After years of inactivity on the topic, MISO’s Steering Committee is directing the Market Subcommittee to re-examine whether the RTO should create a process to compensate resources for energy delivered during a system restoration event where the real-time market has ceased to function.
Steering Committee members made the decision during a July 25 conference call. The Market Subcommittee will host discussion on the topic at future meetings.
Reliability Subcommittee Chair Bill SeDoris brought the issue forward for assignment by the Steering Committee, saying the time is ripe to create a pricing structure for energy used to restore the system from blackout conditions. The RSC pointed to MISO’s declining reserve margin, its tendency to enter more emergency conditions and FERC’s possible future rulemaking to promote resilience.
“This issue is key to compensation for the ultimate act of resilience: the restoration of the bulk electric grid,” the RSC said in its submittal.
SeDoris said the need for a restoration power price was raised in stakeholder meetings as far back as 2012. In 2015, the project was added to the Market Roadmap with low-priority status and has since been in “parking lot” status, the term MISO gives to low-priority market improvements that are on hold. During this year’s June meeting to kick off the Market Roadmap ranking process, SeDoris urged the RTO to resume work on the project. (See MISO Stakeholders to Rank Market Improvement Ideas.)
“It’s always been low priority … but given all the talk around resilience and reliability, the time is right to get this in front of stakeholders again,” SeDoris said, adding that it would be unfortunate if MISO and its members were to face a blackout without a restoration pricing mechanism in place.
Consumers Energy’s Jeff Beattie asked if LMP would provide a pricing framework for restoration energy.
The RSC said day-ahead and real-time markets will not be running during a restoration event because the MISO system will be broken into multiple islands with “widespread blackouts and loss of contiguousness.”
“There are no markets if the system is black, and the markets don’t start back up until the system is stable,” SeDoris explained.
SeDoris also said restoration compensation would differ from MISO’s existing black start services definition because black start resources derive their revenues from the capacity they provide, not MISO’s energy market. Black start generators are those able to restore electricity without using an outside electrical supply.
While SeDoris agreed with other Steering Committee members that utilities will be naturally incentivized to restore service and that the probability of reaching a system restoration event is extremely low, he contended that having no compensation rules could make a bad situation worse. Other Steering Committee members had said MISO could sort through the details of compensation once it recovered from total blackout.
“There’s nothing out there to say, ‘We pay $1,000/MWh or cost of new entry,’” SeDoris said, throwing out examples. “How would we end this? Are we looking at litigation?”
American Electric Power on Friday announced it is canceling its proposed $4.5 billion Wind Catcher Energy Connection project, one day after receiving a negative ruling from the Public Utility Commission of Texas.
The PUC on Thursday denied AEP subsidiary Southwestern Electric Power Co.’s request to acquire a 70% interest in the project, which was scheduled to be completed in 2020 to take full advantage of the federal production tax credit.
AEP had said Wind Catcher would save customers of SWEPCO and sister company Public Service Company of Oklahoma (PSO) more than $7 billion over 25 years. PSO would have owned the remaining 30% share.
“We are disappointed that we will not be able to move forward with Wind Catcher, which was a great opportunity to provide more clean energy, lower electricity costs and a more diverse energy resource mix for our customers in Arkansas, Louisiana, Oklahoma and Texas,” AEP CEO Nick Akins said in a statement.
Wind Catcher included a 2-GW wind farm,to be built by Invenergy on 300,000 acres in the Oklahoma Panhandle, and a 360-mile, 765-kV transmission line from the facility to Tulsa, where it would have been connected to the PSO and SWEPCO grids.
| AEP
FERC and Arkansas and Louisiana regulators had already approved the project. The Oklahoma Corporation Commission had yet to issue a ruling, but had also expressed concerns.
Saying the project’s costs placed an undue burden on SWEPCO’s Texas ratepayers, the PUC rejected an administrative law judge’s proposal for decision (PFD) on the utility’s request for a certificate of convenience and necessity to participate in the project (Docket No. 47461).
“I don’t believe I could approve the PFD, because I don’t believe it provides sufficient safeguards for the ratepayers,” said PUC Chair DeAnn Walker. “The costs are known. The benefits are based on a lot of assumptions that are questionable.”
PUC Chair LeAnn Walker (center) discusses the Wind Catcher decision with Commissioners Shelly Botkin, Arthur D’Andrea. | PUCT
“They’re asking us for $4.5 billion in taxing authority against the people of Texarkana and Longview,” Commissioner Arthur D’Andrea said during the PUC’s open discussion, referencing the major cities in SWEPCO’s East Texas footprint.
“It’s one thing when the story is, ‘We need this generation to go forward,’” D’Andrea said. “But when the question is, ‘We don’t need it, and we think it will lower the rates, and we think it’s a good deal and it’s a financial play.’ … You have a burden to show the taxpayers and businesses of Texarkana and Longview really have something to gain from that. I don’t think [SWEPCO has] met that burden.”
Settlement Unlikely
The PUC in May approved a 478-MW wind farm for Southwestern Public Service, following a settlement agreement between SPS and various parties. (See Texas PUC Issues Final Order for SPS Wind Farm.)
SWEPCO was never able to reach a settlement with its intervenors.
“The only reason it worked in the SPS case was because everyone agreed to [customer protections],” Walker said. “We don’t have that situation here, where everyone could agree to what I believe are reasonable conditions.”
Thompson & Knight attorney Rex VanMiddlesworth, who represented the Texas Industrial Energy Consumers trade group, said SWEPCO’s “unnecessary $4.5 billion investment of ratepayer money” was built on a series of improbable assumptions that included $4.75/MMBtu gas prices in 2021, a federal carbon tax by 2026 and the cancellation of most other wind projects in SPP’s interconnection queue. The Energy Information Administration predicts Henry Hub gas prices will be $3.66/MMBtu in 2021, not reaching $4.75/MMBtu until 2046.
Rex VanMiddlesworth presents the TIEC arguments | PUCT
VanMiddlesworth also said Wind Catcher was “burdened” by the $1.6 billion generation tie across Oklahoma.
“That made the project 40% more expensive to construct than other wind projects, while delivering 8% less energy,” he told RTO Insider. “The commission properly found that this was not a risk that should be imposed on Texas ratepayers.”
During AEP’s quarterly earnings conference call Wednesday, Akins seemed prepared for what might come, telling analysts that the company’s “first signal of 2021 capital budgets” assumed no Wind Catcher expenditures.
Akins said Wind Catcher was incremental to AEP’s base plan, which supports 5 to 7% growth in transmission and other investment among its regulated companies.
“If Wind Catcher were not to happen, there would still be opportunities for those kinds of resources to be applied to our resource plans in [the Wind Catcher] states,” Akins said. “Obviously, we don’t want to miss the opportunity for Wind Catcher because it’s a great way to deal with the resource plans in all of those states at one time, rather than independently with perhaps less efficient projects.”
Akins likened AEP’s situation to being in a football field’s red zone, “with time running out, 3rd down with two plays to go, needing a touchdown, with both plays already called. They’re called Texas and Oklahoma.”
The Texas play resulted in a sack, though, and time ran out.
MILWAUKEE — Middle America could significantly decarbonize over the next three decades, but today’s actions and investment decisions and future public policy will be critical to meeting that goal, says a new report by a diverse group of regional energy experts.
The report by the Midcontinent Power Sector Collaborative (MPSC) says the midcontinent electricity sector could “substantially decarbonize by midcentury,” possibly reducing CO2 emissions by 80 to 95% from 2005 levels using existing technology. Entitled “A Road Map to Better Energy,” the analysis was released at a July 24 conference hosted by the Great Plains Institute and the MPSC, a group of regulated utilities, generation and transmission cooperatives, merchant power providers, environmental organizations, and regulatory agencies.
“That’s a really, really critical finding,” Jeff Deyette of the Union of Concerned Scientists said of the carbon reduction potential. “We should be saying that loud and a lot, especially to those that are” doubters.
Great Plains Institute CEO Rolf Nordstrom praised the group for tackling such a contentious subject. He said the roadmap is especially important considering the diverse interests of the group’s members.
“The truth is the world is lousy with roadmaps. Who put this one together is important,” he said. “In today’s environment, where the public discourse can be so fractured and groups can talk past one another … it seems all the more important to note that — it’s in the name — this group is so collaborative,” Nordstrom said.
In the study scenarios in which carbon emissions fall to either 80% or 95% below 2005 levels, the midcontinent region would shift further from coal-fired generation, with no new coal capacity built even when considering carbon capture technology.
In a 95% reduction scenario with low natural gas prices and moderate renewable prices, the 2050 resource mix becomes nearly all wind generation and natural gas with carbon capture technology. With low renewable costs and moderate gas prices, wind dominates with slightly more solar participation. Nuclear generation remains largely static in both cases.
“The key finding is the region can do this,” said Franz Litz of the Great Plains Institute, adding that in California, solar and wind don’t complement each other well, whereas in the midcontinent, the two renewable resources have a more symbiotic relationship.
In a business-as-usual study model that included combinations of either moderate gas prices/low renewable costs or low gas prices/moderate renewable costs, the MPSC found that carbon emissions drop from about 500 million metric tons of carbon dioxide equivalents (MMT CO2) in 2016 to slightly less than 300 MMT CO2 by 2050.
MISO’s current generation mix consists of 77% natural gas and coal, with 18% non-emitting resources.
Policies?
The group said that despite regulatory uncertainty and the demise of the Clean Power Plan, it expects “substantial decarbonization will ultimately be required of the sector.”
Deyette said polices are needed to accelerate the transition: “We’re just not going to get there on the current voluntary choices of the utilities,” he said.
Consultant Judi Greenwald, who once served as an adviser on climate change to Energy Secretary Ernest Moniz, pointed out that even today’s natural gas boom was nudged along beginning in the 1970s with generous government subsidies that encouraged research and development into extraction.
“It may look like market forces, but it has its roots in a mix of technology exploration and public policy,” Greenwald said.
The Lost Study
Greenwald pointed out that the U.S. itself released a study on decarbonizing by 2050 in November 2016 as a component of the Paris Agreement on climate change.
“Maybe you missed it — there was a lot going on that month,” Greenwald joked.
The paper, “United States Mid-Century Strategy for Deep Decarbonization,” is no longer available on the White House website, but a version can be found on the U.N. website. It charts a threefold strategy for decarbonization: transforming the energy system, sequestering carbon and reducing non-CO2 emissions to bring net emissions from under 7 gigatons of carbon dioxide equivalent (CO2E) in 2005 to about 1 gigaton CO2E by 2050.
“Its status is somewhat indeterminate,” Greenwald said of the strategy paper.
Nordstrom encouraged attendees to think about what other countries are doing, especially China, which produced 60% of the world’s solar panels in 2017 and is currently leading the world in electric bus adoption.
“This is our time to determine where the puck is going to be, to use a tired, tired sports metaphor,” Nordstrom said.
‘Long-Lived Choices’
MPSC members say time is of the essence to get to a mostly decarbonized electricity sector in three decades.
“2050 is 32 years away. Some think that’s a long time, others not so much,” Greenwald said. She pointed out that even building appliances last about 10-20 years, while cars stay on the road 15-20 years. Investments being made now will determine the pace of decarbonization, she said. “You want to affect these investments now if you want to get going.
“Deep decarbonization of the U.S. economy is a challenge, but it’s doable,” Greenwald said. “It’s up to us. The emissions that we will have in the next several decades are up to us.”
“The choices that we make today are long-lived choices,” agreed Litz.
Miles Keogh, executive director of the National Association of Clean Air Agencies, said the plan to 2050 should be viewed through a backwards timeline. “Alright, it’s as if we’re getting married by 2050, and we have to have all this new generation built by then; we have to count backwards to see when we have to start constructing,” he said.
Keogh warned that 2050 is fast approaching and steps must be taken now if deep decarbonization is the goal.
“I think we have the money; I don’t think we have time,” he said, warning that as more time goes by without meaningful work, “the more unlikeable, strident and vigorous the driver has to be.” Keogh said the most universally disliked drivers tend to be policies. He pointed out that of the state regulators in MISO, only three — Iowa, Minnesota and Illinois — did not sue the federal government over the Clean Power Plan.
Keogh also said the immediate future holds little to no chance of any sweeping federal policies.
“The movement toward decarbonization is now not a federal matter; it’s a state and local matter,” he said. “We’re going to have this president until 2020, 2024 maybe. So legislation on the federal level is not going to be an immediate, immediate driver,” Keogh said.
Greenwald said she’s often asked if she’s an optimist or a pessimist regarding the goal of deep decarbonization. On that, she quoted physicist and clean energy pioneer Amory Lovins: “I am neither — because they are just two different forms of fatalism. I believe in applied hope. Things can get better, but you have to make them so.”
Greenwald added there’s no one silver bullet for decarbonization, “just a lot of buckshot,” meaning a variety of strategies.
Utilities Preparing
Xcel Energy’s Nicholas Martin said his company has moved beyond meeting renewable portfolio standards. He also said natural gas generation plays only a “supporting role” in its fleet.
“For many utilities, it’s been a transition from coal to gas. For us, it’s been a transition from coal to largely renewables,” he said. Xcel has pledged an 80% carbon-free energy fleet by 2030 in the upper Midwest and 60% in the rest of its service territory by the early 2030s.
“I can see us going beyond that,” Martin added.
DTE Energy’s Greg Ryan said his company plans for at least an 80% reduction in emissions levels from 2005 by 2050.
“The Clean Power Plan was going to be not too heavy of a lift,” Ryan admitted. “Especially after the 2016 election, we believed this is something we can lead the way on.”
Minnesota Public Utilities Commission Chair Nancy Lange said utilities should keep customers content so they stay on the grid and don’t exit for community aggregation programs that could disrupt the utility structure.
“To me, there’s a continuum of cost on one side and carbon on the other side, and reasonable people should care about both,” said Arkansas Public Service Commission Chair Ted Thomas, who also chairs the Organization of MISO States. “Look at my state; we’re on the cost side of the continuum, no doubt.”
Lange said regulators must reflect often on whether their decisions stifle innovation.
“I know … we’ll probably have gas plant proposals in front of us. That risk about climate is going to ripen, especially in Minnesota’s case,” she said, referring to Minnesota Power’s contested plan to partner with Dairyland Power Cooperative on a new 550-MW natural gas plant on the Wisconsin-Minnesota border. Opponents of the proposed plant say it could compromise the state’s ability to meet its own emission-reduction targets.
If you peruse my columns (and thank you if you do), you may have noticed chronic heartburn over all manner of subsidies.
Huntoon
To be sure, I think everyone should have the right to buy a Tesla. But I don’t think anyone should have to contribute toward someone else’s Tesla.
Ditto someone’s microgrid, rooftop solar, home battery, grid battery, new nuclear plant, old coal plant, etc.
Which brings me to today’s topic: Offshore wind. Coming soon to a beach near you if the ambitions of just about every state north of Virginia pan out.
Now, please don’t get me wrong, I think wind energy is wonderful. If you’ve been to Atlantic City in the last 12 years, you may have noticed five wind turbines in the back bay. Yours truly did the resource analysis, the financials, the permitting and the contracting for that project. I drove the stakes in the ground to mark where the turbines were placed. Back then, wind project development was a jack-of-all-trades business. I was the jack.
Offshore Wind in Reality Is Anti-wind
My objection to offshore wind is that in reality it’s anti-wind. Here’s why: Whatever value you want to assign to wind (and other renewables), it is critical that we make the most of our collective money.
Offshore wind squanders that money.
How do we know that? Because onshore wind is a fraction of the cost.
For a given amount of subsidy dollars, to get 1 million MWhs of offshore wind, we could get 11 million MWhs of onshore wind.
| Lazard Levelized Cost of Energy Analysis
Here are the numbers, using a recent study by analysts who support offshore wind (seeking to show that offshore wind is more valuable than onshore wind). They define value as the market revenues in $/MWh. So in PJM, for example, onshore wind has a value of $39/MWh, and offshore wind has a value of $45/MWh.[1]
But here’s the thing. Onshore wind costs in the range of $30 to $60/MWh per Lazard’s most recent Levelized Cost of Energy analysis.[2] Offshore wind is estimated by Lazard to have a mid-point cost of $113/MWh – which I would suggest is way too low,[3] but let’s go with it.
Using the midpoint of the Lazard cost range for onshore wind of $45/MWh, and subtracting the onshore value of $39/MWh, means onshore wind on average needs a subsidy of $6/MWh.
Using the Lazard cost midpoint for offshore wind of $113/MWh, and subtracting the offshore value of $45/MWh, means offshore wind on average needs a subsidy of $68/MWh.
See the difference? Offshore wind sucks up $68/MWh, when onshore wind needs only $6/MWh. We can get on average 11 times more onshore wind from a given dollar of subsidy. Wow.
Lots of Onshore Wind Out There
It’s important to point out the enormous subsidy of offshore wind cannot be based on a claim that we’re running out of onshore wind. In PJM, for example, only some 8,200 MW of onshore wind have been installed, while the potential onshore wind resource is a staggering 365,000 MW.[4]
Yes, you read that right. Installed wind in PJM is only 2% of the potential wind resource. And the PJM onshore potential is 43 times the total offshore wind currently planned for the entire East Coast (8,500 MW).
The undeveloped onshore resource is out there, waiting. Why sacrifice so much to subsidize offshore wind when that same subsidy dollar could create 11 times more onshore wind? With 11 times more environmental benefits?
Offshore Apologia Doesn’t Hold Up
I raised these concerns at the summer meeting of Mid-Atlantic regulators, to a panel of offshore wind proponents (no skeptics allowed on the panel). I received answers something like these (answers in quotes with my comments following):
“There’s not enough onshore wind in places like New Jersey.” If you care about global warming, why should you care if the wind is built in your state? And even if that mattered, offshore wind isn’t going to be located in New Jersey – or any other East Coast state for that matter. By federal law, each state’s offshore boundary extends only 3.5 miles from the coastline (with the notable exception of, where else, Texas). So this must be about political bragging rights instead of responsible use of taxpayer and consumer dollars.
“Offshore wind is a better resource than onshore wind.” This misses the point that offshore wind, being a better resource, is already reflected in the value-cost comparison above.
“Offshore wind costs are declining, as shown in Europe.” True enough, but as the current numbers reflecting the most recent decline show, offshore wind is nowhere close to making sense. When and if it ever is, that would be the time to spend scarce taxpayer and consumer dollars on it, instead of on onshore wind.
“It’s a long-term investment.” A bad idea is a bad idea. It doesn’t become a good idea by calling it an investment and thereby taking money from people who could productively use it. Whenever offshore wind comes to make sense, then, and only then, would it be a good idea.
The Economic Development and Jobs Scam
As a final note, let me address a couple other leading arguments for offshore wind subsidies: economic development and jobs. The economic development claim typically comes from the wind developer’s consultant and is not only fanciful but also still pales in comparison to the negative impact of the subsidy cost (which somehow doesn’t appear in the press release).
As for jobs, let me give as an example the U.S. Wind project of 248 MW in Maryland, which the Maryland Commission claimed would create 4,540 new jobs in the operating phase of the project,[5] a claim that was cranked into the press release.[6]
This is a ridiculous number of new jobs for a relatively small (yet expensive) wind project. The project sponsor, U.S. Wind, claimed only 250 new jobs during the operating phase.[7]
So how could the Maryland Commission come up with 4,540 new jobs? The Commission’s consultant took its estimate of 226 new jobs and multiplied it by 20 years of project operation.[8] So every year, the same 226 jobs got counted again and again and again, for a total of 20 times. Is “scam” too strong of a word?
Oh, and as the Maryland People’s Counsel pointed out, the economic development claims completely ignored the negative effects on Maryland businesses (and jobs) from having to pay the enormous subsidies.[9] This is the free-lunch fallacy.
Bottom Line: All Ashore Please!
Subsidies are costly, especially when they sacrifice many times better options and can’t possibly produce the claimed benefits.
Politicians and regulators should suppress their Edifice Complex and support the wind resources that makes sense.
http://eta-publications.lbl.gov/sites/default/files/offshore_erl_lbnl_format_final.pdf (subtracting the $6/MWh of additional energy and capacity revenue on pdf page 15 from the offshore value on pdf page 11 to get the net onshore value). 2016 data are used from the study, rather than 2007-2016 data, because the latter do not fully reflect the fundamental change in natural gas prices over time. ↑
Pegging the cost of offshore wind is difficult because numbers bandied about in the trade press and in press releases can be deceptive. Some reported numbers are north of $200/MWh, and then there is a surprise like Maryland’s claim of Offshore RECs at $131.93/MWh. Now, with RECs, the developer is assuming some level of energy revenue that needs to be added to get total cost. But more importantly about the Maryland report is that the actual REC cost is $163/MWh in year one, escalating at 1% per year. Now, you might wonder how a REC cost starting at $163/MWh can actually cost $131.93/MWh. It can’t. The Maryland Commission converts the actual cost into a present value in 2012 dollars by an assumed discount factor. https://webapp.psc.state.md.us/newIntranet/Casenum/NewIndex3_VOpenFile.cfm?FilePath=C:Casenum9400-94999431\121.pdf, pdf page 78. Of course, there’s no end to such nonsense – the Maryland Commission could have converted to 1912 dollars and said the cost was $6.50/MWh. ↑
The D.C. Circuit Court of Appeals on Tuesday dismissed claims by a labor union that FERC had failed to consider the effects of the closure of the Brayton Point power plant on ISO-NE’s Forward Capacity Auctions 9 and 10 but did suggest the commission should act on a similar claim regarding FCA 8.
Circuit Judge Cornelia Pillard filed the opinion for the three-member panel July 24, dismissing claims by the Utility Workers Union of America Local 464 and its president, Robert Clark, who contended that high clearing prices in FCAs 9 and 10 — resulting from the “illegal” closure of Dynegy’s 1,488-MW Brayton Point station in Massachusetts — increased the cost of their retail electricity service. The union represented workers at the plant, which closed last year.
The petitioners challenged FERC’s orders approving the results of those wholesale auctions as just and reasonable under Section 205 of the Federal Power Act.
The Brayton Point Power Station in Somerset, MA went offline in June 2017.
“Because no record evidence establishes a causal link between the claimed manipulative closure of Brayton Point and the clearing prices of FCA 9 and FCA 10 that FERC approved, we hold that petitioners lack standing to challenge FERC’s acceptance of those results,” the court said.
The union and others also had challenged Brayton Point’s closure before the commission as an attempt to manipulate the results of FCA 8.
In September 2014, the commission split 2-2 over whether it should reject the results from FCA 8 because of unchecked market power, allowing the 2017/18 auction results to become “effective by operation of law” (ER14-1409). Under the FPA, rates take effect 60 days after they are filed with FERC, absent a commission order to the contrary. (See Court Asked to Force FERC Action on Disputed ISO-NE Capacity Auction.)
In the absence of final FERC action, the court lacked jurisdiction to consider that FCA 8 petition.
Tuesday’s ruling said, “Petitioners’ long-pending request that the full commission revisit Brayton Point’s retirement in the FCA 8 proceedings has yet to be resolved. We trust the commission will give it appropriate consideration without further delay.”
Missing Link
The court suggested the petitioners erred in referring solely to events that occurred in FCA 8, which saw total capacity costs for 2017/18 rise to $3.05 billion (or $7.025/kW-month) — almost double the previous high — as the region’s capacity shifted from an expected surplus to a deficiency of more than 1,000 MW. Prices surged again the following year to $9.55/kW-month for FCA 9 covering 2018/19 but fell to $7.03/kW-month in FCA 10.
“It might seem intuitive, given the laws of supply and demand, that the non-participation of a large plant like Brayton Point would exert some upward pull on auction prices,” the court said. “Again, that logic might suffice in relation to FCA 8, given that Brayton Point retired after the deadline for other suppliers to participate in that auction. But in this context, where petitioners challenge successive Forward Capacity Auctions exclusively by reference to events during FCA 8, the link is missing.”
The court said New England has structured its forward capacity markets to safeguard against undesired effects in one auction rolling through succeeding ones.
The cycle of annual auctions, “conducted three years before generators assume the resulting obligations, are spaced so as to permit the market to account and correct for the events of the previous auction,” the court said.
Russian hackers gained the ability to manipulate U.S. utilities’ industrial control systems (ICS), federal officials said in a briefing Wednesday that offered the most detailed account yet of a campaign that compromised hundreds of energy companies last summer.
The campaign, which began with phishing attacks and watering hole exploits to capture the credentials of vendors trusted by the utilities, did not result in any physical impact. But it was nonetheless troubling because of the length of time the hackers lingered in the utilities’ systems and the access they gained, officials said.
“The punch line is this: In this campaign so far, the effect has been limited to being able to access the systems — to gain fairly sophisticated level access into the systems,” said Jon Homer, chief of the industrial systems control group for the Hunt & Incident Response Team at DHS’s National Cybersecurity & Communications Integration Center. “But … they have not caused physical impact as a result of that access. So, they had access to be able to do it, but they haven’t actually caused any physical [damage].”
Jeannette Manfra, assistant secretary for DHS’s Office of Cybersecurity and Communications, said the detection of the infiltrations — the subject of a March 15 DHS alert — was the result of the “partnership” among DHS, the power industry, the Department of Energy, the intelligence community and the FBI.
“We were able to work very closely as soon as we identified a threat and respond to that and ensure that in this case the Russians were not able to achieve any significant goal in terms of actually disrupting infrastructure,” she continued. “To be clear, there was no threat for the electrical grid to go down. … While they were in a position to be able to manipulate some systems, there wasn’t a broader threat to our entire electric grid.”
DHS held Wednesday’s webinar “to raise awareness more broadly so that others could defend against this,” Manfra said. Additional briefings are scheduled for July 30 and Aug. 1.
Hackers ‘Stuck Around’
Homer said the campaign was “an advanced persistent threat in its classic definition. We’re looking at someone at an organization that got in and stuck around.”
He said the campaign targeted or affected “hundreds of victims” focused on electric generation, transmission and distribution. “But there were also victims … in the nuclear sector, in the aviation sector, critical manufacturing, government entities.”
The targets — none of which were identified — included small, medium and large organizations selected for their “strategic placement,” Homer said. DHS said the targets’ names “align with open-source lists (organized by subject-matter areas) published by third-party industry organizations.”
Homer said the power generation, transmission and distribution companies were penetrated despite having “good, sophisticated networks from a cyber defense perspective. They have the right tools. They have the budgets. They have the capabilities to defend their networks from this effort.”
Preexisting Relationships
The campaign began in early 2016 with the penetration of the first of many “staging targets,” small organizations with less sophisticated networks such as vendors, integrators and strategic R&D partners.
“They were selected because of their preexisting relationship with the intended target,” Homer said. “This is not a target of opportunity-type campaign. This is not one where the threat actor went around and said, ‘Who forgot to patch their systems last month?’”
Graphic illustrates how hackers used vendors (on the outside of the bulls-eye) as “staging targets” to win access to utilities — the “intended targets.” | National Cybersecurity & Communications Integration Center
The campaign was dormant for more than a year after the first penetration, until early 2017, when a second vendor network was compromised. That network was used to launch a phishing attack against another vendor and government entity, allowing the hackers to move to another vendor, which was used to phish operators at the utilities. Later, the first compromised vendor was used to access several utilities and IT service providers.
Homer said the hackers used the staging targets’ networks, so when the intended targets reviewed activity logs it appeared “as if the traffic or the code was originating from … one of their trusted partners.”
Because control systems are customized for their application, it takes utilities’ technicians months to learn how to operate them. “In the same regard a threat actor who wished to manipulate a control system has to understand that particular setup, architecture and design,” Homer said.
Thus, the hackers scoured file servers “for specific file names and specific keywords — things pertaining to vendor information and reference documents.”
The hackers were aided because some of the companies’ “jump boxes” — computers used to authenticate access to the ICS — contained files with information such as IP addresses, ports and default user names.
The hackers also were aided by publicity photographs on some companies’ websites that inadvertently revealed security information.
“These are things like … cutting a ribbon or something like that, and there’s the CEO talking to the mayor,” Homer explained. “But in the background of the picture are control systems, and on these control systems are very important things like set points and safety guards and configurations and diagrams and all these kinds of things. All of this is very valuable information, but it’s in the background and the organization didn’t realize what they had published.”
Lessons Learned
The campaign ultimately allowed the hackers to get across the ICS firewalls and gain control of the human-machine interfaces used by the utilities’ system operators.
Graphic shows how Russian hackers accessed control system networks after first penetrating the corporate networks. The hackers’ techniques included compromised credentials, the exfiltration of vendor reference documents from corporate servers, remote access profiles downloaded from “jump boxes” and configuration data and screenshots downloaded from human-machine interfaces. | National Cybersecurity & Communications Integration Center
DHS officials concluded the initial access to corporate networks came primarily through the capture of legitimate credentials. All victims had externally-facing, single-factor authenticated systems. Intrusions came via virtual private networks, Microsoft Outlook web access and remote desktops.
Officials said the investigation illustrated the need to require multi-factor authentication for all external interfaces and to block all external server message block (SMB) network traffic. “There’s really not a good business justification for having external SMB outbound,” Homer said.
VALLEY FORGE, Pa. — The results are in from a PJM member poll on the stakeholder process. The findings? It’s not perfect, but it’ll have to do.
Stakeholders reviewed the results and considered next steps at a “stakeholder super forum” on Wednesday. The effort to review the process rose out of concerns raised by multiple RTO participants.
The PJM Stakeholder Super Forum on the stakeholder process was held on July 25, 2018 | PJM
Observations of the results showed there was strong agreement that PJM’s main job is to maintain grid reliability; robust, non-discriminatory and competitive markets; and efficient operations. Additionally, many respondents agreed that “all things considered, the PJM stakeholder process is superior to the stakeholder processes of other RTO’s” and that PJM’s staff provide highly satisfactory technical expertise and analysis to support the process.
However, members also agreed that the process takes on more issues than it can process and resolve; that PJM and members can do a better job prioritizing issues; and that standing committees need to better manage their subcommittees and task forces.
“On balance, … we do think that of the bad ideas that are out there, we think that this is a good one,” Gabel Associates’ Mike Borgatti said, referring to the stakeholder process.
Borgatti (left) and Anders | PJM
Ironically, or perhaps as expected, respondents showed less agreement on what to do when the stakeholder process cannot reach agreement on an issue.
PJM’s Dave Anders facilitated the meeting, along with Borgatti, who chairs the Members Committee. Anders confirmed that the total of 204 respondents was representative of the usual participation in MC votes, which is usually around one-fifth of the roughly 1,000 members. Borgatti said that “all around the same timeframe” earlier this year, he received feedback from members, PJM staff, board members and other stakeholders about concerns with the current process.
That feedback initiated the poll, which relied on the same questions used during the Governance Assessment Special Team (GAST) that PJM implemented in 2009 following FERC Order 719, which required the board to prove it was responsive to stakeholders. Borgatti said the GAST responses provide a baseline for where the process has improved or worsened in the ensuing years.
He stressed the purpose of the meeting was to identify issues members would like to consider addressing and not to formulate solutions.
“This is purely informative. … We’re not solving anything now,” he said. “I personally don’t believe it’s my responsibility to tell you what conversations you should be having” or what the membership should be voting on.
Stakeholders then listed issues they would like to consider addressing. Among them were subjects that have come up recently, such as how to handle proposals introduced at the MC or the Markets and Reliability Committee rather than at lower committees and reducing the threshold for proposals from lower committees to be recommended for consideration at the MRC and MC. A major consideration was prioritizing issues and limiting the number being considered simultaneously.
Stakeholders also wanted to discuss procedures for handling issues when there is no consensus on a solution or when a FERC decision is anticipated, but they did not want to change PJM’s voting mechanisms. In fact, while several stakeholders expressed concerns through the poll about sector-weighted voting, stakeholders didn’t add it to the list of issues to consider. Instead, they will consider whether PJM should take a stronger role in placing members in their correct sector.
Borgatti said the issues will be distilled into a few ideas for consideration and then included in a problem statement and issue charge to be endorsed by the membership later this year.
At what point will an offshore wind bid in New York become firm and binding? And how will state agencies ensure a project delivers its promised benefits?
State officials discussed these and other issues with developers and stakeholders when they met in New York City Monday to explore contract terms for the planned fourth-quarter solicitation for 800 MW or more in offshore wind energy, the first part of a two-phase plan to develop 2,400 MW by 2030. (See NYPSC: Offshore Wind ‘Ready for Prime Time’.)
The New York State Energy Research and Development Authority (NYSERDA) held a July 23 technical conference to discuss the agency’s request for information (RFI) issued July 20, soon after the state’s Public Service Commission issued an order (Docket No. 18-E-0071) authorizing the solicitation.
| Darren Coleshill on Unsplash
“We know that we have a lot of work to do in a short period of time, which is why we wasted no time trying to pull together this conversation,” NYSERDA CEO Alicia Barton said.
The agency’s RFI covered the procurement schedule and quantity, interconnection and deliverability, offshore wind renewable energy certificate (OREC) pricing options, bid price evaluation, economic benefit, project viability, environmental issues and eligibility and contract provisions.
Binding Provisions
“We’re interested to know how much time you would need to develop your proposals … and secondly, we are looking for these bids to be firm and binding for a period of six months,” Doreen Harris, NYSERDA director for large-scale renewables, told prospective developers. “Is this duration reasonable?”
Anbaric Project Manager Howard Kosel said the term “firm” seemed to clearly apply to pricing but asked if “binding” referred “to all internal approvals, court approvals, all necessary such that, if awarded, would be bound to contractually execute?”
NYSERDA Deputy Counsel Peter Keane clarified the agency’s approach would be similar to that for the renewable portfolio standard (RPS).
“We consider the submission of a proposal as an offer,” Keane said, noting that a developer would include its terms in its proposed contract and that NYSERDA can form a contract by accepting. “We do, however, require that within a reasonable amount of time, about 30 days, they provide a corporate confirmation that the authority has been given to the execution parties, etc.”
NYSERDA must issue its offshore wind solicitation in consultation with the New York Power Authority (NYPA) and the Long Island Power Authority (LIPA). The agency will announce the award in the second quarter of 2019 and, if needed, issue a second solicitation next year to meet the 800-MW goal.
“Will the capacity that NYPA and/or LIPA be purchasing, if they decide to go forward, be a subset of the 800 MW or would it be additive to, and if so, would that be known as part of the RFP?” asked Clint Plummer, Deepwater Wind vice president of development.
Keane said the PSC would have to weigh in on that issue, but his “feeling” was the NYPA and LIPA capacity would be additional.
“Either of the other two power authorities could go out on their own; theoretically, there’s an option that they could join with us and just make a long-term financial commitment for whatever capacity we procure,” Keane said. “In either case, I don’t see those as being automatically subtracted from our Phase 1 goal.”
Harris agreed with Keane and read from the authorizing order: “The quantity of ORECs that is procured by NYSERDA, NYPA and/or LIPA toward the Phase 1 goal need not be limited to the proportional share of retail load to be served but instead could be based on quantities being efficient for each particular solicitation or award.”
Enforcement Mechanisms
NYSERDA plans to announce the award in the second quarter of 2019 and, if needed, issue a second solicitation next year to meet the 800-MW goal. The agency expects the Department of Interior’s Bureau of Ocean Energy Management (BOEM) to identify new lease areas for New York early in 2019.
New York Offshore Wind Study Area | NYSERDA
Harris did not attribute questions from those participating in the conference via the web. One asked how NYSERDA would determine or quantify a shortfall in claims — either estimated benefits or expenditures — made at the time of the bid.
“In the land-based renewables context, we do have a very similar category, albeit it was for a slightly different purpose,” Harris said. “However, on the land-based side, we do audit the spending of the awarded developers to verify, through a third-party audit, the spending records that they are claiming to have executed in their project development.”
There will be contractual ramifications for a shortfall, she said.
“What kind of enforcement mechanism should we have?” Keane asked. “We need to have something, for you win eligibility points for the economic benefits that you pledged.”
Wind developers must submit their bids in terms of both fixed-price ORECs and variable — or index — ORECs, and NYSERDA has the authority to specify under what conditions an index OREC contract may revert to a fixed price.
“I don’t think NYSERDA expects to have discretion to just order that trigger on its own for whatever reason. My thought is it would be some sort of event,” Keane said.
Compliance Payments
One web participant expressed concerns about the OREC compliance obligation for load-serving entities in cases of project delays or cancellations: “If there is not an alternative compliance payment, what will happen if projects are not constructed and there are not enough ORECs available for an energy service company [ESCO] to purchase the requirement?”
Harris explained that ORECs will follow a scheme similar to that for zero-emission credit obligations, with LSEs and ESCOs only responsible for purchasing a prorated share of whatever volume of ZECs NYSERDA acquires from eligible nuclear generators.
“If there was a circumstance where a project was delayed, and it came online in July instead of May, and there were fewer ORECs to be had in a given year, it wouldn’t impact the ESCO or LSE in any way other than to just reduce the pro rata share of the ORECS that it would be obligated to purchase,” Harris said.
Transmission and More
Another meeting participant asked how the grid will accommodate large injections of power if 800 MW or more is awarded in Phase 1.
“This is expected to be a primary consideration for the transmission working group … to be formed prior to Sept. 28 this year,” said Matt Vestal, NYSERDA technical advisor.
Kosel pointed to NYISO’s “fairly rigorous” and time-consuming interconnection process, in which costs are not determined until well into the process. With 70% of the RFI’s evaluation criteria based on price, he asked how developers can be expected to plan without knowing costs for system deliverability upgrades.
Vestal said developers have been thinking about those issues for a long time and probably have significant understanding of where their interconnection costs lie.
“We’re seeking to understand and want to be able to assess the reasonableness of those interconnection costs as we evaluate those prices,” Vestal said. “We include that question specifically in the RFI, but NYSERDA, as well as the commission, certainly understands that these prices can be incrementally uncertain relative to the other costs required for offshore wind on the generation side.”
Nora Madonick of Arch Street Communications pointed out the RFI did not address “anything specific to minority, women-owned or service-disabled veteran-owned businesses, and I’m wondering if a percentage has been discussed or if you would like input on that in the RFI, and, if so, in what category.”
NYSERDA now has no plan for a set percentage, but stakeholders can address that topic under any part of the RFI they like, Keane said.
Stakeholders can submit comments on the RFI until 5 p.m., Aug. 10, to offshorewind@nyserda.ny.gov. NYSERDA will post all comments on its website.
SCOTTSDALE, Ariz. — State regulators were forced to scramble the programming at their summer meeting last week when Department of Energy officials belatedly rejected invitations to talk about the Trump administration’s proposed coal and nuclear bailouts.
The National Association of Regulatory Utility Commissioners invited officials from DOE’s Office of Fossil Energy and Office of Nuclear Energy to speak on a panel July 17 on Trump’s directive to subsidize at-risk nuclear and coal generators (“When the President Says You Can’t Retire: The Impacts of Section 202c on the Electricity Industry”) but neither office was represented.
In addition, Assistant Energy Secretary Bruce J. Walker, who was scheduled to speak at the Summer Policy Summit’s General Session on July 16, instead appeared at the Fairmont Scottsdale Princess hotel ballroom on a screen via a recorded cellphone video.
Walker, appointed by President Trump last year as head of the Office of Electricity, said he was unable to attend because of “weather problems in New York.” DOE said Walker was scheduled to fly from New York to Phoenix via Denver but missed his connecting flight because of delays at LaGuardia Airport and was unable to reschedule to arrive at the conference in time.
The Maryland Public Service Commission told RTO Insider that DOE’s nuclear energy representative canceled the day before the panel discussion.
“We received an email on Monday, July 16 from DOE’s Office of Nuclear Energy that they would be unable to send a representative to speak at the joint subcommittee panel on July 17 due to scheduling conflicts,” Amanda Best, an aide to Maryland Commissioner Anthony O’Donnell, who was to moderate the session, said in an email. “A representative from the DOE Office of Fossil Energy was also unable to attend.”
DOE’s absence led some NARUC attendees to speculate that the department wanted to avoid questioning by regulators and reporters about its plans for implementing Trump’s directive.
DOE spokeswoman Shaylyn Hynes didn’t deny it.
“There is an interagency policy review process underway regarding grid resilience and examining multiple policy options,” she said in a statement. “It would have been premature for DOE representatives to discuss the specifics of that process while it remains ongoing.”
Walker angered members of the House Committee on Science, Space, and Technology’s Subcommittee on Energy last month when he testified that his agency had no estimates on the cost of the bailouts, which Trump had ordered a week earlier. Walker responded to Democratic members’ questions tersely and without elaboration. (See Dems Hit Coal, Nuke Bailout at House Hearing.)
Walker’s name has been among those floated as a potential replacement for FERC Commissioner Robert Powelson, an outspoken opponent of the bailouts, who is resigning in mid-August to become CEO of the National Association of Water Companies. (See related story, FERC Says Farewell to Powelson.)
At the conference, however, NARUC members passed a resolution asking that Trump appoint a replacement with state regulatory experience. “No one understands better than state commissioners the real-world, often unintended, effects of federal policy at the ground level on consumers, and how such policies complement, interfere or interact with related state programs or local/regional market conditions/demographics,” the regulators said.
Powelson, former chairman of the Pennsylvania Public Utility Commission, is the only former state regulator on FERC.
Quicker Recovery for Cyber Investments
Walker spoke for less than four minutes on the video, reading from notes while sitting in what looked like an airport corridor.
“What I wanted to speak about directly was the need for all of us within the regulatory framework to acknowledge the changes that are necessary in the general rate case filings so that they better adapt to and address the problems we see today,” he said. “Specifically, in the cybersecurity world, the investments that are being made today become obsolete within six months. Our regulatory models today don’t necessarily recognize that, and one of the things we collectively need to do is — using a risk-based approach process — properly align the rate case mechanisms and the recovery aspects for the utilities that we work with so that they can properly recover their investments.”
NARUC passed a resolution at the summer meeting encouraging regulators to “explore and examine alternative rate recovery mechanisms to accelerate the modernization, replacement and enhancement of the nation’s electric system.”
Carl Pechman, director of the National Regulatory Research Institute, NARUC’s research arm, said Walker’s “concerns about the rate treatment of cyber activities is real.”
“In light of these issues, the NRRI is planning to undertake a survey and deep dive on the ratemaking of assets that have short and difficult-to-predict asset lives,” Pechman said in an email. “We look forward to working with our nation’s public utility commissions and the U.S. DOE to help assure that cost recovery and rate mechanisms support national priorities of cybersecurity.”
“Regulators should and mostly do have discretion with regard to the treatment of capital and operating costs, including consideration of risk and obsolescence, and the alignment of cost recovery to useful life,” Janice Beecher, director of Michigan State University’s Institute of Public Utilities, said in an email. “Potential obsolescence within one year raises several issues. The regulatory policy community would benefit from research and information-sharing in this area, given its criticality.”
States’ Role in National Security
Walker said that although national security is generally considered a federal function, states have an important role because they regulate the utilities that power the 16 critical infrastructure sectors.
“We will continue to work through our Electric Sector Coordinating Council and the Oil and Natural Gas [Subsector] Coordinating Council to work with the asset owners to develop short-term executable strategies for cyber, physical and [electromagnetic pulses],” he said.
“The investments we are looking to drive are designed to reduce risk. Thus, as you become aware of investor requests designed to address these three specific areas, I would implore you all to take the threat very seriously and find a way to support the investment.”
OMAHA, Neb. — SPP’s Markets and Operations Policy Committee last week agreed to create a task force to evaluate a proposal that would change the recovery mechanism for the RTO’s administrative fee.
Saying the RTO’s Finance Committee “is at a point where maybe we change the recovery methods,” SPP CFO Tom Dunn pitched the committee’s recommendation to change the fee’s billing units from transmission metrics to energy metrics by charging market transactions.
The administrative fee, currently 42.9 cents/MWh, is collected under Schedule 1A of SPP’s Tariff on transmission contracts between transmission providers and customers. Point-to-point contracts are billed against reserved transmission capacity, and network service is billed against the prior year’s average monthly zonal peak.
Speaking at last week’s MOPC meeting, Dunn said regulators have issues with how some companies recover their costs, pointing to the use of historical data for current year costs and inconsistent calculations. The Integrated Marketplace has also resulted in a staff increase and additional IT costs, which have increased the costs to be collected.
“Is there a way we can eliminate or mitigate issues utility customers are having with regulators?” Dunn asked.
He said using energy metrics could potentially reduce the administrative fee to 15 cents/MWh, because financial-only players who are currently not paying Schedule 1A fees would also be contributing. But Dunn also cautioned against adding the “new universe” of market participants.
“From an SPP Inc. standpoint, that’s not necessarily ideal,” Dunn said. “Our customer base is monopolistic entities carrying investment grade ratings. When you change that mix, you slightly change the credit outlook of SPP — slightly.”
The new scheme would also result in independent power producers paying more.
“The value that members and market participants realize in the marketplace comes through in terms of the energy cost customers pay,” said Board Chair Larry Altenbaumer, who also sits on the Finance Committee. “The largest cost component is the 1A fee, which is easy for regulators to lay their eyes on. Our recommendation basically does an automatic netting and captures the energy cost the consumer pays. Some regulatory agencies, we think, would allow this to pass through. Others we’re not clear on.”
Dunn said he had talked with MOPC leadership about setting up a task force, noting that full market participation would “result in a solution that’s tenable for everybody.” The group would return to the committee in January with a recommendation for approval, with the new fee going into effect in 2020.
SPP legal counsel visited with FERC in March and “talked through the concept,” Dunn said.
“FERC’s big concern is consistency across the markets,” he told members. “All of the organized markets have an unbundled rate structure. We don’t want to be put in a position where we’re showing the commission was wrong to put unbundled rates in regulated markets. It’s an issue we would have to address.”
Some stakeholders expressed concerns about forecasting energy usage, which is largely impacted by weather.
“I’m not sure how that brings stability to the administrative fee and cost recovery,” said Midwest Energy’s Bill Dowling.
Dunn responded that energy metrics would improve load forecasts, as market participants would be using 365 data points for each entity, as opposed to 12 data points from the previous year. He added that the methodology change would allow midyear adjustments to true up the remainder of the year should there be under- or over-recovery.
“The simpler we can do it, the better it is for everyone. We don’t want to focus on precision so that we gin up another Z2,” Dunn said, referring to SPP’s troubled method for assigning financial credits and obligations for sponsored transmission upgrades.
“What’s beneficial is keeping rate decisions simpler. We want something that doesn’t drive administrative costs and is easier to administer,” he said.
MOPC Chair Paul Malone, of Nebraska Public Power District, recommended the task force meet monthly.
“Continuing to lay everything on transmission doesn’t make sense to me on the surface,” he said.
