FERC has brushed aside a complaint brought forward by two companies about Ameren Illinois’ annual informational formula rate update and true-up (ER16-1169).
In April, Southwestern Electric Cooperative and Southern Illinois Power Cooperative challenged the $214.4 million revenue requirement rate filing on several fronts. Although FERC agreed with a few points the cooperatives raised, the complaint was dismissed.
FERC ordered Ameren to change how it accounts for contributions in aid of construction. The commission also said it is “improper for Ameren Illinois’ [net operating loss carryforward] to affect Ameren Illinois’ income tax allowance because the tax is deferred, not avoided.” The commission ordered Ameren to include net operating loss carryforward in its rate base to “reflect the fact that the company is unable to take full advantage of its favorable tax timing difference.”
The challenge also caused Ameren to agree with the complainants that it should exclude accrued tax debt, merger costs debt integration, regulatory asset amortization and regulatory liabilities for allowance for funds used during construction from its 2016 true-up.
FERC, however, denied other areas of the challenge:
The complainants said Ameren is allocating solely to transmission certain costs that involve both transmission and distribution. FERC said that while “the naming of certain accounts could be misleading,” the accounts were only related to transmission costs.
The two cooperatives said Ameren should not be allocating franchise fees to customers; Ameren responded that because the franchise fees allow transmission construction, they should be included in transmission rates. FERC said Ameren is allowed to recover franchise fees and said the particular challenge “amounts to a collateral attack on the filed rate.”
The complainants alleged Ameren’s formula rate was improperly related to its generation and distribution functions and asked for “a line-by-line review of specific entries to eliminate generation or distribution-related items.” FERC said that asking for cost to be “functionalized on a direct assignment basis instead of on the basis of an allocation ratio” amounted to challenging the formula rate itself and could only be addressed in a separate filing.
The cooperatives accused Ameren of including costs relating to retail distribution and customer services into the general and intangible plant cost allocation to transmission, which increased from $20.3 million in 2008 to $63.8 million in 2016. FERC said it found “no reason to conclude that Ameren Illinois is not properly classifying the challenged items.”
The complainants questioned the 117% jump in Ameren’s wages and salaries allocation over six years. FERC said the increase was reasonable because Ameren Illinois was using more transmission labor.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:30)
Members will be asked to endorse the following manual changes:
Proposed clarifications to “Member/Vendor Open and Competitive Bidding” will allow flexibility for noncompetitive items, such as office supplies. Revisions to governing document update formatting in the definition sections.
5. Release of Capacity in Delivery Year 2017/18 3rd Incremental Auction (10:00-10:20)
Members will be asked to approve PJM’s proposal to use a straight-line offer curve for selling back excess capacity in February’s third intermediate auction for the 2017/18 delivery year, as recommended by the Market Implementation Committee on Sept. 14. (See “PJM’s Straight-Line Offer Curve Recommended for Capacity Sellback,” PJM Market Implementation Committee Briefs.)
6. Metering Task Force (MTF) (10:20-10:30)
Members will be asked to approve revisions to Manual 1 to close gaps in understanding between staff and members on metering rules. (See “Metering Standards Ready for Stakeholder Vote,” PJM Markets and Reliability Committee Briefs.)
7. Planning Committee Charter (10:30-10:35)
Members will be asked to approve proposed administrative updates to the Planning Committee Charter.
8. PJM Capacity Problem Statement / Issue Charge (10:35-11:35)
Members will be asked to approve Operating Agreement revisions to clarify the “Member/Vendor Open and Competitive Bidding” section to allow flexibility for noncompetitive items, such as office supplies.
3. Cost Development Guidelines Periodic Review (2:55-3:15)
Members will be asked to endorse revisions to Manual 15 that were developed as part of the periodic review process.
4. First Energy Transmission Reorganization (3:15-3:45)
CARMEL, Ind. — MISO will file a revised set of interconnection queue changes with FERC on Oct. 21, and this time it says it has “overwhelming” stakeholder support for the changes.
In its second attempt at a queue reform filing, MISO proposed that the revised M2 milestone become a flat charge of $4,000/MW of new capacity instead of the earlier $5,000/MW. The M3 and M4 fees would total 10% and 20% of any upgrade costs, respectively. MISO would settle any over- or underpayment after it completed a final facility study. (See “MISO Tries to Please FERC with Second Attempt at Queue Reform,” MISO Planning Advisory Committee Briefs.)
All but seven of the 27 members that provided feedback this month supported the three milestone payments. Nearly all members supported total milestone payments being applied to the generator interconnection agreement’s initial payment.
The majority agreed that a project should be able to withdraw penalty-free if a facility study shows costs 25% or $10,000/MW more than the system impact study’s projection. Stakeholders were about evenly split, however, on whether MISO should allow interconnection customers to decrease the number of megawatts they signed up for by 10% at the second decision point of the queue, where projects that withdraw before the first 220 days of the queue can be refunded their entire M3 payment. MISO is proposing 10% megawatt decrease options at both decision point two and the approximately 140-day decision point one, where withdrawing projects are credited their entire M2 milestone payment.
Of the 27 members who responded to MISO, 20 said they generally supported the revised queue reform proposal, five said they did not and two abstained from offering an opinion.
FERC rejected MISO’s first proposal in March, saying the RTO failed to consider other factors when it blamed the queue bottleneck on “speculative” projects. The commission also said MISO’s proposed milestone payments created a “barrier to entry” (ER16-675).
At last week’s Planning Advisory Committee meeting, MISO Director of Interconnection and Planning Tim Aliff said the RTO is responding to FERC’s order by adding more requirements for itself and its transmission owners to lessen the burden on the interconnection customer.
At this month’s MISO Board of Directors meeting in St. Paul, Minn., MISO Vice President of System Planning and Seams Coordination Jennifer Curran said the RTO is hoping to build more certainty into the process and reduce restudies and the amount of time it takes for projects to clear the queue. “It’s currently a two- to three-year process and is challenged by restudies,” she said. “We think we’ve struck a nice balance between all of the interested parties here.”
If approved by FERC, queue changes will take effect in January. Although the new queue rules have not been approved, MISO has nevertheless moved ahead with the transition, which will be fully completed after February 2017’s batch of interconnection entrants.
CHICAGO — The growth of distributed energy resources and behind-the-meter innovation will require upgrades to the distribution network, speakers told PJM’s Grid 20/20 symposium last week.
While the innovative technology driving DER was the subject of much of the daylong conference, many speakers made sure to mention the more mundane network issues as well.
Often, the distribution and transmission networks are treated “as if they’re almost identical,” said the symposium’s keynote speaker, Michael Caramanis, a mechanical and systems engineering professor at Boston University. But a major advantage of the distribution network over the transmission network is that DER capabilities can allow it to sustain a much more competitive market, he said.
While distribution networks tend to experience more unusual situations on a regular basis — a condition described as “normal abnormalities” by CAISO’s Lorenzo Kristov — they also introduce greater marginal-cost granularity across the system, Caramanis said. Using distribution locational marginal pricing (DLMP), that granularity can be harnessed.
“That granularity, if it’s projected into management of distributed energy resource behavior … may affect the aggregate demand [seen] at the transmission and distribution interface,” he said.
“Right now, we’re in a period of evolution,” explained David Owens, the Edison Electric Institute’s executive vice president for business operations group and regulatory affairs. “The goal is to try to move more toward a market. … We have peer-to-peer transaction, but somebody’s got to see all of [the transactions]. Somebody’s got to provide that platform. Somebody’s got to manage it. There’s got to be visibility. There’s got to be interoperability standards. There’s got to be an integrated information and communication system. There’s got to be a data-exchange platform. We don’t have any of that today. … We’ve got a long way to go.”
DER Issues
“The obvious environmental benefits of distributed energy resources can be thought of as being blunted … by the inability to control renewable generation and by its volatility,” Caramanis said. “The way we reward and incentivize distributed energy resources — and, in particular, renewable generation — is introducing certain non-economical choices.”
Information privacy and what he termed as “computational complexity” are also concerns. “How do we handle billions of bits of information that characterize the preferences of millions of” customers? he asked.
That complexity extends to the network as well. “The distribution wires are in abnormal configuration all the time because there are so many circuits that keep changing,” Kristov said. Yet, communication and dispatching is between the grid operator and the resource owner, leaving the distribution-network owner uninformed about the situation.
With voltage changes of 5% able to damage appliances and cause brownouts, distribution networks require careful control, Caramanis said.
Utilities aren’t accustomed to the rapid changes DER may require, speakers said.
“Utility [information technology] systems are very cumbersome, closed and expensive to adapt,” said Kristin Munsch of the Citizens Utility Board.
“We don’t want to sit there and deploy something that we’re going to go back and regret and change a little bit later,” said Ben Kroposki of the National Renewable Energy Laboratory.
And there is no guarantee that consumers will respond to market signals in the way economists would expect. “The one thing we know is people make uneconomic decisions all the time,” Munsch said. “We talk about these sort of transaction incentives and things we’re going to create with this underlying assumption that, ‘Well, all we have to do is explain it to them, and they’re going to be fine with it,’” she said. “Well, they’re not because on some level, utilities — whether it’s energy, natural gas, water — they are different. There’s an expectation they will be there when I want them, how I want them, at a price I can pay.”
Large-scale strategic companies are seeing ways to help with economies of scale, Marathon Capital’s Sarah Nash said. “A lot of these larger players who aren’t necessarily within the traditional energy space, they’re seeing ways to be able to supplement their offerings and move into the energy storage space,” she said.
On a more traditional level, local governments “are on the front lines of these things,” Owens said, and companies should “help them be ambassadors” of the system upgrades.
“Some get it; some fight it,” he said. The models are “smart cities” that have taken an active role in the process, he said.
“You’d be hard-pressed to find someone who says there isn’t overlap” between the state oversight of retail energy sales and the federal oversight of wholesale markets, FERC’s Jignasa Gadani said. “Is the new world going to be cooperative federalism? I don’t know how otherwise you move forward.”
The largest changes, however, might be in perception.
Kristov said the wholesale markets that developed in the late 1990s have created a “commodity concept” of electricity.
“I think we need to question whether that’s an adequate concept going forward because customers don’t care [about] kilowatt-hours; they care about services,” Kristov said. “The value of the grid used to be: get this commodity over here and move it over here, and that’s not the business of the distribution company anymore. It’s creating a new kind of network where the value may not be moving a commodity. It may be providing network services.”
Caramanis disputed that, saying the grid “essentially commoditizes the quality of service.”
“At the end of the day, in order for this to happen, the utility has to have the right incentives as well,” SolarCity’s Seyed Madaeni said. “We’ve got to have a paradigm shift and make sure all the incentives are aligned.”
Consolidated Edison’s Shelly Lyser added that properly valuing DERs’ environmental benefits also is important.
SANTA MONICA, Calif. — Attendees at last week’s Infocast California Distributed Energy Summit received a crash course in the complexity of developing policies on distributed energy resources in a state that already boasts nearly 5,000 MW of rooftop solar.
The takeaway: Conflicting regulatory drivers and misaligned utility business models must be addressed to ensure the value of DERs is maximized and that consumers aren’t saddled with the costs of stranded assets.
Moderating a panel on regulatory issues, Brandon Smithwood, California state affairs manager at the Solar Energy Industries Association (SEIA), let panelists weigh in on the “alphabet soup” of agency proceedings intended to foster the integration of DER.
“To us, DER is anything that’s connected to the distribution level,” said Tom Flynn, storage and DER policy manager at CAISO. “Any resource of any type, any technology. It doesn’t matter to us whether it’s in front of the meter, behind the meter — but it’s connected to the distribution grid, connected to the grid below the ISO’s grid.”
A few years ago, DER advocates expressed interest in aggregating those resources to participate in CAISO’s wholesale market, which requires participating resources to be at least a half-megawatt in capacity, Flynn said.
In response, the ISO allowed DERs to aggregate as a “virtual resource” distributed across multiple pricing nodes within the ISO’s system. That program, known by the acronym DERP — or Distributed Energy Resources Provider — was approved by FERC in June (ER16-1085). (See CAISO Tariff Change Would Extend Market to DER.)
Since then, the ISO has started another initiative called Energy Storage and DER — or ESDER. Among other things, that effort would allow developers to use storage to offset load behind the meter. Unlike other DERs such as rooftop solar, that storage could then bid demand response into the wholesale market.
Storage, “in effect, creates one of the first multiple-use applications,” Flynn said, noting that it can simultaneously participate as a supply- and demand-side resource.
Flynn noted that the California Public Utilities Commission has initiated a proceeding that explores similar issues, such as multiple-use applications; the ability to provide services to multiple entities; station power for storage; and interconnection processes and metering rules for DERs participating in wholesale markets.
Will Speer, director of electric system planning at San Diego Gas and Electric, tossed a few more letters into the regulatory alphabet soup, bringing up the CPUC’s Integrated Resources Plan and Distributed Resources Plan.
The goal of the DRP is to determine the ability of a utility’s distribution system to accommodate DER, Speer said.
“The first requirement was to complete an integration capacity analysis,” he said. “The next big piece of this is a locational net benefits analysis. It’s really looking at — for the locations of feeders — what is the locational net benefit of DERs in those spaces?”
Another component of the plan: demonstration projects to examine the locational benefits of DER and the use of microgrids.
Jim Baak, director of grid integration at nonprofit policy advocacy group Vote Solar, said the number of acronyms indicates the complexity of the regulatory landscape.
“In typical public utility code fashion … we’re very good at parsing issues into siloed proceedings and programs,” Baak said.
To provide a sense of the complexity, Baak listed the topics being treated under separate and overlapping proceedings: electric vehicles, DR, energy efficiency, interconnection rules, the renewable portfolio standard, time-of-use rates, net energy metering, general rate cases, integrated resources planning and energy storage.
That creates a lot of “conflicting drivers” for DER, Baak said.
One of those drivers is the traditional utility planning process, which focuses on loads, resources and forecasting.
Another driver is state policy objectives, which seek to reduce GHG emissions, support jobs and enhance customer choice in energy supply.
And then there’s yet another layer: customer demand and the market forces responding to it.
Although the industry recognizes consumer demand in terms of forecasting and deployment of DER, the planning process is not fully factoring in long-term changes in consumer behavior, Baak contended.
New industry entrants such as Google, Microsoft, General Electric and ADP are seeking to provide services to consumers about how they “consume, produce and think about energy,” Baak noted, asking how that development fits with the traditional utility planning structure and business model.
“If you think about it for a while … there’s not a real good fit,” he said. “We’re sort of trying to overlay this existing infrastructure that we have in the regulatory process with market forces that are happening.”
DER is comparable with the “disruptive” technologies and processes that gave rise to businesses like Uber and Airbnb, and something that can’t be forced into traditional utility structures, Baak said.
“And the one piece that I feel is missing in California is the vision for this,” he said.
Baak acknowledged that the technical proceedings seeking to identify ideal locations for implementing distributed resources are necessary for maintaining reliability. But he also wondered how well equipped they are for meeting state policy objectives and consumer needs.
“What happens when a customer wants to put in an electrical vehicle or solar system in an area of the grid where there are not necessarily grid benefits for doing so?” Baak asked.
And Baak pointed to the elephant in the room: the need to reform the utility business model, an effort that requires regulatory input and oversight.
“We do need to recognize that there’s a misalignment between the utility’s financial objectives and the policy objectives that we have here for DER,” Baak said. Utilities are being asked to defer investment in infrastructure on which they could earn a rate of return for shareholders and instead procure third-party DERs.
In May, New York regulators approved an order revamping their utility business model, creating new revenue streams tied to utilities’ willingness to become “distribution system platform providers” that plan, operate and administer markets for distribution-level services. The order creates incentives based on how well utilities meet goals for GHG reductions, system efficiency and energy efficiency. Customer satisfaction surveys of DER providers also will be a factor. (See NY REV Order Revamps Utility Business Model.)
California has put no such mandate in place, just a set of incentives and “a vague idea of where we think this should go,” Baak said.
“We have to make sure the utilities are structured in a way, and financially awarded in a way, that they support the policy goals of the state as well as the market forces that are driving this,” Baak said.
Speer concurred with Baak up to a point, contending that the state’s support of DER is focused on a goal.
“It’s not just to promote DER to promote DER, it’s to achieve reductions in GHGs,” Speer said. “I do think that vision’s out there, but there is a lot of work to be done.”
“I get a sense in everywhere that we go that we want it to happen today,” Speer continued, adding that customers will suffer without proper planning.
Baak said Vote Solar feels “a sense of urgency,” both because of the state’s climate goals and an anticipated increase in consumer demand for DER as prices decline.
CAISO’s Flynn acknowledged that “evolving customer preferences” — and not just public policies — are driving the adoption of DER.
DER owners’ desire to maximize their investments led the ISO to begin developing ways for DERs to access its wholesale markets.
The ISO is starting to see DER as a more significant supply resource, something that can both offset and serve more load.
Keeping Distribution in the Loop
But with that trend comes increased effects on the utility distribution system, which “are going to more and more affect the transmission system — and vice versa,” Flynn said.
Distribution utilities are developing the capabilities to manage those effects, but increased participation by DER in wholesale markets will require improved data transfers between CAISO and utilities, he said.
Flynn pointed out that an ISO dispatch order to a DER market participant — which puts power on the distribution grid hosting the resource — leaves the distribution utility “completely out of the loop in terms of information.”
“They don’t know what that DER is offering to provide us in the wholesale market,” Flynn said. “They don’t know that we’ve issued a dispatch instruction to them.”
That has alerted CAISO to a “major gap” in its processes: the need to improve data exchange with utilities — something just as important to the ISO, which needs to ensure a predictable response by a DER.
“I think everyone’s goal here is to optimize the use of DER,” Flynn said. “We don’t want to leave value on the table.”
Baak brought the consideration of that value into the context of the regulatory process, noting that Southern California Edison has submitted a rate case proposing more than $2 billion in distribution grid investment to facilitate increased deployment of DER.
While Baak acknowledged the need to modernize the grid, he contended that some of that investment could be displaced by using DERs more cost-effectively.
His organization is concerned that without a utility business model reformed to accommodate DER, regulators will sanction unnecessary investment in utility infrastructure that will remain as a fixed cost in the rate base for 20 years. As the growth of DER allows more customers to supply their own energy, the utility rate base will decline.
“Well, what happens to that fixed-cost recovery?” Baak asked. “Now you’re exacerbating the problem of fixed-cost recovery over a diminishing rate base. What happens to rates?”
Those issues will have to be resolved in a way that supports the state’s energy and environmental goals, Baak contended.
“We’re concerned that, because these proceedings are moving forward independently without that vision, we’re going to end up with a solution in the end that’s less cost-effective for consumers.”
The Nuclear Regulatory Commission wants to know more about NextEra Energy’s plans to respond to the degradation of concrete at its Seabrook nuclear generating station in New Hampshire. An alkali-silica chemical reaction is causing the plant’s concrete walls to break down.
NextEra’s amended license proposal did not contain sufficient details on how it would address the issue, according to a NRC spokesman. The company has until Oct. 3 to provide more details on how it is going to stop, or counter, the chemical reaction. NextEra is seeking a 20-year extension to the plant’s operating license, which is currently set to expire in 2030.
The commission has not deemed the degradation a safety issue, but it wants to know how the company is going to tackle long-term preventative measures.
The Tax Court has ordered Exelon to pay as much as $1.45 billion in back federal taxes, penalties and interest.
The bill resulted from a tax strategy that Commonwealth Edison used after its $4.8 billion sale of coal-fired power plants in 1999. To shield itself from the potential tax bill, ComEd sunk much of the proceeds in long-term leases of power plants in other parts of the country and leased the plants back to the owner-operators.
Exelon must now decide whether it wants to pay or appeal. Even if it to decides to appeal, it still must pay the Internal Revenue Service or post a bond, the company said in a Securities and Exchange Commission filing. “Exelon is still evaluating the Tax Court’s decision and considering next steps,” the company said.
A coalition of environmental groups asked the D.C. Circuit Court of Appeals last week to stay construction of Spectra Energy’s Algonquin Incremental Market natural gas pipeline project while its appeal of FERC’s approval is pending. The pipeline project is designed to transport natural gas from shale-gas fields in the Mid-Atlantic region to markets in the Northeast and Canada.
The groups noted that the court reprimanded FERC for approving a similar project in 2014, but that by the time it had reached its decision, construction was almost complete.
An offshore wind developer has begun surveys off the Massachusetts coast, where it leases about 160,000 acres from the Bureau of Ocean Energy Management.
OffshoreMW is conducting the work south of Martha’s Vineyard in preparation for the possible construction of offshore wind facilities in the area. Seafloor and sub-seafloor surveys will be taken by the crew of the Shearwater research vessel. The company was the successful bidder for the lease area in 2015.
The Idaho National Laboratory has developed a ballistic barrier system designed to protect substations against threats such as bullets, explosives and tornadoes.
The lab started working on the patent-pending Transformer Protection Barrier after a substation in California was targeted by a marksman who fired up to 150 rounds at it, causing an estimated $15 million damage to 17 transformers.
“We are trying to be proactive and provide solutions to threats when they emerge,” said Chad Landon, head of INL’s Defense Systems Materials Technology and Physical Analysis department. “Based on the 2013 incident and similar situations, we decided to come up with a solution.”
FERC is considering changes to its Electric Quarterly Report (EQR) rules, including requiring data on ancillary services transactions and changes to how financially settled trades are reported.
In its Sept. 22 notice of the proposed changes, the commission said it will accept comments on the proposals for 60 days following their publication in the Federal Register (RM01-8, RM10-12, RM12-3 and ER02-2001).
Ancillary Services
Transmission providers currently report ancillary services such as reactive supply and regulation in the EQR’s Contract Data section. FERC is proposing that transmission providers also report information about transactions made under their ancillary services agreements in the EQR’s Transaction Data section.
FERC said the information will “help the commission, the public and the industry determine the actual rates being charged for service under these agreements [and] increase price transparency into the wholesale ancillary services markets.”
Booked Out Transactions
The commission also is seeking to clarify the reporting of “booked out” trades — those settled financially without any transmission of power.
FERC said EQR submissions relating to book outs frequently contain inconsistent or inaccurate information, making it difficult to determine how much power is being traded compared to how much is actually being delivered.
“We find that, based on the current EQR database configuration, it is not possible to differentiate book outs of energy or capacity because EQR filers do not have the option to distinguish between the two products,” FERC wrote.
To create a distinction, FERC proposed amending its data dictionary to replace “booked out power” with the product names “booked out energy” and “booked out capacity.”
FERC also seeks to clarify that booked out transactions must be reported in the EQR regardless of the number of parties involved. The notice provides examples of how booked out transactions should be reported when:
two companies sell physical energy to each other for the same delivery period;
one company sells energy to another company and, in real time, the company buying the energy signals the seller to reduce the amount of energy it is providing; and
at least three companies are in a chain of energy sales and one company appears twice in that chain.
Tariffs and Time Zones
FERC also proposed that filers submit into the EQR’s tariff reference fields tariff-related information that they currently submit in the e-Tariff system and that they include time zone information for transmission capacity reassignment transactions.
FERC said last week it remains unconvinced that MISO’s plan to integrate qualifying facilities into Entergy’s footprint would violate Occidental Chemical’s rights under the Public Utility Regulatory Policies Act, denying the company’s request for rehearing of its April order (EL13-41-001).
MISO’s QF plan, implemented when Entergy first joined the RTO, included two options for QF participation, a “hybrid” option and a behind-the-meter option. Occidental claimed the commission failed to address its argument that QFs participating under the behind-the-meter option would have to give up their PURPA rights. Much of FERC’s original order focused on Occidental’s arguments against the hybrid option. (See FERC Denies Occidental’s PURPA Complaints.)
In its original order, “the commission discussed … why requiring a behind-the-meter QF to be reflected in MISO’s commercial model as an Entergy asset for purposes of MISO market participation does not unduly discriminate against QFs,” FERC said. “Occidental has not elaborated why the commission erred in its rejection of Occidental’s arguments that the behind-the-meter option is unduly discriminatory.”
FERC concluded that QFs “could participate in the MISO market while continuing to exercise their rights pursuant to PURPA, and that MISO does not need to modify its Tariff.”
NextEra Energy’s bid to acquire Texas’ largest electric utility, which cleared a U.S. bankruptcy court earlier this week, may have to navigate some choppy waters with state regulators.
At the Public Utility Commission’s open meeting Thursday, Chairman Donna Nelson and Commissioner Ken Anderson both expressed concerns with NextEra’s proposed $18.7 billion purchase of Oncor.
Anderson said his concern is with the $275 million termination fee to be paid to NextEra should the company be out-bid by a last-minute competitor, or if the commission rejects the sale or imposes overly “burdensome” conditions. Nelson said she was concerned about the impact on competition.
Anderson said he has no problem with the termination fee itself, but with how it is structured.
“This merger agreement … appears to be an effort to really tie the commission’s hands in the proceeding,” he said. “If I read the merger agreement and if the commission rejects the transaction in its entirety as not in the public interest, subject to some caveats, there’s no termination fee.
“If, on the other hand, the commission purports to approve it, but with what they call burdensome conditions … that could have a material adverse effect on NextEra or its credit rating … the result is they could walk the deal and get $275 million. Now that’s an extraordinary requirement.”
‘Offended’
“I have frankly been offended by [the merger agreement], but it is what it is,” Anderson added. “I don’t know where the $275 million is coming from, but it can’t be from Oncor’s ratepayers.”
Anderson said he wanted to explain his concern “so the potential applicant, if it wants to, can address them.” The commissioner admitted he has not reviewed the merger agreement in detail, but he promised to file a memo “maybe” next week that fully explains his viewpoint (Docket No. 42750).
“Burdensome” conditions sank a previous bid to buy Oncor from its bankrupt parent, Energy Future Holdings, when creditors objected to the PUC’s conditional approval in March of Hunt Consolidated’s offer. One of the commission’s requirements was that the Hunt group share potential tax savings with the utility’s ratepayers. (See Hunt Reopens Oncor Bid in Lawsuit Against PUCT.)
For her part, Nelson said she is concerned with the deal’s tax implications and its effect on ERCOT’s competitive market. The Internal Revenue Service earlier this summer issued a ruling that eliminates a potential $4 billion tax liability for its remaining assets, power generator Luminant and electricity retailer TXU Energy.
Anderson noted that NextEra has “substantial competitive assets” in ERCOT that could give the company an unfair advantage, a position Nelson agreed with. Brandy Marty Marquez, the PUC’s third member, was silent during the discussion.
“As this transaction has progressed, it does feel in many ways like a step backwards … with respect to [Oncor’s] ownership,” Nelson said. “The reason the [ERCOT] market is restructured the way it was with separate and regulated [transmission and distribution providers] was to grant generators and retailers access to customers and a way of serving those customers.”
Oncor is not a separate, unbundled company like most in the ERCOT market. As part of EFH’s leveraged buyout of TXU Corp. in 2007, the commission required Oncor to be ring-fenced from its sister companies with a separate, independent board of directors.
“The utility press says part of the reason NextEra buys Oncor is they continue to invest in generation and take advantage of the production tax credits,” Nelson continued. “I do want to look at those, as well.”
An Oncor spokesman declined to comment on the commissioners’ statements.
OK from Bankruptcy Court
On Sept. 19, NextEra won approval from the U.S. Bankruptcy Court in Delaware of its bid for Oncor after increasing its offer by $300 million in cash. The company said it would also make other changes to satisfy EFH creditors (Docket No. 14-10979).
EFH’s legal counsel told U.S. Bankruptcy Judge Christopher Sontchi during a hearing that unsecured creditors will now receive an additional $450 million. NextEra will pay $4.4 billion in cash for Oncor and assume its debt and other liabilities, including funding $9.5 billion for the repayment of EFH debt. Oncor was valued at $18.4 billion before NextEra added its sweetener.
After the collapse of the Hunt group’s bid, NextEra announced in July it had reached an agreement with EFH to purchase its 80.25% stake in Oncor. The other 19.75% is owned by an investor group led by Borealis Infrastructure Management and Singapore’s GIC Special Investments. (See NextEra Reaches Deal for Oncor.)
NextEra says it expects to file a joint application with the PUC “soon,” and that it expects the transaction to close in the first quarter of next year.
“Our proposed transaction provides Oncor with a financially strong, utility-focused owner that shares Oncor’s commitment to providing customers with affordable, reliable electric delivery service and significant value and certainty for the EFH bankruptcy estate,” NextEra CEO Jim Robo said in a statement.
NextEra said the deal is subject to bankruptcy court confirmation of EFH’s Chapter 11 reorganization and approval by FERC and the Texas commission, as well as “other customary conditions and approvals.”
NextEra shares have gained $4.72 since Monday, closing at $128.03/share Thursday.
The Hunt group remains unfazed by NextEra’s progress, with spokesperson Jeanne Phillips saying Hunt “will continue to work with all stakeholders to develop a Texas-based solution for the purchase of Oncor.”
EFH has been struggling to emerge from bankruptcy for more than two years now. It has proposed to sell Luminant and TXU to senior creditors owed $24.4 billion. Another hearing is scheduled in bankruptcy court next Monday.
WASHINGTON — FERC on Thursday approved a NERC reliability standard requiring grid operators to assess and protect against the threat of geomagnetic disturbances (RM15-11).
The final rule (Order 830), effective 60 days after its publication in the Federal Register, is nearly identical to the commission’s proposed rulemaking issued in May last year. Under the rule, certain transmission owners and planners will be required to assess the vulnerability of their systems to a “benchmark” GMD event, defined as a one-in-100-year occurrence. They would then need to submit plans to mitigate the identified vulnerabilities. (See Questions and Answers on NERC’s Proposed GMD Rules.)
NERC will also need to submit a work plan within six months of the rule’s effective date detailing how it will study GMD events in general, “given the limited historical geomagnetic data and because scientific understanding of such disturbances is still evolving,” FERC said.
“While we recognize that scientific and operational research regarding GMD is ongoing, we believe that the potential threat to the Bulk Electric System warrants commission action at this time, including efforts to conduct critical GMD research,” the commission said.
GMDs, caused by solar events that disrupt the planet’s magnetic sphere, are considered “high-impact, low-frequency” events.
Response to Comments
FERC’s original Notice of Proposed Rulemaking questioned certain aspects of NERC’s proposed standard, TPL-007-1, including its reliance solely on spatial averaging to calculate the size of the impacted area in the benchmark event.
In comments submitted in response to the NOPR, NERC and other industry stakeholders defended the standard’s methodology for the benchmark definition, but FERC said they did not provide any new information.
“NERC and industry comments largely focused on the NOPR’s discussion of one possible example to address the directive” to modify the calculation so that it did not rely solely on spatially averaged data, FERC said. “However, while the method discussed in the NOPR is one possible option, the NOPR did not propose to direct NERC to develop revisions based on that option or any specific option.”
The commission gave NERC 18 months to make those revisions, as well as to modify the standard to require that data from geomagnetically induced current monitors and magnetometers be made public and to establish specific deadlines for mitigation plans.
In a few cases, FERC declined to direct NERC to make revisions it had considered in the NOPR, instead including them as part of NERC’s study homework.
For example, the commission had questioned whether the benchmark definition should also be modified to reflect that GMDs could have pronounced effects on lower geomagnetic latitudes. While it said that commenters who defended the original calculations did not provide any new information, the commission declined to direct NERC to revise the latitude scaling factor, saying it found “sufficient evidence to conclude that lower geomagnetic latitudes are, to some degree, less susceptible to the effects of GMD events.”
The final rule represents the second stage of the commission’s effort to protect against GMD, an effort that began in May 2013 with Order 779. The first stage, approved in June 2014, dealt with developing operating procedures for responding to GMDs and mitigating their effects.
Data Lacking
Commissioner Cheryl LaFleur called last week’s order “a milestone reflecting over five years of work by the commission, our staff, NERC, industry and stakeholders to address the threats posed” to the grid by GMDs. “It’s not the beginning of the end but the end of the beginning. We still have a lot of work to do.”
LaFleur said the rule “appropriately balances the need for action on this important issue with a recognition that our understanding of the science around GMD events and their operational impacts on the grid is still evolving.”
“One of the things we found frustrating in our tech conferences in developing the final rule was that so much of the magnetometer and monitoring data was from Canada or Europe when in fact we have one of the most highly developed electric grids in the world and very little public data on which to base our analysis.”
Situational Awareness Requirements
The commission also gave final approval to reliability standards IRO-018-1 and TOP-010-1, which specify requirements for the real-time reliability monitoring and analysis capabilities of reliability coordinators, balancing authorities and transmission operators (RD16-6).
The standards implement Order 693, which specified operators’ minimum capabilities, as well as the recommendations contained in a 2008 NERC best practices report and the joint FERC-NERC report on the 2011 Arizona-Southern California outage.
FERC noted that inadequate situational awareness was identified as one of the key causes of the 2003 Northeast blackout.
The joint report on the Arizona-Southern California outage recommended that entities “should take measures to ensure their real-time tools are adequate, operational and run frequently enough to provide their operators the situational awareness necessary to identify and plan for contingencies and reliably operate their systems.”
NERC said the new standards build on existing requirements by requiring applicable entities to provide them with indications of the quality of information being provided by their monitoring and analysis capabilities and notify them of real-time monitoring alarm failures.
Frequency Control Standards
The commission also gave preliminary approval to NERC’s proposed standard BAL-005-1 (Balancing Authority Control) and FAC-001-3 (Facility Interconnection Requirements), which it said would clarify and consolidate existing frequency control requirements (RM16-13).
The commission said the proposed standards “support more accurate and comprehensive calculation of reporting area control error (ACE) by requiring timely reporting of an inability to calculate reporting ACE and by requiring balancing authorities to maintain minimum levels of annual availability of 99.5% for each balancing authority’s system for calculating reporting ACE.”
The NOPR also seeks the retirement of standards FAC-001-2 (Facility Interconnection Requirements) and BAL-006-2 (Inadvertent Interchange).
The commission said it was uncertain whether to support NERC’s proposal to also retire requirement 15 of standard BAL-005-0.2b (Automatic Generation Control), which requires the maintenance and periodic testing of backup power supplies at primary control centers and other critical locations. “Depending on the explanation received in comments, the commission may issue a directive in the final rule to restore the substance of requirement R15 in the reliability standards,” it said.
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