The PJM Board of Managers on Wednesday approved about $417 million in reliability-related transmission projects, more than half of which will go to Public Service Electric and Gas to replace a substation in downtown Newark, N.J.
Newark Switch property exterior | PJM
“The board’s approval of these projects reinforces both PJM’s fundamental mission of preserving reliability and the value of PJM’s independent assessment of transmission needs,” CEO Andy Ott said. “Planning is evolving in PJM to consider impacts of new trends. However, studying and planning for reliability remains the top priority.”
The PSE&G substation rebuild is expected to cost ratepayers $275 million. A new gas-insulated substation will be built adjacent to the existing station, which will be torn down. (See “New Proposal Shaves $78M from PSE&G Switch Fix,” PJM Planning Committee and TEAC Briefs.)
Newark Switch property interior | PJM
The board also approved projects for American Electric Power, Dominion Energy, Atlantic City Electric, PECO Energy, Pennsylvania Electric, American Transmission Systems Inc., East Kentucky Power Cooperative, Exelon Generation and Dayton Power & Light. Most projects are estimated to cost less than $5 million, but a 31-mile reconstruction of a 230-kV line in Dominion’s territory is expected to run $31 million. Two ATSI reconductor projects are estimated at a combined $33.43 million.
NextEra Energy CEO Jim Robo said Wednesday that the Florida-based company would “vigorously” pursue a $275 million termination fee it says it is owed following a failed attempt to acquire Texas utility Oncor.
The Public Utility Commission of Texas in April ruled that NextEra’s $18.7 billion acquisition of the state’s largest utility wasn’t in the public interest, and then rejected two subsequent rehearing requests. Warren Buffet’s Berkshire Hathaway Energy has since announced it has reached an agreement to buy Oncor’s parent, bankrupt Energy Future Holdings (EFH), which would give it control of Texas’ largest utility. (See PUCT Staff Welcomes Buffett’s Oncor Bid; Debtor Miffed.)
During a conference call with financial analysts following the company’s release of second-quarter earnings, Robo said the termination fee was triggered when NextEra was unable to agree to a list of what it called “burdensome conditions,” which included protective ring-fencing around Oncor and an independent board of directors for the company.
“The agreement has been terminated by EFH … in that the burdensome conditions had not been satisfied, which was one of the precursors to obtaining regulatory approval,” Robo said. “As a result of the termination of merger agreement, we will vigorously pursue our rights to termination of the fee.”
NextEra has also filed a lawsuit in Texas state court against the PUC, asking the court to reverse the regulators’ rejection of the proposed acquisition. Robo declined to address the lawsuit, saying the petition it filed “speaks for itself.” (See “NextEra Sues over Regulators’ Rejection of Oncor Acquisition,” Company Briefs.)
Asked about the Department of Energy’s grid reliability study and its focus on baseload power, Robo said it was too early to speculate about the final report’s conclusions. He said the “data is pretty clear” that the grid does not have any reliability issues.
“The facts are, the grid is very reliable in America right now, particularly as storage prices come down and make renewables more reliable,” he said. “Our industry has a choice of hanging on to the techs of the past or adopting and embracing the technology of the future. We know what our strategy is. We’re going to embrace renewables and embrace them hard.”
NextEra reported an 11% increase in adjusted earnings during the second quarter, from $777 million last year to $881 million this year. Earnings per share were $1.86, up from $1.67, beating Nasdaq’s consensus analysts’ forecast of $1.76.
The company’s stock price jumped almost 2%, from $142.62/share to $145.35/share, after the market opened. It was trading at $144.94/share by late afternoon.
WASHINGTON — RTO officials acknowledged Wednesday that they are challenged by low power prices and a shifting generation mix but insisted they are up to the task, asking Congress not to abandon its support of wholesale markets.
“Although debate on various market rules is perfectly appropriate, we caution against the potential to add greater uncertainty to the markets by signaling some kind of wholesale retreat from the competitive market model that has been in place since the mid-1990s and has worked well to keep prices low and investment certain,” Craig Glazer, PJM’s vice president of federal government policy, told the House Energy and Commerce Committee’s Subcommittee on Energy.
“The markets are working very well,” agreed SPP CEO Nick Brown, who said his RTO provides net benefits of more than $1.7 billion annually — a benefit-cost ratio of 11:1, he said. MISO provided $3 billion in benefits last year and $18 billion over the last decade, said Chief Operations Officer Richard Doying.
Representatives from all six FERC-regulated RTOs and ISOs appeared along with an ERCOT executive at the nearly two-and-a-half hour hearing, the third in a series of fact-finding sessions that began last year with a letter to FERC and a hearing in September on the 1935 Federal Power Act. On July 18, the committee heard from stakeholders representing public power, independent power producers and integrated utilities. (See Public Power Takes PJM Gripes to Congress.)
A Republican committee aide, speaking on background, said the bipartisan hearings will resume after the August recess. Although some witnesses and committee members at last week’s hearing called for changes to the 1978 Public Utility Regulatory Policies Act, “consistently what we’ve heard is that there’s no immediate need” for changes in the FPA, the aide said.
The aide said, however, that the May 1-2 FERC technical conference on tensions between wholesale markets and out-of-market procurements and subsidies “got more attention [from House members] than any other technical conference in recent history.”
Criticism Nothing New
As at the technical conference and the July 18 House hearing, much of the focus was on PJM, NYISO and ISO-NE, the three eastern grid operators facing the most acute challenges from state policies.
PJM has perhaps the toughest challenge of the three grids in threading the needle between stakeholders pushing for supports for coal and nuclear “baseload” power and efforts to insulate the markets from price suppression. Unlike the single-state NYISO and the environmentally activist New England states, PJM’s footprint is particularly diverse, encompassing both consumer choice states and traditional, vertically integrated states; only some states have renewable portfolio standards; some states are coal producers, while others are heavily reliant on nuclear power.
But Glazer, a former Ohio utility regulator and PJM’s longtime voice in D.C., said the conflicts are nothing new for the RTO. “The PJM markets have weathered many challenges to the industry, ranging from the impact of EPA’s Mercury and Air Toxics rule on the coal fleet to the threats of cyberattacks on the grid itself. We are stronger as a result and are confident that innovative market-based solutions, which have been the hallmark of PJM since its inception, can continue to serve us well in addressing our new set of 21st century challenges.”
He appealed to his congressional inquisitors by holding up photos of new generation in several of the committee members’ districts.
On several occasions, he attempted to rebut criticism by public power providers who say their self-supply option has been eroded since the settlement that created PJM’s capacity construct. Lisa McAlister, senior vice president and general counsel of regulatory affairs for American Municipal Power, told the committee July 18 that PJM rule changes “have stripped away guaranteed clearing for self-supply.”
Glazer cited 1,375 MW of new generation or uprates to existing public power-owned generation since the inception of the capacity market. The RTO has added more than 46.5 GW of new generation over the same period.
The order “did not overturn the specific agreed-to arrangement that PJM and its stakeholders worked out with public power entities,” Glazer said. “As a result, the right to self-supply in our capacity market and energy market has been negotiated with public power and fully honored by PJM and its stakeholders. To suggest otherwise is simply not consistent with those facts.”
“Absolutely, we have self-supply today,” Glazer reiterated in response to a question from Rep. John Shimkus (R-Ill.). “We have no intention of changing that.”
But Glazer rejected public power’s call to abandon the capacity market and use bilateral contracts to fill most of its capacity needs, saying it would eliminate price transparency.
Glazer had an exchange with Rep. Morgan Griffith (R-Va.), who complained that coal-fired generation was “under severe assault.” Glazer said PJM’s proposal that FERC change its price formation rules “to better recognize the attributes that key generators — including those which have come to be labeled ‘baseload generation’ — bring to the grid” would provide financial help for struggling coal plants. He said the proposed changes would “ensure that all resources needed to serve load are able to set wholesale prices.”
But he rejected Griffith’s claim that stranded costs resulting from premature coal plant retirements were falling on ratepayers. “We moved to the markets to try to not put it all on the backs of the customer,” he said.
Ranking member Frank Pallone (D-N.J.) took PJM to task for what he called excessive transmission spending and a lack of transparency in the RTO’s Regional Transmission Expansion Plan. Glazer noted that the Transmission Expansion Advisory Committee meetings are open to the public and sought to distinguish PJM’s role from that of state siting authorities. “Maybe we need to do more to reach out,” he offered.
ISO-NE CEO Gordon van Welie recalled his testimony before the committee in March 2013, when he cited the “serious operational challenges” facing New England because of its changing generation mix.
“As New England has increased its reliance on natural gas [since 2013], we have not seen a corresponding increase in the region’s natural gas transportation and storage infrastructure, which is currently stressed to meet demand for natural gas for both home heating and power generation during the coldest weeks of the year,” he said. “The shift from power plants with on-site fuel supply (e.g., oil, coal and nuclear) to plants relying on the natural gas transportation network to deliver fuel when needed has exposed the limitations of New England’s fuel infrastructure system and highlights the challenge of securing fuel in advance of power system demands.”
Van Welie said the RTO has concluded that the Pay-for-Performance capacity incentives developed in 2013 “may not be sufficient to ensure fuel security during the winter” because of opposition to siting dual-fuel facilities and tighter emission limits that restrict the amount of time generators can operate on oil. That, he said “is likely to create greater dependency” on LNG imports.
NYISO CEO Brad Jones briefed members on the ISO’s proposed transmission expansions to connect upstate renewables to downstate loads and its plan to incorporate carbon prices in its energy market — a response to the zero-emission credits approved for three upstate nuclear plants. (See New York ZEC Suit Dismissed.)
The ISO said it expects to release The Brattle Group’s report on the carbon plan within two weeks. That, Jones said, will be the basis for discussions with market participants and state officials. He said the ISO hopes to implement the plan in the markets within three years.
Unlike the other grid operators, ERCOT is still seeing strong load growth, said Chief Operating Officer Cheryl Mele. After growing at 2% annually in recent years, ERCOT expects annual growth of 1.5% for the next five years.
One thing it does have in common with the other regions: Low energy prices are pinching the finances of thermal and nuclear units. “We also have seen that, for several years, investors and unit owners of every type of generation were watching to see if there would be federal environmental policies that would materially affect their investments or retirement strategies,” Mele said. “That conversation has since changed. Nevertheless, aside from regulatory concerns, ongoing changes in the generation resource mix and market dynamics may have major impacts on potential unit retirement decisions.”
Keith Casey, CAISO’s vice president of market and infrastructure development, told the committee the effects of low power prices — which have sparked calls for nuclear and coal subsidies in the eastern markets — also have led “conventional” plants in California to request “backstop” contracts to maintain their financial viability. (See CAISO Stakeholders Question Risk-of-Retirement Initiative.)
Casey, too, defended the markets. “We have almost 20 years of operating experience and have evolved our markets since the Western Energy Crisis occurred 17 years ago,” he said. “Consequently, the California ISO’s electricity markets have matured significantly and are in far better shape now than they were then to serve electric demand in an efficient and reliable manner. Indeed, our success has encouraged other transmission providers in the West to join our real-time energy market and form the Western Energy Imbalance Market.”
Connecticut Gov. Dannel Malloy on Tuesday ordered state regulators to assess the economic viability of the Millstone nuclear power plant and determine whether the state should provide it financial support. Millstone supplies about half of Connecticut’s electricity.
The Connecticut General Assembly in June failed to pass a bill that would have allowed the 2,111-MW nuclear plant in Waterford to bid into the state procurement process (S.B. 106). Millstone owner Dominion Energy had sought the legislation to boost the plant’s revenues, which have suffered from low-priced natural gas. Gas-fired generators often set LMPs in New England.
Malloy’s executive order also directs the state Department of Energy and Environmental Protection and the Public Utilities Regulatory Authority to assess the role of large-scale hydropower, demand-reduction measures, energy storage and emissions-free renewable energy in helping Connecticut meet its ambitious targets to cut its carbon output.
The state’s Global Warming Solutions Act of 2008 mandates cutting greenhouse gas emissions to 10% below 1990 levels by 2020, and to 80% below 2001 levels by 2050.
Show us the Books
The governor’s July 25 order directed DEEP and PURA to use “the best available information, including such facilities’ audited financial statements and such other financial data that is reasonably requested by [regulators]” in their economic analysis of Millstone.
Matt Fossen, spokesman for the Stop the Millstone Payout coalition, said “it is essential that Dominion fully disclose the plant-level financials of Millstone; otherwise the investigation won’t be truly comprehensive or accurate.”
The coalition — sponsored by competitors Calpine, Dynegy and NRG Energy and the Electric Power Supply Association (EPSA) — had argued S.B. 106 would be a burden on ratepayers and an unnecessary handout to a power plant that had not been proven to be unprofitable.
The group in April released a study by energy consultancy Energyzt that showed the Millstone plant has earned at least $3 billion in profits since Dominion bought it in 2001 and will likely earn an additional $2.2 billion in after-tax income from now through 2030. Dominion spokesman Ken Holt criticized the Energyzt report as “loaded with gross assumptions and preposterous claims, with no real data.” (See Millstone No Dead Weight for Dominion, Says Opponents’ Study.)
New York ZEC Suit Dismissed
The legislation would have made Millstone the only eligible nuclear generator in Connecticut’s competitive bidding process and awarded it a five-year contract if it bid lower than competing renewable resources. The bill would have set an annual limit on nuclear energy purchases at 8.3 million MWh, equivalent to half of Millstone’s output.
The Connecticut measure would have been similar in effect to the zero-emission credit programs that EPSA and its members are contesting in New York and Illinois.
EPSA and its members in Illinois on July 17 filed an appeal with the 7th U.S. Circuit Court of Appeals. They argued they stood to lose millions because the subsidized nuclear plants would suppress capacity and energy prices. The plaintiffs are expected to also appeal the New York decision to the 2nd Circuit.
PJM’s Independent Market Monitor last week filed a complaint with FERC requesting fast-track revocation of the RTO’s decision to exempt a generator from a rule meant to combat market manipulation.
The complaint said PJM was “incorrect” in providing an unnamed generating unit with a competitive-entry exemption from the minimum offer price rule (MOPR).
The RTO developed the MOPR to prevent subsidized units from suppressing market prices by offering bids that are below a unit’s competitive operational costs. The rule creates a price floor at which all new units must offer into the market unless they receive one of three types of exemptions from PJM. The competitive-entry exemption allows a unit to offer in at any bid, provided the generator can prove it receives no direct or indirect subsidies. (See PJM: No Change on MOPR Yet; Remand May Have Little Impact.)
“The stakes in this case are high. This generation is clearly not merchant generation, is clearly not competitive generation and represents exactly the type of subsidized generation that the MOPR was intended to address,” the complaint said.
The complaint asks FERC to rescind the exemption before the generator submits “a noncompetitive offer” into any of PJM’s Reliability Pricing Model auctions. The RTO holds annual Base Residual Auctions for capacity required three years into the future, along with incremental auctions each year leading up to the delivery year.
The Monitor declined to name the exempted generator to avoid disclosing market-sensitive information, but it described it as “a non-regulated company wholly owned by a parent company that wholly owns a regulated, vertically integrated electric utility.” The Monitor told both the generator and PJM that the generator wasn’t eligible for the exemption because it indirectly recovers costs from customers through a non-bypassable charge, according to the complaint.
Because the generator’s construction was financed entirely by the parent, the cost of capital was lower than if the generator’s operating company had sought financing on its own, the Monitor said, and that difference is the cost the generator indirectly recovered from customers through a non-bypassable charge.
However, PJM still granted the exemption.
The Monitor contended that allowing an exemption in this situation “would create a significant loophole” in the MOPR that would render it “ineffective” in similar situations because the unit is not “purely a merchant resource” as the exemption rule requires.
“Competitive market participants who invest in new generating facilities without the backing of a regulated utility or other nonmarket support” receive “essential protection” from the MOPR and would be “inappropriately disadvantaged” by the loophole, the complaint argues.
The issue was amplified by a July 7 decision from the D.C. Circuit Court of Appeals that vacated PJM’s current MOPR provisions and remanded the order back to FERC. Among the topics at issue is one of the three MOPR exemptions, which PJM and its stakeholders had jointly requested that FERC eliminate.
If FERC reverses its position and now decides to approve the request, that would make having an exemption more advantageous and the precedent of an approved loophole more problematic, the IMM said. There would be just two exemption types, and the second — known as the “self-supply exemption” — is very limited.
“This would enhance the need for an effective MOPR and correct application of categorical exemptions to the MOPR,” the complaint argues. “If the requested application of the competitive-entry exemption were approved, it would provide an easy way to avoid the defined limits on the self-supply exemption that applies to regulated utilities and to the utility in this case.”
Southern California Gas Co.’s Aliso Canyon gas storage facility resumed injections Monday, despite Los Angeles County officials’ request that a state appeals court prevent the reopening.
“SoCalGas must begin injections to comply with the [state’s] directive to maintain sufficient natural gas inventories at Aliso Canyon to support the reliability of the region’s natural gas and electricity systems,” the company said in a statement sent to Porter Ranch residents, according to the Los Angeles Times.
Following a series of back-and-forth court rulings over the weekend, the county filed a petition with the 2nd District Court of Appeal for a stay preventing gas withdrawals until more analysis is done. A judge on Saturday ruled that operations can resume.
The volley of court actions occurred after the California Division of Oil, Gas and Geothermal Resources (DOGGR) issued an order July 19 allowing SoCalGas to resume injections into the facility. The county does not object to withdrawals on an emergency basis, which is currently allowed.
Location of Aliso Canyon Storage Facility
The county wants the court to forestall any withdrawals until it can determine whether DOGGR complied with the law in clearing the facility to resume operations. SoCalGas refused the county’s request.
“Before the prohibition on injections can be lifted, SoCalGas must show — and DOGGR must determine — that all necessary steps to ensure the safety of the facility have been completed,” the county said in its original filing in Los Angeles County Superior Court last week. Conditions have not been met regarding a risk-of-failure review and emergency response plan, the county contended.
Withdrawals were halted at the facility following the massive methane release there, detected in October 2015 and finally plugged in February 2016. DOGGR and other state agencies recently issued findings that it is safe to resume withdrawals. (See California Officials: Aliso Canyon Safe to Open.)
The court filing says county officials met with DOGGR and SoCalGas on July 20, when the company refused to refrain from withdrawals and to disclose when they would resume. SoCalGas did not immediately return a request for comment.
Residents near Aliso Canyon still report health problems they say are related to the leak, including headaches, nosebleeds and nausea. A few dozen residents recently protested resuming gas withdrawals in roadside gatherings reported on local news stations.
Aliso Canyon protest | Food and Water Watch
California Energy Commission Chairman Robert Weisenmiller and Gov. Jerry Brown have asked for the state to explore permanent closure, and the California Public Utilities Commission has a proceeding underway that is analyzing whether the facility is needed for system reliability. (See Study to Weigh Aliso Canyon Shutdown.)
On July 19, SoCalGas issued a statement that it has completed the state’s required safety reviews and has implemented a host of safety measures and procedures. The company argues that loss of the facility will create reliability problems in times of severe weather and peak electricity usage.
The county also argues that there is a risk of gas leaks caused by seismic activity in the area, which is prone to earthquakes. “DOGGR and SoCalGas have acknowledged the well-known and very serious risk of a catastrophic earthquake shearing multiple wells at Aliso Canyon,” county officials said.
Although the appeals court did not issue a stay, Deputy County Counsel Scott Kuhn told the Times on Monday that the courts have yet to rule on the county’s request that the state complete their analyses before continuing injections. “We hope that some court will get to the merits and when they do get to merits, they will see that further study of the seismic risk and the environmental risk is necessary before [the utility] can proceed with business as usual,” Kuhn said.
A federal judge on Tuesday dismissed all claims in a suit against New York’s zero-emissions credit program, the second such victory for state nuclear subsidies after a complaint over the Illinois ZEC program was thrown out July 14.
Judge Valerie Caproni of the U.S. District Court for the Southern District of New York granted motions to dismiss the case from the Public Service Commission, the defendant, and intervenor Exelon, owner of the three New York nuclear plants that would receive ZEC payments (16-CV-8164).
“Although no individual state can reverse the trend all by itself, New York and many other states have decided that they will do their part to reduce the emissions that contribute to global warming,” Caproni said. “The issue in this case is whether the method New York has chosen to facilitate its doing so is constitutional. … The court concludes that the New York [ZEC] program is constitutional.”
Her 47-page decision rejected every one of the plaintiffs’ arguments, including claims that the program intruded on FERC’s authority to regulate wholesale prices, and that New York violated the Constitution’s dormant Commerce Clause by favoring in-state generators.
The Electric Power Supply Association (EPSA), which filed the New York challenge with several members, said it will appeal the ruling. “We’ll continue to fight these nuclear bailouts, which cost ratepayers billions, crowd out investments in true renewables, and distort and could eventually destroy the established wholesale power markets,” said David Gaier, spokesman for EPSA member NRG Energy. On July 17, EPSA and its members appealed the dismissal of the Illinois suit to the 7th U.S. Circuit Court of Appeals. (See Illinois Zero-Emission Credit Suit Dismissed.)
Affirmation of CES
Gov. Andrew Cuomo praised Tuesday’s ruling in a statement: “The court forcefully ruled that the Clean Energy Standard (CES) and its zero-emissions credit program are valid tools to use to combat climate change. At a time when the federal government has abdicated its leadership on climate change, New York will continue to do all that we can to ensure that current and future generations have a clean and safe environment in which to live and prosper.”
The ZEC program, initiated as part of the CES last August, requires utilities in New York to procure ZECs that are generated by Exelon’s three in-state nuclear power plants. The PSC claimed that the program helps avoid the closure of the upstate nuclear plants, which the state needs to meet its goal of reducing carbon emissions and having 50% of energy produced by renewable resources by 2030.
Nine Mile Point Nuclear Plant | Constellation Energy Nuclear Group
EPSA, and members Dynegy, Eastern Generation and NRG Energy, joined Roseton Generating and Selkirk CoGen Partners in arguing they would lose millions because the subsidized nuclear plants would suppress capacity and energy prices.
Caproni used colorful language to frame her decision, citing President Trump’s description of climate change as a “hoax” and paraphrasing a famous line from “Romeo and Juliet”: “A rose by any other name still smells as sweet.”
On the plaintiffs’ argument that the ZEC program is directly tied to NYISO’s wholesale markets, Caproni said: “This argument is no more than an attempt to fashion a ‘tether’ by jamming a square peg into a round hole; plaintiffs’ argument rewrites the CES order. The CES order itself does not require the nuclear generators to sell into the NYISO auction.”
The Illinois and New York decisions are the latest in a string of federal court cases testing the boundaries between state and federal jurisdiction over electricity markets.
“Under current law, states have broad authority to advance a cleaner electric grid,” said Ari Peskoe, senior fellow in electricity law at Harvard Law School, who tracks constitutional challenges to state energy policies. “If courts rule against the states on appeal, their decisions might limit the scope of future state clean energy programs.”
At last week’s National Association of Regulatory Utility Commissioners Summer Policy Summit in San Diego, attendees were encouraged to download an app to facilitate in-person meetings. There’s just one problem: Were it subject to the privacy rules adopted by commissions in several states, the app would be in violation.
Murray
Privacy rules prevent electric and gas utilities from selling or disclosing personal information except under certain, carefully monitored circumstances. Customer protections, such as clear notices to users about what data are being collected, are absent from the app. This leads to an embarrassing double standard for some state regulators. While commissioners enjoy the conveniences provided by the “NARUC 2017” app, their own rules would outlaw similar practices in their home states.
For example, take California’s rules. In 2011, the Public Utilities Commission issued a lengthy privacy decision that requires software companies that access customer data held by a regulated utility to provide written privacy policies that are “meaningful, clear, accurate, specific and comprehensive.” But, confusingly, the app links to two privacy policies that are sometimes in conflict with one another. The policies also do not explain what personal information is captured by the user’s mobile device — a clear violation of California’s rules.
Another California requirement is for software companies to distinguish “primary purposes” from “secondary purposes” of the personal data used. A primary purpose could be “to help you save energy and money in your home with tailored recommendations on your smartphone,” while a secondary purpose could be, for example, selling the data to make extra money. Secondary uses are explicitly prohibited without the prior written consent of the customer. Unfortunately, NARUC 2017’s terms say vaguely, “We will collect and use of [sic] personal information solely with the objective of fulfilling those purposes specified by us and for other compatible purposes.” Thankfully, the app’s developer has an agreement with NARUC not to sell any users’ personal data, according to the company’s CEO. But if a complaint were filed in California against a similar app maker, the commission would likely find the software unlawful.
Other commission-approved rules require companies to make informational disclosures to consumers prior to releasing personal data. By standardizing disclosures, the idea is that companies are prevented from writing their own vague or misleading language that exploits customers. For instance, Pacific Gas and Electric’s form for demand response is four pages long, and deviations from the form are not allowed.
Outside of California, Colorado and Illinois regulators have approved standardized disclosure language. But the NARUC 2017 app does not ask for any specific authorization at all, and, when it does, the authorization language is fluid. Both of its policies say that the app maker “may revise these terms of use at any time without notice.” Changing terms without notifying users is anathema to privacy advocates and consumer groups who fought for rules that ban the practice.
Finally, California’s rules enshrined the principle of “data minimization,” the idea that only the personal data necessary for the task should be collected. Presumably, an app to help people at conferences meet face to face would need information like your name, title, organization, location and which sessions you want to attend. However, the NARUC 2017 app requires users to give it permission to much more, such as the right to read and modify any file stored on your device; to create new Bluetooth connections; and to control the phone’s networking settings — none of which are clearly tied to helping people meet at a conference.
It is ironic that many state commissions publicly take a “tough on privacy” stance that is at odds with their national association’s practices at its summer conference. But the double standard is not altogether surprising. Since the advent of smartphones, consumers have routinely traded their personal data for access to free services. Commission requirements for paper forms appear increasingly out of step with modern technology.
Over time, as sharing personal data such as banking transactions and health data with tech companies becomes easier, it is worth re-examining the utility industry’s practices. Is it reasonable to give away the data on your phone with a single click, while your utility bills require filling out a four-page legal form?
To be clear, the NARUC 2017 app would only violate commission rules if it accessed users’ energy information or customer account information held by utilities. Apps that do not request data from a utility operate without commission oversight.
Nevertheless, as leaders in the public sector, state commissioners and their national association should lead by example. Entrepreneurs in software and energy management have a saying: “Eat your own dog food.” It means that entrepreneurs should use their companies’ products in their personal lives, to live by their creed. We encourage NARUC to do so as well.
Michael Murray is president of Mission:data Coalition, a national coalition of more than 40 innovative technology companies that empower consumers with access to their own energy usage data. We strongly believe that energy management technologies can flourish while simultaneously protecting customer privacy. For more information about privacy and state private rules about energy, see our whitepaper, “Got Data?”
NYISO reported Monday that locational-based marginal prices (LBMPs) for June averaged $31.76/MWh, nearly unchanged from May but up 16% from June 2016. Year-to-date monthly LBMPs averaged $36.01/MWh through June, a 20% increase from a year earlier.
In a July 24 Market Operations Report to the ISO’s Business Issues Committee, Rana Mukerji, senior vice president for market structures, said natural gas and distillate prices fell from the previous month but gained 27.5% year-over-year. Natural gas prices at Transco Z6 NY averaged $2.35/MMBtu in June, down from $2.80 the previous month.
Gulf Coast jet kerosene for the month came in at $9.59/MMBtu, down from $10.47 in May, while ultra-low sulfur No. 2 diesel at NY Harbor was $10.14/MMBtu, compared with $10.82. Distillate prices dropped 5.4% from a year ago.
On Capacity Exchange, Probabilistic Method not Better
A new probabilistic method to limit capacity price increases caused by exports from an import-constrained area would complicate the process and offer results no better than the current deterministic method, according to an analysis conducted for NYISO by GE Energy Consulting.
Mukerji shared the analysis from the monthly Broader Regional Markets Report as the latest development arising from FERC’s January acceptance of the ISO’s capacity revisions while rejecting a proposed one-year transition as lacking an “analytical basis” (ER17-446). A NYISO analyst briefed stakeholders on the outlines of the study at the April Business Issues Committee meeting. (See NYISO Provides Update on Capacity Export Concerns.)
Probabilistic Locality Exchange Factor Analysis | GE Energy, NYISO
NYISO proposed the plan last fall to address anticipated price spikes in the capacity market in the Lower Hudson Valley and New York City zones expected after the commission in October allowed a New York plant in a constrained zone to export into ISO-NE. (See FERC Sides with ISO-NE in Capacity Dispute with NYISO.)
The new rules use a locality exchange factor to reflect how much capacity from “rest of state” can replace capacity exported from an import-constrained locality. The prior rules assumed that 100% of a generator’s exports from an import-constrained area must be replaced with generation in that locality.
“The probabilistic method introduces uncertainty and does not give results which differ significantly from the 47.8% found using the current deterministic method,” the analysis said. That figure represents an estimate of the percentage of exports from NYISO zones G-J to ISO-NE that could be expected to be replaced by “rest of state” capacity. NYISO compromised with an 80% figure.
Stakeholder comments on the methodology analysis were due by July 14. FERC in its January order encouraged a robust stakeholder-driven process but said “we cannot accept NYISO’s proposal for a one-year transition based solely on stakeholder support.”
SAN DIEGO — More than 1,000 people attended the National Association of Regulatory Utility Commissioners’ Summer Policy Summit last week. Here’s some of what we heard.
Sunrun CEO Lynn Jurich said that the task for regulators and industry is to figure out what value distributed energy resources bring to the grid, and which business models and rate designs would work best. She said rooftop solar could be connected directly at the utility level to be dispatched when it is needed.
“Too often we are stuck fighting rate designs that appear to slow the growth of the rooftop solar,” Jurich said. “Let’s work together to actually maximize the value of these assets to the entire system.” Solar companies know how to market the technology to consumers, but utilities best know how to integrate the systems in the most efficient way, she said.
NuScale Power Vice President Jack Bailey said that the Nuclear Regulatory Commission is reviewing the company’s small modular reactor design, but it will take 46 months to approve the 12,000-page application. Oregon-based NuScale is the first small modular reactor company to seek approval of the technology. The company filed for approval of its design in January, an effort that took more than 800 people over two years. The 12 50-MW modules — 600 MW in total — are planned to be built on the site of the Idaho National Laboratory, owned by Utah Associated Municipal Power Systems and operated by Energy Northwest.
Asked what the reaction has been from the environmental community, Bailey said, “I would say it’s a mixed bag overall, but we are seeing some support.” He is also hopeful that the federal government will take steps to solve the problem of where to store spent nuclear fuel.
Katrina McMurrian of Nuclear Waste Strategy Coalition said she is hopeful the federal government will revisit the stalled Yucca Mountain nuclear waste disposal site in Nevada. The U.S. Nuclear Waste Fund contains more than $40 billion, accruing interest of $1.5 billion/year, but fee collection has stopped because of a suit brought by NARUC and others.
President Trump proposed to restart Yucca with $100 million in his budget proposal, and $10 million for an interim storage program to a private or federal facility while Yucca is completed.
The Senate last week approved funding for an interim storage site for nuclear waste, but unlike the House of Representatives, did not include money for restarting Yucca. “The hope is to see both sides put something together that they can conference and actually fund both of these priorities,” McMurrian said. Rep. John Shimkus (R-Ill.) has introduced legislation that would set a time limit for NRC to approve Yucca and allows the Energy Department to permit an interim facility while the facility is licensed.
Dipka Bhambhani, communications director of the United States Energy Association, said her group is working with the International Gas Union to support the 27th World Gas Conference in D.C. on June 25-29, 2018. It will be the first time in 30 years that the U.S. has hosted the triennial event, which has been held since 1931, and the first time that the host country is both the largest producer and consumer of natural gas, she told the NARUC Gas Committee. USEA is a liaison to the Energy Department for the conference and is helping to manage communications for the event.
