamentally an economic decision [for generating companies],” Smith said. “Why aren’t you using financial information to assess this rather than the criteria you’ve chosen?”

He contended it would “a very, very dangerous assumption” that any units will be compensated to “stay around.”

Calpine earlier this year idled its gas-fired Sutter Energy Center in Northern California, saying the plant was not economically viable. In 2012, the California Public Utilities Commission directed the state’s three investor-owned utilities to enter into contracts with the 578-MW, combined cycle plant to keep it operating for reliability reasons, but those agreements expired later that year. The PUC has resisted the idea of California developing a capacity market — or any system of capacity payments — to keep such plants available.

sutter energy center (calpine), CAISO, gas generators — Calpine idled its gas-fired Sutter Energy Center in Yuba City, California earlier this year for econmic reasons. *Source: Calpine*

“Trying to do a bottom-up analysis of individual units and trying to understand the value chains they have access to is a far broader exercise,” replied Neil Millar, CAISO executive director of infrastructure development.

“This is our first time to take on this analysis and our focus is the risk to the grid,” Millar said, adding that the ISO will refine its approach in the future.

Zhang said CAISO plans to share a list of potential retirements during a September stakeholder meeting.

June 20, 2016

Cathey’s Inner Geek Helps SPP Incorporate New Technologies

By Tom Kleckner

LITTLE ROCK, Ark. — It doesn’t take much for SPP’s Casey Cathey to let his inner geek flag fly.

Casey Cathey, SPP (copyright RTO Insider) — Casey Cathey, SPP © *RTO Insider*

“Have you heard about Solar Reserve’s salt tower?” he asks, jumping to his feet and grabbing a marker. Cathey steps to the whiteboard and begins to sketch a representation of the 110-MW Crescent Dunes Solar Energy Plant in Nevada. It is capable, its developers say, of providing enough firm solar energy to power 75,000 homes.

Cathey explains how the 10,000 tracking mirrors encircle the 640-foot molten salt tower, following the sun’s movements to concentrate sunlight onto a large receiver at the top of the tower. Molten salt flows through the receiver and down piping inside the tower, eventually being stored in a thermal tank. The salt is then passed through a steam-generation system that provides electricity as needed.

“I’m sorry, but I really geek out about things like this,” a visibly excited Cathey says.

It comes with the job. As manager of operations analysis and support, Cathey led the group that produced a 2015 wind-integration study that revealed SPP could successfully handle wind-integration levels as high as 60%. That same group is now working on a follow-up analysis, the newly renamed Variable Generation Integrated Study.

Cathey also represents SPP on the ISO/RTO Council’s Emerging Technologies Task Force, which has further exposed him to the new technologies and challenges facing the electric industry.

“What we’ve learned is everyone has problems,” he says. CAISO “has too much solar; we have a lot of wind; [and] Toronto has reduced their nuclear plants to offset the wind.”

Front-Row Seat

Cathey almost can’t believe his luck at having a front-row seat to the latest in technological innovation.

“It’s pretty amazing, especially with the people I get to meet and talk to. Ph.D.s, Popular Science, Elon Musk,” he says. “I used to put that stuff on a pedestal, but then you get to meet them and see where we’re at and where we’re going, and you start to realize where the human race is in terms of technology.

“There are a lot of brilliant people out there, but at the same time, there’s a lot of things we can do better,” he added. “There’s a lot of stuff we can improve on.”

For now, Cathey and SPP are working to educate themselves on wind and solar energy, behind-the-meter resources, and batteries, flywheels and other energy storage technologies. The more staff knows, Cathey says, the better they can forecast.

What’s Out There?

“We’re focused on our current business functions as a balancing authority and market reliability. It’s starting to be a little worrisome that we don’t know what’s out there, and we don’t have rules in place to report it.”

Cathey says SPP currently has a requirement that any behind-the-meter resource capable of producing 10 MW or more has to register in the Integrated Marketplace, so it can be modeled correctly. He says loopholes in the requirement allow for derating resources or splitting them up, saying the ratings of some resources do not always tell the whole story.

“The worst risk is if there are many smaller facilities we don’t know about, we could potentially coordinate outages incorrectly and we would not know the real impacts on the Bulk Electric System,” he says. “At these small magnitudes, they’re not going to bring down the system, but if we don’t know about certain generation and we’re not coordinating it, we could have a problem with efficiency and reliability.

“We understand the capabilities and types of generation out there, but … we’re pretty much in the same boat as a lot of other ISOs and RTOs. We don’t know what we don’t know, and [other RTOs] don’t know. The loads themselves don’t know.”

To get better information, SPP has surveyed its members about their behind-the-meter resources.

The RTO hasn’t yet settled on a name for the resources. MISO calls them DERs (distributed energy resources) while ERCOT refers to them as DG (distributed generation). And SPP?

“We don’t have a term yet, but I’m sure it’ll be a different acronym when we come up with it,” Cathey says with a laugh. “Right now, we just want to know about it, so that our models are accurate.”

The RTO will eventually require more stringent reporting on distributed generation, Cathey says — and despite some stakeholder fears, the requirement will not force them to register the resources in the market or to inhibit their contributions to state renewable portfolio standards.

SPP does have an acronym for stored energy resources: SERs. Staff has drafted a revision request that would add energy storage capability to the Integrated Marketplace’s rules, enabling the resource to be registered as a generator type for regulation only. Staff has tweaked the revision request to take advantage of PJM‘s and MISO’s experience with the technology.

Cathey says SPP’s current rules are not “conducive to allow us to embrace that technology.”

“You can actually help out the system by plugging [the batteries] in … they’re providing regulation-down service,” says Cathey, who expects the first SER to show up by year-end. “That extends the life of conventional resources, because we’re not [ramping] them up and down. We’re sending the battery up and down.”

SPP’s current wind-integration study was renamed to include technologies like these, but its primary focus remains wind. The RTO has already seen wind integration reach 48.32%, a record for all North American ISOs and RTOs. It currently has 12,397 MW of installed and available wind capacity, with another 33,819 MW in development.

Cathey says the current study, which will use updated models and assumptions to analyze frequency response and transient response, is an extension of the 2015 study. It will take a “much more thorough” look at voltage, he said. The first study ignored thermal constraints and used an hourly ramp, but the second study will honor thermal ratings and use a five-minute ramp, “so it’s much more realistic.”

“Frequency and ramp, that’s one aspect we’re really interested in,” he says. “Is there a real problem when we have 50%, 60% wind penetration, while honoring thermal constraints? Are we Chicken Little, or is this an actual problem?”

SPP is working with Powertech Labs to develop a module that honors thermal constraints and is placed on top of its voltage-security assessment tool. Cathey says the RTO is past the R&D phase with the technology, which will eventually be rolled out to other ISO/RTOs.

“The model basically … lets us know we need to concentrate further on [a] scenario and build in more planning and operational processes,” he says.

Data, Data and More Data.

Cathey is also helping out with SPP’s Synchrophasor Strike Team’s work, which is intended to ensure the RTO isn’t pushing phasor measurement units (PMU) without stakeholder buy-in.

PMUs are devices that measure the voltage, frequency and angle of the grid’s electrical waves, using a common time source for synchronization. The devices can take samples hundreds of times a second, while the standard SCADA systems can have scan rates of 10 to 30 seconds.

“If we’re making measurements at that scale, we can determine whether there are issues with the models,” Cathey says. “But the problem with PMU incorporation is the data is so much. An operator needs to understand if it’s just a blip on the system for a nano-second. You’re talking petabytes [1 million gigabytes] of data. You’re well beyond terabytes.”

Staff is currently working on how best to filter the data and make it more manageable for operators. In the meantime, SPP has posted a revision request that would require all new generators to have a PMU. The request has been vetted within the strike force, which will determine whether the cost-benefit analysis justifies requiring existing generation to be retrofitted with PMUs.

Oklahoma Gas & Electric, which has installed more than 200 PMUs as part of a Department of Energy grant, has become a proponent of the technology, Cathey said.

“They’re the [subject-matter experts] for the industry, not just our area,” he says. “According to OG&E, the cost is not that much. Where the cost comes into play is if your substation or your switchyard is not capable of accepting the PMU.

“These are things we don’t traditionally think about. We think about power, getting it from Point A to Point B and whether the line can sustain it. … Now, we’re thinking about very engineering-centric problems.”

Which is exactly the way Cathey likes it.