CARMEL, Ind. — A senior Homeland Security official told MISO employees and stakeholders Tuesday that cyberattacks will escalate in the future and the RTO and its members will be among the prime targets.
Neil Hershfield, deputy director of the U.S. Department of Homeland Security’s Control Systems Security Program, said of the 290 cyberattacks committed by nation-state terrorists that the department investigated in 2016, the energy industry accounted for 59, ranking third in targeted American industries behind critical manufacturing (63) and communications (62).
“Hackers are very interested in what you do,” Hershfield told MISO employees and stakeholders at a May 23 Informational Forum.
The department estimates that by 2020, 50 billion internet-ready devices will be in people’s hands worldwide. “All this adds up to a much-larger attack surface. It’s a long-term threat,” Hershfield said.
The number of sophisticated attacks will climb in the future, he said. “Frankly we anticipate more attacks, as hackers figure out how to monetize them like ransomware attacks,” referencing the international WannaCry ransomware attack, which held encrypted data in exchange for Bitcoin payments. Hershfield also said he believes that the 2015 attacks on power utilities in Ukraine were simply testing grounds for a larger attack. He said trojan malware ― like Havex and Black Energy, which was used in the Ukrainian cyberattack ― were used in most sophisticated industrial control systems attacks in 2014 and 2015.
“You might have to operate in a contested environment someday,” he warned.
The department categorizes cyber threats into three types: small groups or individuals who act out of notoriety or curiosity; criminals and activists that act on revenge or blackmail; and terrorist organizations and nation states with political motives. The government has identified hackers in Russia, China, Iran and North Korea, Hershfield said.
He said companies may have to operate in manual mode while they work to regain computer operations following a cyberattack. But that is not always possible.
“Many of the processes controlled by computerized control systems have advanced to the point that they can no longer be operated without the control system,” Hershfield said. Many of the employees who know how to operate in manual mode have retired, he added. “That’s something to think about.”
Hershfield also said the average company spends 2 to 3% of its information technology budget on cybersecurity, and best-in-class companies spend 8%.
Spear-phishing emails were the most common means of entry identified in the 290 attacks investigated by Homeland Security in 2016.
He said LinkedIn is hackers’ preferred starting point to gain access to work email accounts. “The main reason someone would go after you is access or placement in your organization,” said Hershfield, who advised employees with security access to be on guard, especially when opening emails. “Who here clicks on emails from their bank? I never click on emails from my bank. If I want to do something, I go to the bank’s website myself.” He also admitted that he recently earned low marks because of his Facebook account in a personal cybersecurity assessment. “I had my profile opened to everyone, not just friends,” he said.
Two-Password Authentication
Hershfield urges companies to limit remote access and isolate critical operating systems, recommending that all remote access be routed through a business network that doesn’t hold critical information. He also advised that MISO use a two-password authentication to access a critical control network, meaning one log-in and password for the business network and one for the critical control network.
“Is it less convenient? Yes. Is it more secure? Yes,” Hershfield said.
He also said companies should immediately terminate security access for employees that leave the company, pointing to a former Georgia-Pacific employee in Baton Rouge who remotely accessed computer systems and interrupted operations in February, causing $1.1 million in damage to the paper maker in retaliation for being fired. FBI agents arrived at his home to find a still-active virtual private network connection, Hershfield said. He said MISO and member companies should report control system cyber incidents and vulnerabilities to Industrial Control System Cyber Emergency Response Team by emailing ICS-CERT@hq.dhs.gov or calling (877) 776-7585.
Turbulent spring weather in MISO South and more expensive natural gas contributed to MISO’s highest energy prices since December.
Real-time energy prices averaged $30.03/MWh during April while day-ahead prices averaged $30.77/MWh, the first time prices have exceeded $30/MWh since December. The higher prices were due in part to about $3/MMBtu natural gas, and congestion from forced outages and high load in MISO South, which experienced severe weather and temperatures more akin to expected May levels. Systemwide load averaged 66.9 GW, a slight decrease from April 2016, and peaked at 79.6 GW.
“Operating challenges were few in the Midwest, but for the South, the opposite was true,” MISO Executive Director of Strategy Shawn McFarlane said at a May 23 Informational Forum.
McFarlane said MISO activated emergency procedures a number of times during the month in response to the weather and used its emergency pricing structure on three occasions in the month, one culminating in a maximum generation event on April 4. (See “Several Factors in Spring MISO South Maximum Generation Event,” MISO Market Subcommittee Briefs.)
McFarlane said MISO “successfully balanced supply and demand” during all emergency alerts.
“Fortunately, the actions of our neighbors and members and our own actions in the control room allowed us to navigate successfully through challenging events,” McFarlane said.
The Texas Public Utility Commission last week consented to a staff briefing order that lays out the issues to be considered in SPP and Southwestern Public Service’s joint request (Docket 46901) to determine whether Texas law includes a right of first refusal (ROFR) that overrides FERC Order 1000.
SPP and SPS filed a petition in February asking the PUC to consider whether the RTO can designate entities other than the incumbent utility to construct and own regionally funded transmission facilities in Texas outside the ERCOT service area. (See SPS, SPP Ask Texas to Rule on Transmission Competition.)
Transmission line foundation construction | Plocher Construction
At its May 18 meeting, the commission said the parties must address:
Whether an electric utility or other entity can construct transmission facilities in Texas without first obtaining a certificate of convenience and necessity from the PUC;
Whether the commission has authority under state law to grant a CCN to a utility that will provide only transmission service outside ERCOT; and
Whether SPS has the exclusive right to construct transmission facilities within its certified service area and, if it does, whether it can decline to exercise that right.
The commissioners directed the parties to not take up any issue “relating to the interpretation of a FERC order or tariff,” saying such issues are not within the PUC’s jurisdiction.
The briefs are due June 21, with reply briefs due July 6.
As an incumbent utility operating outside ERCOT, SPS contends the state’s Public Utility Regulatory Act (PURA) gives it a ROFR to build in the service area prescribed by the PUC. That would prevent a potential competitive project under Order 1000.
SPP claims that no such right exists, giving the RTO the ability to solicit and designate transmission-only utilities to construct and operate new transmission facilities within SPS’ service area under Order 1000.
The project in question, the 345-kV Potter-Tolk transmission line in the Texas Panhandle, was pulled from SPP’s 10-year planning assessment in April. SPP’s Board of Directors has directed staff to conduct a congestion study in the area, due within a year. (See SPP Board Cancels Panhandle Line, Seeks New Congestion Study.)
The PUC debated during its previous meeting whether to send the case to the State Office of Administrative Hearings (SOAH). The commissioners eventually agreed the docket could be decided based on written briefs. (See Texas PUC Agrees to Take up SPP, SPS Request on ROFR.)
SPS Rate-Recovery Request Moves Forward
The PUC also revised a preliminary order in SPS’ request to recover the cost of developing two wind farms in West Texas and New Mexico (Docket 46936).
Commissioner Ken Anderson directed staff to include in the order a discussion of the final approval’s effect on the city of Lubbock, which has said it wants to transfer load currently served by SPS from SPP into ERCOT. (See Texas PUC OKs ERCOT, SPP Studies on Lubbock Move.)
“Does it have the potential to create stranded costs that would have to be recovered?” he asked. “If the answer is yes, then the order should include a question about what should be done to eliminate that risk. It seems to me that because Lubbock has already filed to make that move, it shouldn’t be a surprise … that SPS will attempt to argue stranded costs. That issue should be teed up for the commission to consider.”
Anderson also asked SPS and its intervenors to address whether there should be a cap on costs — estimated at $1.6 billion, or about 40% of SPS’ rate base — as the PUC required of a Southwestern Electric Power Co. plant in western Arkansas.
“The truth of the matter is, we don’t know what the cost is going to be. It could result in very substantial increase in the rate base,” he said.
The company has asked the PUC to approve a “cost-reconciliation mechanism” for the period between the wind farms’ commercial operation date and their inclusion in the rate base. SPS has said it “cannot afford to wait eight to 10 months … to begin receiving revenue attributable to the facilities.”
SPS told the commission it hopes to have both wind farms in operation by the end of 2020, allowing it to capture the full federal tax credits. The two projects have a combined capacity of 1,000 MW.
The docket has been referred to SOAH. The Texas Industrial Energy Consumers and Golden Spread Electric Cooperative have intervened in the case.
The meeting was the PUC’s first without Donna Nelson, who retired from the commission May 15 after almost six years as the three-person panel’s chair. (See Texas PUC Chair Nelson Stepping Down.)
Her absence was notable from the start. With Nelson at the helm, Anderson would normally offer motions and Marquez would second them. On Thursday, Anderson had to prod Marquez into offering a motion to approve the consent agenda.
Momentarily flustered, Marquez said, “I’m sorry, that was a little out of order. You have that motion.”
Anderson seconded, and the hearing was underway.
Texas Gov. Greg Abbott has yet to announce a replacement for Nelson. The Texas Legislature’s 85th biennial session ends May 29, which may be delaying the announcement.
CARMEL, Ind. — Both MISO and PJM will attempt second drafts of their respective pseudo-tie requirements after receiving deficiency letters from FERC in response to their initial filings, officials said Tuesday.
MISO Director of Forward Operations Planning Kevin Vannoy confirmed at a May 23 MISO-PJM Joint and Common Market meeting that the two RTOs are working to respond to FERC’s requests for more information.
“Both RTOs are making administrative improvements that were intended for this year, but the commission rejected those, so we are continuing with those filings and continuing to work through the congestion overlap issue,” Vannoy said.
FERC’s May 5 deficiency letter asked PJM to explain how much it worked with MISO on the rules, how its proposed minimum electrical distance impedance was determined and how it will determine whether resources are operationally deliverable (ER17-1138).
MISO Senior Director of Regional Operations David Zwergel said his RTO still agrees that a revised pseudo-tie agreement will allow it to manage pseudo-tie impacts reliably. “It’s not infinite; there’s only so many pseudo-ties that transmission can handle,” Zwergel added.
PJM proposed that pseudo-ties be based on aligned network models from the two RTOs for flowgates and have firm transmission subject to a deliverability analysis similar to one it uses for internal resources. The RTO also proposed that any new flowgate created because of a pseudo-tie must have at least one flexible internal generator with at least a 1.5% impact on the flowgate.
“None of the current pseudo-ties fail this [deliverability] test … so we’re okay so far with that,” said Tim Horger, PJM director of energy market operations. Horger said PJM will again take up deliverability test specifics once double-counting complaints from MISO and PJM market members are resolved. “Once the dust settles from the FERC filings, we’ll work on that. We took a historical look at impacts so far.”
Customized Energy Solutions’ David Sapper asked if the RTO with the most stringent pseudo-tie rules would essentially determine what requirements new and existing pseudo-ties would follow.
“I guess you could look at it that way, but both requirements are going to have to be met,” Horger replied.
Some stakeholders expressed concern that MISO and PJM are still pursuing stricter pseudo-tie rules considering they don’t always bind at the same time on constraints.
Sapper also asked for more detailed Tariff filings from the RTOs on the second pseudo-tie requirement attempts, saying that MISO’s load-serving entities prefer more details, especially because the filings are “uncharted territory.”
Horger also said PJM is still pushing for its first-ever pseudo-tie pro forma agreement, which was debated for months this year before it was put on hold. Horger said if the RTOs agree on future rules laid out in their joint operating agreement, MISO would no longer need to be a signatory to the pro forma, and it could be limited to pseudo-tie owners and PJM. Horger said MISO and PJM staff are currently at work on joint operating agreement language.
However, Horger said PJM still isn’t in a hurry to finalize a pro forma. “We have the whole FERC quorum issue also; I don’t think there’s a rush to get this filed,” he said. The commission has been without a quorum since February, preventing it from taking definitive action on any disputes, including addressing the MISO Independent Market Monitor’s challenge to the pseudo-tie concept. (See Pseudo-Tie Feud Rises as Patton, NYISO Protest PJM Proposal.)
RTOs Closer to Double-Congestion Rebate Program
MISO and PJM hope to implement rebates by September as a stopgap solution to the double-charging of congestion on pseudo-tied units.
The RTOs agree that day-ahead firm flow entitlement exchanges will improve predictions on the effect of congestion on pricing. The day-ahead exchanges between MISO and PJM began in late January.
Vannoy said in a best-case scenario, MISO and PJM can implement the stopgap rebate solution by the beginning of September and implement a longer-term goal of scheduling pseudo-ties in the day-ahead process by next May.
Four Categories for Freeze Date
Joe Rushing, a senior engineer in PJM’s interregional planning division, said the RTOs will continue to pursue a “bucket” approach to revise the current 2004 freeze date for determining eligibility for a share of firm rights on flowgates. The rights would be divvied up based on how long resources have participated in the market. (See “Freeze Date Future in Buckets?” PJM, MISO Go Quiet on Pseudo-Ties; Reach Interface Pricing Accord.)
The RTOs are proposing to add a fourth tranche to include market-wide transfers that align with planning processes. The tranche would be the first in line for a megawatt reduction when firm flow entitlements exceed a flowgate’s capability. The third tranche — which allows for entitlements to be granted for limited market-based transfers for reliability within the RTO balancing authority — will end after 10 years.
The first bucket will continue to be used for active designated network resources predating the current April 1, 2004, freeze date and historic transmission service requests, which will be given first consideration for flowgate needs. A second tranche would be for active designated network resources and transmission service requests after 2004.
Rushing said the RTOs will draft Tariff language for a FERC filing sometime in the third quarter.
The rush to build new generation in PJM might be over, if analysts are correctly reading the tea leaves of yesterday’s PJM capacity auction results.
Base Residual Auction prices for Delivery Year 2020/21 fell to $76.53/MW-day in most of the RTO, down from $100 last year. ComEd dropped to $188.12 from $202.77, and MAAC, which cleared with the RTO at $100 last year, dropped to $86.04.
The only areas that saw price increases were EMAAC, which jumped to $187.87 from less than $120 last year, and Duke Ohio-Kentucky, which cleared at $130 this year after pricing with the RTO last year. (See Capacity Prices down in Most of PJM in 1st Year of 100% CP.)
“The silver lining here appears to be a meaningful slowdown in new capacity clearing the auction,” UBS analyst Julien Dumoulin-Smith wrote in a note published Wednesday. “While it’s been years that many generators have been speculating on just when the flow of new units would slow, this appears it.”
| PJM
Less than 3,200 MW of new generation and uprates offered and just 2,824 MW cleared. Both results are down approximately 50% from last year’s auction. Clearing prices for 2020/21 ranged from only 26 to 66% of the net cost of new entry.
“To this end, we see the latest capacity prices and challenges in the debt markets as stymying any future efforts despite a clear backlog of future proposed plants,” he wrote. “We believe the market for new capacity is largely exhausted.”
Capitalizing on cheap fuel caused by an abundance of production in the Marcellus and Utica shale plays and pipeline constraints that limited takeaway capacity, developers flooded the market in recent years with new, highly efficient gas units that have depressed capacity and energy market prices. Low fuel prices persist, but the spark spread might not be as attractive anymore.
“I don’t see any economic justification for bringing a new power plant online” in these market conditions, ICF’s George Katsigiannakis said in an interview. “You start questioning what was driving all those builds: it was economics or it was just irrational expectations?”
Going forward, he said, “the market is going to rationalize and provide better returns,” but that will require unit retirements to reduce the excess capacity. With the onset of governmental initiatives to save certain units for socio-economic reasons, such as the zero-emissions credits passed last year in Illinois, and promote construction of others, such as renewable energy credits for solar and wind projects is several states, Katsigiannakis said “one of the most important issues” is how the oversupply will be curtailed.
“The intervention of state policies on the capacity market … how they can do it so they will not break down the market, is a different question,” he said.
Dumoulin-Smith agreed that he doesn’t “see any obvious easy fixes to improve prices” and that retirements appear to be a waiting game.
“The question is increasingly when will retirements materialize given the lower prices? We think any number of large legacy coal plants could see further pressure in [Pennsylvania and Ohio],” he wrote. “Even fully compliant larger plants could be at very clear risk across any part of the RTO footprint.”
He identified Talen Energy’s Susquehanna nuclear plant and Exelon’s Three Mile Island — which failed to clear the last three auctions — as potential casualties. He said Dynegy’s and FirstEnergy Solutions’ generation also is at risk.
Alternatively, he saw Public Service Enterprise Group, Calpine and Exelon as potential winners from the BRA, with their units concentrated in the higher-clearing locational deliverability areas.
Katsigiannakis said the “big surprise” was how much demand response was able to hang on despite the increased commitment demands of 100% Capacity Performance. He had expected DR to drop by about half from 10,348 MW to approximately 6,000, as that’s how much had year-round capability in last year’s auction. Instead, 7,532 MW cleared.
He said he’ll need to analyze the situation further to understand why so much additional DR was able to clear.
WASHINGTON — Pennsylvania regulator Robert Powelson and Neil Chatterjee, senior energy policy adviser to Senate Majority Leader Mitch McConnell (R-Ky.), received a mostly friendly reception Thursday at their Senate confirmation hearings to fill two Republican vacancies on FERC.
Aside from several interruptions by anti-pipeline activists, the two-hour hearing before the Senate Energy and Natural Resources Committee was largely uneventful with no obvious stumbles by the nominees nor attacks by senators.
The tenor of the hearing suggested Powelson and Chatterjee should have no problem winning confirmation in the Republican-controlled Senate to restore the commission’s quorum, which was lost in February with the resignation of former Chairman Norman Bay.
Powelson and Chatterjee, who are seeking terms expiring in 2020 and 2021, respectively, testified along with Dan Brouillette, President Trump’s nominee to be deputy secretary of energy.
Each nimbly tap danced in response to questions on senators’ pet concerns — favored Department of Energy labs, pipeline and hydro projects, state incentives to save nuclear generation, the fate of the Yucca Mountain nuclear waste depository — promising to consider the issues but not committing themselves to positions.
Chair Lisa Murkowski (R-Alaska) pledged at the end of the hearing to bring the nominees to a committee vote quickly after they answer any written questions from the senators. “My hope is to be able to advance your names quickly, along with that of [nominee for Interior Department deputy secretary, David Bernhardt], so that we can process these nominees for the FERC, for DOE, for DOI and allow the business to proceed.”
Mild Tone
The mild tone of the questions was a stark contrast to the grilling Bay — a Democrat and former prosecutor — received at his confirmation hearing in 2014, when Republicans attacked his record as chief of FERC enforcement. (See LaFleur Cruises, Bay Bruises in Confirmation Hearing.)
That’s not to say the hearing was devoid of partisanship.
Murkowski blamed Bay for resigning and former President Obama for refusing to fill Republican vacancies on the commission last year (by some accounts, a response to the Senate’s refusal to consider Supreme Court nominee Merrick Garland). “As a result of those factors, this is the first time in 40 years that FERC has lacked a quorum,” she said.
Sen. Al Franken (D-Minn.), sitting in for ranking member Maria Cantwell (D-Wash.), countered that Bay had informed the Trump transition team he would resign if replaced as chair. He noted it took Trump three months to name nominees.
Franken also took the opportunity to criticize Trump’s proposed Energy Department budget cuts and its rollback of the Obama administration’s clean energy and climate policies.
“Both the Department of Energy and the Federal Energy Regulatory Commission can play a key role in the clean energy revolution, or they can hold us back while our international competitors reap the rewards,” he said. “That is the prism through which I will consider the nominees that we hear from today.”
Later, in response to Franken’s question about what needs to be done to allow distributed energy technologies to participate in the markets, Chatterjee pledged: “I’m in favor of markets. I’m in favor of competition. And I’m in favor of technology, particularly technologies of interest to consumers.”
Climate Change Question
Sen. Tammy Duckworth (D-Ill.) asked the nominees whether they believed in manmade climate change.
“I’m not a climate denier,” Powelson responded, adding that “market-based solutions” were adding natural gas and renewables and reducing carbon emissions in Pennsylvania.
Chatterjee — who was central in McConnell’s fight against the EPA Clean Power Plan — said he would insist that any policy to cut carbon emissions not undermine the grid. “The first issue at FERC is to oversee reliability. I think that any policy … that seeks to mitigate carbon emissions, we have to ensure that it not have a negative impact on reliability,” he said.
“The climate is changing and we’re all living here, so it must have some impact,” Brouillette said.
Duckworth also asked the FERC nominees for their position on state energy initiatives, such as Illinois’ zero-emission credits for nuclear plants.
“I’m a state’s rights individual,” said Powelson, adding that “nuclear power is part of our energy mix and we’re going to need it.”
Chatterjee also promised, “I believe in states’ rights.”
Sen. Joe Manchin (D-W.Va.) made his case for a continued role for coal in the nation’s generation portfolio, saying it is an essential part of “baseload power. “All that we’re asking for is a proper mix,” he said. “I’m being told by the utility companies the proper mix isn’t being enforced because of certain conditions and certain requirements that the previous FERC has put on them.
“There’s going to be a fuel of the future, I’m sure in 10 to 20, 30 years from now,” he continued. “But right now we have to use — in the cleanest fashion we can — what we have that we can depend on.”
Responding to Sen. Martin Heinrich’s (D-N.M.) question about the commission’s role in transmission development, Powelson said if confirmed, he wanted to “immediately sit down with our regional transmission organizations and independent system operators and see where the bottlenecks are, what’s working and what’s not working.”
PURPA
Sen. John Barrasso (R-Wyo.) asked the FERC nominees for their views of the Public Utility Regulatory Policies Act, passed in the aftermath of the 1973 oil crisis.
Powelson called PURPA “a 1978 vintage document. It was addressing a scarcity issue … and the generation mix has changed today.” He promised to look at “what’s working with PURPA and what’s not” if confirmed.
“But I say this respectfully, a Congressional review of PURPA — a PURPA 2.0 doctrine — might be part of a potential energy bill.”
Chatterjee echoed Powelson’s sentiments. “Any major changes to PURPA would be made by Congress, and while you have my assurance I would work very seriously on this issue should I be confirmed, I think any major changes need to come from this body and not from FERC,” he said. (See related story, PURPA Critics Call for Reforms.)
Paths to FERC
Powelson, a member of the Pennsylvania Public Utility Commission, is the current president of the National Association of Regulatory Utility Commissioners. “What I learned from my experience at NARUC is what works in Pennsylvania might not work in other jurisdictions and the proud appreciation we each have for our individual states’ rights in supporting our states’ energy policies,” he said in his opening remarks.
Chatterjee, a former lobbyist for the National Rural Electric Cooperative Association, became McConnell’s energy adviser in 2011 after working for two years as a staff aide for the coal state senator. Noting the tradition of bipartisanship and consensus at the commission, he touted his ability to compromise with Democratic senators in pushing through legislation.
“We call Neil ‘the Boxer whisperer’ in my office — a term of endearment, I assure you,” McConnell told the committee in his introduction, referring to Sen. Barbara Boxer (D-Calif.). “His work was key in forging alliances between Sen. Boxer, myself … and others that ultimately resulted in bipartisan agreement.”
Franken said Trump should quickly fill the remaining Republican vacancy and nominate a Democrat to replace Commissioner Colette Honorable, who announced she would not seek a new term when hers expires in June.
Numerous reports have identified Kevin McIntyre, co-head of the energy practice at law firm Jones Day, as the third Republican nominee and likely chairman.
“It is important that we restore the quorum at this commission. But it is equally important that the president nominate two more members to fill the remaining vacancies — one a Democrat, and one Republican — and maintain the party balance that the law requires,” Franken said.
The hearing was interrupted several times by protesters from environmental group Beyond Extreme Energy, who chanted “FERC hurts families” and “Shut FERC down.” The group has used the same modus operandi to disrupt FERC open meetings.
Police removed and arrested four protesters, including Lee Stewart, who had tied himself to a chair and had to be carried out along with it. One demonstrator left behind a noisemaker that filled the hearing room briefly with a piercing shriek until it was removed. “Until Congress investigates the agency’s abuses of power and law, the Senate must not approve new FERC commissioners,” the group said in a statement.
At the end of the hearing, Murkowski praised the nominees’ young children, who sat with their mothers in the front row. “You’ve been extraordinarily well behaved,” she said in an apparent dig at the protesters. “I think you set a fine example for grownups.”
We all follow Elon. (He’s ubiquitous.) Tesla buys — or bails out — SolarCity to create an even grander vision of integrating electric cars, solar panels and batteries.
Huntoon
Next will be Tesla/SolarCity buying SpaceX so the integrated electric cars, solar panels and batteries can be transported to those new Martian communities. All aboard![1]
I wrote before about why Elon’s Powerwall home battery made no sense.[2] Remember Elon saying he had 38,000 orders for the Powerwall 1, with installations to begin in October … of 2015? And announcing a new version, Powerwall 2, last year with twice the specs — but at twice the cost?[3]
What is Tesla actually delivering? From Tesla’s first-quarter 2017 letter to shareholders: “In Q1, we installed 60 MWh of energy storage, including a 52-MWh storage project for Kauai Island Utility Cooperative (KIUC) in Kauai, Hawaii.”
So subtracting the Hawaii project using utility-scale Powerpacks, Tesla installed 8 MWh of Powerwalls and other Powerpacks. If the 8 MWh was all Powerwalls, then worldwide sales of the Powerwall were 571 (8,000 kWh divided by 14 kWh per Powerwall).
That is a pittance.
There’s also a huge reality gap for the combined Powerwall/Powerpack business. In August 2015, Elon said revenue in 2017 for this business would be “probably at least a few billion dollars.”
From Tesla’s first-quarter 10-Q we can determine that its Powerwall/Powerpack gross revenues were $5.244 million. Annualized: $21 million.
Tesla Powerwall on house | Tesla
That’s less than 1% of what Elon claimed they would be two years ago. Maybe the first quarter was anomalous. Maybe not.
The fundamental problems with the Powerwall bear repeating.
As a backup generator, the Powerwall is uneconomic and impractical relative to conventional backup generators. Tesla quietly abandoned the backup version of the Powerwall because it made no sense relative to conventional backup generators.[4]
As a cycling generator, there is no value added where net metering is available, because net metering effectively provides storage for free. Rightly or wrongly, net metering remains widespread in the U.S.
Elon acknowledged the value problem in 2015 in explaining why SolarCity wouldn’t offer the cycling version of Powerwall 1. As Bloomberg headlined in May 2015, “Tesla’s New Battery Doesn’t Work That Well With Solar.”
But later, to justify Tesla buying SolarCity, Elon reversed course, saying battery plus solar is a match made in heaven. Confused? So was I.
Powerwall 2, with or without solar pairing, continues the intractable problem of one foot in the canoe, and one foot in the boat.
As a backup generator, it is uneconomic and limited relative to conventional backup generators.
As a cycling generator with solar, it is uneconomic in comparison with net metering that effectively provides storage for free.
At the end of the day, Powerwall 2’s only hope is the demise of net metering … the net metering that the SolarCity business needs to survive.[5]
Isn’t it ironic?
[Editor’s Note: RTO Insider offered Tesla an opportunity to respond to this column on May 15. Although a company spokeswoman claimed the column contained “multiple inaccuracies” the company had not provided any rebuttal as of deadline.]
Steve Huntoon is a former president of the Energy Bar Association, with 30 years of experience advising and representing energy companies and institutions. He received a B.A. in economics and a J.D. from the University of Virginia. He is the principal in Energy Counsel, LLP, www.energy-counsel.com.
[1]We may want to await proof of concept. As Elon said: “I’d like to die on Mars. Just not on impact.”
Speaking of proof of concept, Elon’s latest and greatest is “Neuralink,” which involves implanting electrodes in the brain to enable communication with computers. My immediate reaction: When you think about the damage hackers can do to your computer, imagine what they can do when they hack into your brain. How much bitcoin ransom is that going to cost?
[3]Speaking of cost, here’s a fun question: What costs more, a Powerwall or the equivalent capacity in rechargeable “D” batteries (yes, those flashlight batteries)? If you answered the D batteries, congratulations. A Powerwall is $6,200 (without installation) with 13.5 kWh of capacity. Rechargeable NiMH D batteries have 11.4 Wh, so it would take 1,184 of them to provide 13.5 kWh of capacity. At $5 per battery, the total cost is $5,920.
[4]Tesla continues to promote the Powerwall as providing cycling and reliable backup power even though it is inherent in cycling that the battery will be partially or fully discharged most of the time. And even if fully charged when a utility outage occurs, the battery supply is of limited duration — unlike natural gas backup generators.
And here’s something to check out: On the order-your-Powerwall page here, https://www.tesla.com/powerwall#design, you can select a two-bedroom home using 20 kWh/day. For the option of supplying the entire home for one day, Tesla recommends one Powerwall. How does a battery with 13.5 kWh maximum usable capacity supply 20 kWh? It must be magic.
Not to mention that just the air conditioner for a two-bedroom house of maybe 1,500 square feet is going to exceed the 5-kW continuous rating of one Powerwall. More Musk magic I suppose.
Texas regulators’ decision on the applicability of state and local right of first refusal (ROFR) laws could influence the selection of who builds more than 20 projects proposed for MISO’s 2017 Transmission Expansion Plan, RTO officials said last week.
MISO has no opinion on whether Texas has a ROFR, but it realizes the outcome of the case will affect next year’s competitive developer selection process, Manager of Competitive Transmission Brian Pedersen told the Planning Advisory Committee on May 17.
The Public Utility Commission of Texas is considering a joint request by Southwestern Public Service and SPP to rule on whether Texas statutes allow ROFRs in areas of the state outside of ERCOT’s footprint (46901). (See Texas PUC Agrees to Take up SPP, SPS Request on ROFR.) SPP claims Texas statute only allows for certificates of convenience and necessity inside ERCOT and says other areas should follow a competitive selection process. SPS, on the other hand, argues for the existence of a ROFR outside ERCOT. The Texas PUC will decide the case on briefs without hearing.
Entergy Texas has submitted 22 possible projects for evaluation and inclusion in MTEP 17, ranging from $300,000 to $47 million, and East Texas Electric Cooperative has submitted seven ranging from $900,000 to $62.5 million. MISO will not make MTEP 17 draft project recommendations until August.
Although federal ROFRs were abolished with FERC’s Order 1000, state and local ROFRs were left standing. Upgrades to existing facilities also are assigned to incumbent transmission owners.
Last year, the lone market efficiency project in MTEP 2016 — the $80.9 million Huntley-Wilmarth 345-kV line in Minnesota — would have been opened to competitive bidding save for the state’s ROFR statute. At the time, some stakeholders wrote a letter encouraging MISO to open the project to bidding. (See MISO Board Approves MTEP 16’s $2.7B in Tx Projects.)
Higher Cost Threshold for Competitive Projects?
Meanwhile, stakeholders in MISO’s Competitive Transmission Task Team are debating if the RTO should raise the $5 million cost threshold for opening market efficiency projects to competition. (The RTO’s threshold for opening multi-value projects to competition is four times higher at $20 million.)
MISO staff posed the question to stakeholders at the May 19 task team meeting, saying inexpensive projects might not attract many bidders or justify the cost of a lengthy evaluation and selection process. Staff imagined a scenario where the RTO would run up a $1 million-plus bill evaluating a dozen or so bids on a mere $5 million market efficiency project.
MISO spent $1.3 million last year to evaluate 12 construction bids in its first competitive transmission process, recovering the entire amount from the submitting developers. (See MISO’s Competitive Tx Evaluation Costs $1.3 Million.)
LS Power’s Sharon Segner said MISO’s concern that lower-cost competitive projects would attract too few bidders to justify a costly, full evaluation process would resolve itself because the RTO’s cost to evaluate just a few bids would be much smaller than sizing up a dozen or so bids. MISO could also forego the cost of evaluation altogether if it received just one bid response from an incumbent developer, Segner said. LS Power won MISO’s first competitively bid project with a $49.8 million proposal for the Duff-Coleman 345-kV transmission project.
Pedersen said he has heard arguments for and against a cost floor from stakeholders.
“There are 48 competitive developers in MISO right now, and we trust they can make decisions on whether to bid for themselves. We were just generally asking stakeholders because there was a concern over the evaluation cost. [Stakeholders] raised that issue from an efficiency standpoint, but if developers want to decide what’s best and [decide against a minimum cost floor], that’s fine too,” Pedersen said.
Stakeholders also discussed whether developers should be able to recoup from ratepayers the costs of submitting bids. Some said the issue should be left to FERC while others said states govern what types of costs developers may recover from ratepayers.
MISO is asking for feedback on how to improve its competitive developer process in the hopes of presenting draft Tariff revisions by July. The RTO agreed in December to consider improvements after it announced the Duff-Coleman developer. (See LS Power Unit Wins MISO’s First Competitive Project.)
Staff of the New York Public Service Commission said Thursday that the state’s utilities have 41 GW of capacity for the summer, more than enough to meet a projected summer peak of 33.2 GW.
| NY Dept. of Public Service 2017 Summer Preparedness Report; May 18, 2017
“We have plenty of reserves, and prices are going to be moderate,” Mike Worden, director of the office of electric, gas and water, said in delivering the New York 2017 Summer Preparedness Report at the commission’s May 18 meeting.
The report forecast capability this summer to be 123.6% of demand. The total capability requirement, including the 18% installed reserve margin, is 39,150 MW.
Commissioner Diane Burman asked Leka Gjonaj, chief of bulk electric systems, if the peak load forecast would change if the economy grew more than expected. He replied that NYISO includes econometrics in its forecasts and they would adjust those values to reflect higher growth rates if necessary.
| NY Dept. of Public Service 2017 Summer Preparedness Report; May 18, 2017
“Peak loads continue to decline, and while we can’t line up the reasons one-on-one … we can point to several things that have contributed to it,” Worden said. “Contributing factors include more energy efficiency, more conservation and more distributed generation, and the positive REV [Reforming the Energy Vision] policies that the commission has enacted over the last three years.”
A three-judge panel for the D.C. Circuit Court of Appeals on Friday reversed a 2015 decision by FERC that prevented a Washington state generating plant from recouping funds from the Bonneville Power Administration even though the commission had ruled that it was entitled to the money.
In 2008, FERC had invoked Section 205 of the Federal Power Act to order TNA Merchant Projects, owner of the 520-MW Chehalis natural gas-fired generator, to refund a portion of the rates it had charged BPA for providing reactive power service. FERC had concluded that Chehalis’ rates were not just and reasonable.
Chehalis Generating Facility | Pacificorp
“Several years later, FERC had second thoughts,” Senior Judge Harry Edwards said in the opinion (TNA Merchant Projects vs. FERC, No. 13-1008). “It determined that Chehalis should not, after all, have been required to pay these funds and held that Chehalis ought to recover funds with interest.”
But BPA, the customer to whom Chehalis had paid the refund, had no interest in voluntarily returning the money. Chehalis sought relief from FERC, seeking an order requiring repayment.
“FERC, however, in a perplexing decision, held that it could not order recoupment because the commission’s refund authority does not extend to exempt public utilities such as the intervenor Bonneville,” Edwards wrote, in an opinion joined by Senior Judge David Sentelle and Judge Nina Pillard.
“We hold that FERC erred when it held that it lacked the authority to grant the order requiring recoupment,” the court said. Section 309 of the Federal Power Act permits FERC to “perform any and all acts … [as may be] necessary or appropriate to carry out [the act’s] provisions,” the court said.
The FPA “clearly affords FERC the authority necessary to make Chehalis whole,” the court said. FERC has considerable latitude “when it is prescribing remedies for violations of the FPA and attempting to undo harms caused by its own mistaken or unlawful acts,” the court said.
The court remanded the case back to FERC to determine whether it should “apportion” its recoupment order. “FERC amply explained why recoupment is justified in this case, but in assessing the equities, the commission did not consider whether something less than full recoupment might be warranted,” the court explained.
TNA sold the Chehalis plant to PacifiCorp in 2008 but retained the right to litigate the case.
2005 Rate Filing
The case had its genesis in 2005, when Chehalis filed a proposed rate schedule for providing BPA with reactive power service. In April 2008, FERC concluded that Chehalis’ rates were excessive and ordered it to make refunds to BPA for billings from August 2005 through September 2006, approximately $2 million.
FERC changed course in October 2013, saying that “its precedents on this point had not been entirely clear and thus stated that its determination … was a prospective policy, inapplicable to Chehalis,” the D.C. Circuit said.
In a July 2015 rehearing order, FERC said it believed that recoupment would be appropriate because “Chehalis should not be penalized given the need for clarification” of its policies on reactive power. FERC went on to conclude — incorrectly, the court held — that while it would be “appropriate” for Chehalis to recoup the funds, FERC lacked authority to order BPA to pay.
A BPA spokesman said it was reviewing the order to determine whether to seek rehearing.
“In the meantime, it is worth noting that FERC’s original ruling that the charged rate was unjust and unreasonable was never challenged and has not been overturned,” spokesman Mike Hansen said. “BPA estimates that the rate in question was over 250% of what a just and reasonable rate should have been. If the court’s ruling stands, the matter returns to FERC to ‘balance the equities’ between Bonneville’s rate payers … and TNA Merchant.”
