Page 1384 – RTO Insider

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 (14-1297-EL-SSO). (See 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 Board of Managers last week, in response to a PJM white paper about resource investment in competitive markets. (See 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 FERC and PJM, saying the distribution factor cost allocation method (DFAX) is unjust and that the customers paying the most stand to receive just 10% of the load savings benefits. (See 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.

June 20, 2016

FERC Accepts ISO-NE Auction Results

By William Opalka

FERC accepted the results of ISO-NE’s 10th Forward Capacity Auction last week, again rejecting allegations of market manipulation and concluding that the prices were just and reasonable (ER16-1041).

Brayton Point power plant, ISO-NE forward capacity auction, ferc — Brayton Point *Wikipedia*

The auction, covering the 2019/20 commitment period, saw prices drop to $7.03/kW-month from last year’s $9.55/kW-month. It was the first decline in four years. (See Prices Down 26% in ISO-NE Capacity Auction.)

The Utility Workers Union of America has claimed the Brayton Point generating plant in Massachusetts has been withheld from the last three auctions to drive up capacity prices. The plant, purchased by Dynegy in 2015 from Energy Capital Partners, is scheduled to close next year. (See FERC Again Rebuffs Brayton Point Union.)

“We emphasize, as the commission has stated in previous orders, that the commission’s Office of Enforcement reviewed Brayton Point’s bidding behavior in FCA 8 to determine whether further investigation of Brayton Point was warranted and ‘found credible justifications for the owners’ retirement decision and elected not to widen its investigation to include Brayton Point,’” FERC said. “We are not persuaded by Utility Workers Union’s allegations that market manipulation affected FCA 10, as the record is devoid of any evidence to that effect, and we similarly reject Utility Workers Union’s request for a stay pending discovery and further adjudication of that allegation.”

The commission also said that a “rigorous” review by ISO-NE’s Internal Market Monitor determined FCA 10 was competitive.

FERC Backs ISO-NE in Tariff Dispute

In a separate order, the commission rejected a complaint that alleged ISO-NE violated its Tariff when it refused to qualify an increase in a Massachusetts generating plant’s output for FCA 10 (EL16-48).

Northeast Energy Associates, owner of the Bellingham generating station, agreed with ISO-NE that an additional 10 MW of capacity was a “significant increase” but disagreed on whether it should be treated as new or existing capacity. New capacity is required to submit a composite offer linking incremental summer qualified capacity to existing winter qualified capacity.

NEA said the 10 MW should have been added to the existing summer qualified capacity without a composite offer and asked the commission to order ISO-NE to include the increase as if it had cleared FCA 10 — a move that would result in capacity payments to NEA of almost $844,000.

FERC sided with ISO-NE, saying that NEA, which is owned by subsidiaries of NextEra Energy and GDF SUEZ Energy Resources, misread the Tariff.

“We agree with ISO-NE that … the Tariff is clear that a significant increase must abide by all the provisions applicable to a new generating capacity resource,” FERC wrote.

This is the second time FERC has addressed a capacity increase for Bellingham. Previously, FERC granted a waiver to allow the plant to participate when the company submitted a late interconnection deposit. ISO-NE wanted to disqualify the resource, but the commission said a good-faith effort was made to submit a timely payment after NEA discovered its oversight. (See FERC Overrides ISO-NE, Grants Waiver for Late Capacity Payment.)

June 20, 2016

FERC Proposes Protections on CEII

By Michael Brooks

WASHINGTON — FERC last week issued a Notice of Proposed Rulemaking to implement legislation enacted last year to protect the grid from terrorist attacks (RM16-15).

The Fixing America’s Surface Transportation (FAST) Act, signed by President Obama in December, was mainly a highway funding bill, but it also amended the Federal Power Act to require FERC to update its critical energy infrastructure information (CEII) regulations. (See Transportation Bill Includes Grid Security Measures.)

The NOPR details how the commission plans to update its procedures for designating CEII, sharing CEII with other government agencies and sanctioning employees for unauthorized disclosures.

“Obviously, maintaining the confidentiality of critical infrastructure information is absolutely essential to our work in this area, particularly on reliability,” Commissioner Cheryl LaFleur said. “The FAST Act contains important new authority for the commission that allows us to both protect critical information and confidentially share it with government and private parties.”

LaFleur in particular praised Congress’ exemption of CEII from Freedom of Information Act disclosure.

The sanctions for unauthorized release of CEII stemmed from former Chairman Jon Wellinghoff publicly discussing a confidential FERC analysis on the grid vulnerability to physical attacks. The NOPR says that any FERC employee who knowingly discloses CEII would be subject to termination and/or criminal prosecution. Commissioners who do so would be referred to the Energy Department’s Inspector General.

FERC Chairman Norman Bay would not detail what criminal statutes an employee would be prosecuted under, only saying that CEII is not the same as classified material.

Comments on the NOPR are due 45 days after its publication in the Federal Register.

NERC Databases

FERC also amended its regulations to require NERC to provide the commission and staff access to three of its databases (RM15-25).

The rule gives FERC access to NERC’s transmission availability data system, generating availability data system and protection system misoperations databases. (See FERC to Look over NERC’s Shoulders on Reliability.) It will not take effect, however, until the commission issues a final order implementing the FAST Act provisions.

June 20, 2016

New York Transmission Developers Ask FERC to Order a Do-over

By William Opalka

Three competitive transmission developers asked FERC last week to order NYISO to issue a new request for proposals for transmission upgrades to alleviate congestion and bring renewable energy downstate (EL16-84).

The RFP was issued in February in response to a New York Public Service Commission order that declared a public policy need for two projects in the Mohawk and Hudson valleys to deliver energy to load centers in and around New York City. (See NYPSC Directs NYISO to Seek Tx Bids.)

The developers — Boundless Energy NE, CityGreen Transmission and Miller Bros. — say NYISO violated its Tariff and FERC directives under Order 1000 when it solicited projects without conducting its own review and instead deferred to state regulators.

“We are filing a petition with FERC because the NYISO violated its FERC tariff by inappropriately deferring to the New York Public Service Commission rather than follow its FERC-approved transmission planning function,” Boundless President Rod Lenfest said in a statement.

nypsc

“Based on FERC’s own guidelines, the NYPSC has a limited role in the energy transmission planning process. While that planning process allows the NYPSC to identify to the NYISO the transmission needs for the state, here the NYPSC went even further and pushed for a particular project solution to meet those needs. Rather than consider these projects along with other alternatives that could reduce costs for consumers, the NYISO decided to consider only proposals for the particular projects identified by the NYPSC.”

The developers asked FERC “to confirm that the NYISO, not the NYPSC, is the entity that is required to study and identify the specific project solutions.”

The plaintiffs said the ISO should follow its normal study process — including its base assumptions and generator dispatch modeling — to consider competing solutions without excluding specific technologies or relying on the PSC’s assumptions and modeling.

Developers’ proposals, which were submitted in late April, are currently being evaluated by NYISO staff.

Boundless CEO E. John Tompkins said in an affidavit that the company is seeking a stay of the solicitation process in the appellate division of the state Supreme Court.

The company participated in an evaluation of potential projects last year by NYPSC staff in its AC Transmission initiative. But staff recommended that the developer be disqualified because its proposals were deemed to be not cost-effective. (See NYPSC Staff Recommends $1.2B in Transmission Projects.) Boundless also sought a rehearing of the NYPSC order that declared the public policy need, but that petition was denied in February.

Earlier this month, NYISO named 10 project finalists in a concurrent public policy proceeding designed to alleviate congestion in the Buffalo area. (See NYISO Identifies 10 Public Policy Tx Projects.)