Page 1138 – RTO Insider

July 27, 2018

Deep Carbon Cuts in Midwest Possible by 2050, Group Says

By Amanda Durish Cook

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.

Greenwald addressing attendees | © *RTO Insider*

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.”

The Regulator Perspective

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.

July 26, 2018

Counterflow

By Steve Huntoon

If you peruse my columns (and thank you if you do), you may have noticed chronic heartburn over all manner of subsidies.

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 offshore 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. ↑
https://www.lazard.com/media/450337/lazard-levelized-cost-of-energy-version-110.pdf, pdf page 3. ↑
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. ↑
Installed wind in PJM is available here: https://www.pjm.com/planning/services-requests/interconnection-queues.aspx (sort by generation interconnection, in-service status and wind fuel type). Total wind resource in PJM is estimated from total resource by state, developed by AWS Truepower for NREL, which is available here: https://openei.org/doe-opendata/dataset/acf29328-756e-4d14-bd3e-f2088876e0e6/resource/337aca6a-c8f1-4813-b0e6-670beb47a900/download/windpotential80m30percent1.xls (estimates exclude areas unlikely to be developed such as urban areas). And from prorating each state’s total potential resource by the PJM installed portion of the total state installed capacity, as provided by AWEA, which is available here: https://www.awea.org/statefactsheets. Spreadsheets available by request from the author. ↑
https://webapp.psc.state.md.us/newIntranet/Casenum/NewIndex3_VOpenFile.cfm?FilePath=C:Casenum9400-94999431\121.pdf, pdf page 11. ↑
https://www.psc.state.md.us/wp-content/uploads/PSC-Awards-ORECs-to-US-Wind-Skipjack.pdf. ↑
https://webapp.psc.state.md.us/newIntranet/Casenum/NewIndex3_VOpenFile.cfm?FilePath=C:Casenum9400-94999431\3.pdf, pdf page 54. ↑
https://webapp.psc.state.md.us/newIntranet/Casenum/NewIndex3_VOpenFile.cfm?FilePath=C:Casenum9400-94999431\85.pdf, compare Tables 20 and 21 on pdf pages 130 and 131. ↑
https://webapp.psc.state.md.us/newIntranet/Casenum/NewIndex3_VOpenFile.cfm?FilePath=C:Casenum9400-94999431\113.pdf. ↑

July 26, 2018

D.C. Circuit Dismisses Union Challenges to FCA Results

By Michael Kuser

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.

FCA Brayton Point FERC ISO-NE — 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 A u ction.)

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.

July 26, 2018

DHS: 2017 Russian Probes Hit Hundreds of Energy Cos.

By Rich Heidorn Jr.

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 Department of Homeland Security’s “Awareness Briefing” indicated the hackers had access to the same type of human-machine interfaces that suspected Russian agents used to cause blackouts in Ukraine in 2015. (See How a ‘Phan t om Mouse’ and Weaponized Excel Files Brought Down Ukraine’s Grid.)

Access but no Damage

“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 ale r t — 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 schedule d 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?’”

DHS cybersecurity Russian hackers — 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.

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.

July 26, 2018

Poll: PJM Stakeholder Process Imperfect, Necessary

By Rory D. Sweeney

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 resu l ts and considered next ste p s 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*

Observati o ns 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.

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.

July 25, 2018

NYSERDA Talks Offshore Wind Contract Terms

By Michael Kuser

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.

“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.

July 24, 2018

DOE Rejects NARUC Invites on Coal, Nuke Bailout

By Rich Heidorn Jr.

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.

doe naruc coal nuclear — DOE Assistant Secretary Bruce Walker addressed NARUC’s General Session Monday via a cellphone video. | © *RTO Insider*

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.)

doe naruc nuclear coal — The House Committee on Science, Space, and Technology’s Subcommittee on Energy hears DOE Assistant Secretary Bruce Walker testify in June. | © *RTO Insider*

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.”

July 24, 2018

SPP Stakeholders to Study Admin Fee Changes

By Tom Kleckner

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.

spp administrative fee — SPP CFO Tom Dunn explains potential changes to the administrative fee’s recovery. | © *RTO Insider*

“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.

July 24, 2018October 31, 2023

Massachusetts Seeks Input on Energy Plans

By Michael Kuser

WESTFIELD, Mass. — Massachusetts officials last week held three hearings across the state to get public input ahead of a September release of the statutorily mandated Comprehensive Energy Plan (CEP).

The state’s Department of Energy Resources is preparing the plan to project the state’s 2030 energy demands for electricity, transportation and thermal conditioning and help it meet its greenhouse gas emissions targets. The state’s Global Warming Solutions Act (GWSA) requires a 25% reduction in emissions by 2020 from the 1990 baseline and an 80% reduction by 2050.

The state accounts for 45% of electricity demand in New England.

“This report is really looking at supply and demand of energy going forward,” DOER Deputy Commissioner Joanne Morin said on July 19. “The CEP is going to demonstrate the modeling, the impact and required balance in pursuing these goals simultaneously, and looking at different pathways that we could take with our energy future.”

State lawmakers are now considering legislation to increase the state’s renewable energy and reduce high-cost peak demand. Earlier this year, two senators touted a goal to achieve 100% renewable electricity by 2035 and to make the heating and transportation sectors 100% powered by renewables by 2050.

Asa Hopkins of Synapse Energy Economics, the DOER’s consultant on the energy plan, sought feedback on its assumptions and analysis of 2030 scenarios.

“Have we got it right or have we got it wrong? Should we be designing these policy features in some different way?” Hopkins asked.

The public has until July 31 to submit comments at the CEP website.

“That’s not much time for public comment,” said Rosemary Wessel, director of “No Fracked Gas in Mass,” a program of the Berkshire Environmental Action Team.

Wessel also complained about what she called a lack of transparency in clean energy data, saying the DOER shows state emissions data only up to 2014. She also said the DOER website “has become much harder to use.”

Several audience members murmured their agreement to the website assessment, and Morin said, “I’ll have to follow up on that.”

Soft or Hard Push?

Hopkins’ study included a status quo scenario and also analyzed the impact of adjusting “key levers,” including efficiency, renewables and electrification via electric vehicles and heat pumps.

Under the status quo or “sustained policies” scenario, renewables would supply 45.5 TWh in 2030, or about 35% of electricity in the region, with Massachusetts hitting its 25% renewable portfolio standard target. Under a “high renewables” scenario, the amount increases to 38% (49 TWh), with all of the increment serving Massachusetts, which would get about half its electricity from Class I renewables in 2030, Hopkins said.

Massachusetts CEP Comprehensive Energy Plan Electrification

2030 electric consumption is projected at 11% above 2018 under aggressive policies leading to high electrification in New England. | Synapse

“We’re looking at electrification, which in the case of electric vehicles, is associated with a substantial increase in efficiency, as it is with heat pumps, so there’s a common thread there,” Hopkins said. “There are distinctly more heat pumps in Massachusetts than there are EVs, but more people consciously see EVs than see heat pumps.”

Because they’re moving heat rather than generating it, heat pumps have efficiencies well over 100%.

“A typical seasonal average in Massachusetts would probably be well over 200%, and for a heat pump water heater it will go up well over 300%,” Hopkins said. A 300% efficient heat pump produces three units of heat for every unit of energy, Hopkins explained.

The “high electrification and high renewables” scenario includes a “clean peak” idea to incentivize generation or energy dispatch to be available to meet winter and summer peaks without emissions.

The scenario for increased efficiency, electrification and renewables would reduce the average commercial building’s heat energy by 25% or more with the state getting 50% of its electricity from renewables, Hopkins said.

Enhancing both electrification and renewables would push wind and solar growth to 33.7 TWh in 2030, while natural gas use would be 29% lower than today.

System demand graph shows results under aggressive policies leading to high electrification in New England. Regional demand increases 13% by 2030 but most of the increase is powered by renewables (+165%). Gas generation drops (-25%). | Synapse

“Once those clean peak resources are there, it’s not like they’re only there on the peak day; they also run all the rest of the time around the year and are impacting what’s going on with dispatch of different resources,” Hopkins said.

Massachusetts has a goal of 300,000 EVs on the road by 2025 and 1.7 million in 2030. Hopkins said the state can probably only reach 160,000 EVs by 2025 under current policies but could exceed its EV goals by enhancing all policy levers.

Several people asked about energy storage and whether EVs can act as batteries for the grid.

“The place where storage makes a difference is on an hourly basis,” Hopkins said. “One learning from this is that what you assume about the load shape of when all those 1.2 million or 1.7 million EVs are charging, it really matters a lot. And what you assume then about when those batteries will charge and discharge really matters a lot.”

If peaks are in the afternoon and you have everyone charge their cars overnight, “you create a giant super-peak at 3 in the morning,” Hopkins said. “That’s probably not the actual path forward, but things we learn there can flow into policy development.”

Solar Woes

Robert Camus, a Granby selectman and member of the town’s energy committee, said that if the state wants to increase solar energy by 50% by 2030, it should change policies to promote local ownership of solar farms.

“The SMART [Solar Massachusetts Renewable Target] program awards Eversource [Energy] and National Grid so much each year, but there’s no differentiating between a private landowner and a municipality,” Camus said. “If the municipality was to have the solar field, versus a private landowner, you’d have a lot more advantages.”

If a private landowner makes a deal with a solar developer, the money goes to one individual, he said.

“If you go to the municipality, every taxpayer in that town gets a share of the money, which would decrease the demand of the municipalities on the administration every year for money for schools, infrastructure and everything else,” Camus said. “If the money goes to the taxpayer[s] of Massachusetts rather than to out-of-state developers, we can more enhance our own economic growth, because the money stays.”

He suggested that the SMART program devote 75% of its money to municipalities, leaving 25% for individual landowners.

Morin directed Camus to contact Michael Judge, director of DOER’s renewable energy division. The CEP is intended to complement another effort, the Clean Energy and Climate Plan (CECP), which talks about emissions targets and how the state is going to meet them, Morin said.

July 24, 2018November 13, 2023

SPP Markets and Operations Policy Committee: July 17-18, 2018

OMAHA, Neb. — Given a proverbial second bite of the apple, SPP stakeholders easily approved a revision request that requires non-dispatchable variable energy resources (NDVERs) to register as dispatchable variable energy resources (DVERs) within a multiyear transition period.

The Markets and Operations Policy Committee rejected the measure (RR272) during its April meeting. The Board of Directors/Members Committee tabled the request but asked for a review of RR272’s economic impact and that the Market Working Group build greater consensus among the membership. (See “Board Forced to Table NDVER Conversion Change,” SPP Board of Directors/Members Committee Briefs: April 24, 2018.)

MWG Chair Richard Ross, of American Electric Power, began discussion of the change by noting he was one of the few people in the meeting room wearing a tie.

“I’m not trying to make anyone nervous,” he quipped. “But if you get unruly, I’ll take the tie off.”

There was no need. The measure passed with more than 81% approval, almost 20 points better than it fared in April. It was opposed by only two transmission owners (Empire District Electric and Omaha Public Power District) and eight transmission customers with various ties to renewable energy. Seven transmission customers abstained.

“We wanted to see this happen, sooner than now,” said Southwestern Public Service’s Bill Grant. “This is a compromise we can live with. It took a lot of work to get to this point, but we’ve moved to a point where most people are happy.”

Staff shared its analysis of RR272’s economic effects, which compared the conversion of NDVERs to DVERs against a base case using real-time security-constrained economic dispatch data. They found the conversion resulted in improved congestion management and, with it, better convergence of real-time and day-ahead prices. That resulted in about $15,000 in additional monthly real-time energy payments to converted NDVERs and about $20,000 in additional revenue to other resources.

The data also indicated a significant reduction in the number of operating hours with negative pricing.

The MWG revised the proposal to exempt run-of-river hydro not capable of following dispatch instructions and to provide additional time for certain NDVERS to convert. They now face a deadline of either Jan. 1, 2021, or the 10-year anniversary of a resource’s original commercial operation date.

Market Monitoring Unit Executive Director Keith Collins said he supports the proposal, saying the benefits come from “an increase in prices at locations that are primarily non-dispatchable.”

“We’re investing upgrades for controls we don’t own, which increases the [power purchase agreements] for our customers. That’s not something we’re keen on,” said Empire’s Aaron Doll. “Our specific limitation is contractual language that limits curtailments to a certain amount in a 24-hour period. The dispatch signal puts us in bad spot pretty quickly. Anything short of providing an exemption for entities with contract language that precludes curtailment is not something we can support.”

The MOPC also approved RR266, which would model a joint-owned unit (JOU) as a single resource in market-clearing decisions, while performing an after-the-fact allocation of revenues based on ownership shares. Other JOU shares would be used for settlement purposes, and each share would exist only in the context of settlements where final clearing results are split based on the submitted ownership share percentages.

The change is contingent upon final approval by the Regional Tariff and Operating Reliably working groups. Nebraska Public Power District and Oklahoma Gas & Electric’s Transmission and Electric Services divisions opposed the measure, citing problems with the language.

“We have a couple of JOU situations we manage fine ourselves,” said OG&E-Transmission’s Greg McAuley. “We’ll continue to pound the table as it relates to some of these administrative costs.”

Stakeholders approved against minimal opposition three other revision requests brought forward by the MWG:

- RR306, which would minimize potential gaming opportunities identified by the MMU. The change allows market-committed resources that have a minimum run time extending beyond initial reliability unit commitment or day-ahead commitment periods to be eligible for make-whole payments after their initial commitment period.
- RR304, which streamlines the process by which frequently constrained areas are re-evaluated, in order to make adjustments in a timely manner.
- RR312, which would calculate the FERC Schedule 12 rate based on current data. The change aligns the collections of revenue against the customers’ megawatt-hours being assessed.

SPP Prepared for January’s ‘Big Chill’

Staff’s update on what they call “The Big Chill,” the abnormally frigid temperatures Jan. 17-18 that led to heavy north-south transfers of MISO flow across SPP’s system and a maximum generation alert in MISO South, caused one member to recall his scouting days.

“I wouldn’t call this an emergency event,” said MOPC Chair Paul Malone, of NPPD. “It was pretty well known we would have severe weather over a wide area. That begs for proper planning. As the Boy Scout motto says, ‘Be prepared!’”

“Let’s just say, some people are surprised every day by what happens,” said SPP COO Carl Monroe, “and some people were surprised that day.”

MISO exceeded its 3,000-MW regional dispatch limit on transfers between its North and South regions over the SPP system during the event and was forced to make emergency purchases from Southern Co.

SPP Vice President of Operations Bruce Rew said the RTO never had to issue an emergency alert, as it was never short of generation. “It was uncomfortable for us,” he said. “We have to make sure it doesn’t happen again.”

David Kelley, SPP’s director of seams and market design, credited SPP’s and MISO’s neighboring reliability coordinators with helping to prevent load shed and keeping the lights on during the event. He said recent discussions among the Regional Transfers Operating Committee (RTOC), a six-person group comprising two representatives each from SPP, MISO and joint parties to a 2016 settlement agreement, centered on better understanding the non-firm, available nature of MISO’s north-south flows and their effects on neighboring entities. (See SPP, MISO Reach Deal to End Transmission Dispute.)

“Anything over 1,000 GW is on a non-firm, as-available basis. To us, that means SPP’s service should not be in jeopardy of load shed,” Kelley said. “When this event happens again, and will happen again, we’ll be prepared.”

Kelley said staff has also met with FERC staff to “ensure FERC had a clear understanding of what happened that day,” given “very inaccurate statements that found their way into the media.” (See SPP Seeks FERC Meet in MISO Tx Dispute.)

Kelley also briefed the MOPC on a proposed interregional project with Missouri-based Associated Electric Cooperative Inc., a new 345/161-kV transformer at AECI’s Morgan Substation near Springfield and the rebuild of a 161-kV line.

The project’s regional cost allocation was rejected by FERC last year. (SPP would be responsible for 89% of the $13.75 million in engineering and construction costs). SPP staff have since developed data that indicate the project would yield the region $17 million in load ratio share benefits by eliminating the need for upgrades at City Utilities of Springfield’s John Twitty Energy Center and also reduce day-ahead market uplift costs.

“We feel like we’re in much better shape,” said Kelley, who met with FERC staff on July 12. “They look forward to seeing our next filing.”

Kelley said that filing should be made in late July or early August.

Stakeholders Endorse $47.4 Million in Near-term Tx Work

The MOPC endorsed the Transmission Working Group’s recommendation to approve the Integrated Transmission Planning process’s 2018 near-term assessment portfolio, a package of 13 transmission projects with an estimated cost of $47.4 million

However, when taking into account four withdrawn projects from previous assessments that cost a total of $53 million, the portfolio has a net cost of -$5.6 million.

Several of the Kansas and Missouri projects are being driven by the retirement of about 1.9 GW of 50- to 60-year-old generation later this year and in early 2019.

The projects will solve 101 reliability needs. They include a new 345-kV, 50-MVAR reactor at City Utilities’ Brookline substation, a project originally identified as an interregional project with AECI.

OG&E’s Travis Hyde, who chairs the TWG, noted SPP approved nearly $8 billion in construction between 2006 and 2014. With the strategic shift to maintaining “an economical, optimized transmission system,” he said, the RTO has since approved just more than $1 billion in base plan funded investment.

Staff developed a summary presentation of the assessment using a story map tool.

Stakeholders also endorsed NorthWestern Energy’s sponsored upgrade of less than 4 miles of new 115-kV line in Aberdeen, S.D., and a working group recommendation to approve the 2019 ITP’s needs sensitivity scope addressing study results affected by Lubbock Power & Light’s potential exit from the system.

RC Efforts in West Absorb MWTG Integration

Monroe told members that the integration of the Mountain West Transmission Group has been “subsumed” in the debate out West over who will provide reliability coordinator (RC) services — a debate that involves SPP.

The RTO said in June that it plans to offer RC services in the Western Interconnection, matching an earlier announcement by CAISO. Not coincidentally, Peak Reliability said last week it will wind down its RC role by the end of 2019. (See related story, Peak Reliability to Wind Down Operations.)

SPP’s Carl Monroe (c), NPPD’s Paul Malone, NE Texas Electric Co-op’s Jason Atwood, GDS Associates’ Jack Madden anchor the MOPC’s head table. | © RTO Insider

“There’s still interest in [joining SPP],” Monroe said. “The importance of making sure RC is provided, and in an efficient and reliable way, has subsumed their work right now.”

SPP’s efforts to integrate Mountain West were dealt a blow in April when Xcel Energy announced it was withdrawing from the Rocky Mountains group and its efforts to join the RTO. (See Xcel Leaving Mountain West; SPP Integration at Risk.)

Monroe said there have been no changes to the Mountain West’s initial proposal to join SPP, adding he hopes to be able to provide “what kind of a footprint we would have with RC services” by Sept 1.

“As we work through the process, our intent is to meet the goals of what we normally do through contract service, which is providing benefits back to the members themselves,” he said.

MRO’s Patrick Welcomes New Entities

Midwest Reliability Organization CEO Sara Patrick introduced herself to SPP members, many of whom were among the 100 registered entities that joined the organization after the SPP Regional Entity’s recent dissolution. (See SPP RE Ending Compliance Monitoring, Enforcement Activities.)

Patrick said all compliance monitoring and enforcement program (CMEP) data was successfully transferred from the SPP RE to MRO on July 3, and that all entities in its expanded footprint are now using MRO’s webCDMS portal.

Patrick gave credit to the SPP RE’s staff in a “well-coordinated” transition and data transfer. The $1.5 million in transition costs will be recovered by transferring assessments from the SPP RE to MRO, she said.

The MRO’s board of directors last month approved a $4.3 million increase, reflecting the expanded footprint. Patrick said the budget will result in $4.8 million in savings, when compared to the combined MRO and SPP RE budgets.

The board also agreed to add four new directors next year, including two regional directors from the SPP RE’s footprint.

MOPC Sends Two Initiatives Back

The MOPC declined to take action on a pair of work efforts, asking that both be returned to the stakeholder process for further clarification.

Following an update on SPP’s prioritization process for revision requests and project proposals, stakeholders debated potential improvements to the process before the committee’s leadership said it would return to the next meeting in October with ideas on how to proceed.

Stakeholders complained about a lack of transparency, the amount of information they had to deal with and not knowing where decision-making authority lies. Staff said it stopped the quarterly meetings because of a lack of feedback.

Several members familiar with ERCOT’s stakeholder process suggested the Texas grid operator’s Protocol Revisions Subcommittee (PRS) as a good model to follow. Tenaska’s John Varnell, who once chaired the PRS, said if members listened in on the group’s meetings, “You will see how we can do better at this process.”

“That’s one thing that ERCOT does quite well,” said Golden Spread Electric Cooperative’s Mike Wise, who sits on ERCOT’s MOPC equivalent, the Technical Advisory Committee.

“[The PRS] does a really good job of ensuring financial stability or accountability. [Members] debate [revision requests] quite substantially before they ever enter in the queue for approval at the TAC. Many of us want this to be like what we have at ERCOT. It puts more decision-making in the hands of the stakeholders, rather than SPP.”

Grant, who headed the task force that developed the prioritization process, called for more stakeholder involvement in the process. He reminded the committee that the task force hasn’t been disbanded.

“If we’re going to spend the time and effort to improve the process, we need better participation and more dedication to the issue,” he said. “It doesn’t matter what we set up if the stakeholders aren’t going to participate in the process.”

The MOPC also sent back a Credit Practices Working Group (CPWG) revision request, saying it needed more information and noting the Finance Committee had tabled the request. The CPWG reports to the committee.

The CPWG’s RR311 would change the way reference prices are used to estimate the settlement exposure of transmission congestion rights (TCRs). The group’s analysis of a two-year period indicated its proposed methodology would have reduced collateralization in the TCR market by $124 million to $327 million, and more than doubled under-collateralization from $17 million to $39 million.

Staff recommended tabling the change, saying it needed more analysis in light of a market participant’s recent default in PJM’s financial transmission rights market. (See “Credit and Default,” PJM MRC/MC Briefs: June 21, 2018.)

“It sounds like the hesitancy to move forward is lack of understanding of what’s happening in the PJM situation,” said Kansas City Power & Light’s Denise Buffington.

Given that the CPWG has yet to gain approval from the Finance Committee and the Regional Tariff Working Group, stakeholders agreed to send CPWG RR311 back to the working group so that it can be properly shepherded through the stakeholder process.

Members Endorse RRs, Process Language Change

Members endorsed language changes to improve efficiency of the revision request process by reducing the time it takes to gain approval for a change and removing duplicate references that cause unnecessary changes.

The proposal (RR291) would allow a revision with approved “normal status” to progress through the stakeholder process while its primary working group waits on the impact analysis. It would also revise language to reference the applicable documents as SPP revision request documents and remove their multiple references.

The MOPC’s consent agenda, which passed unanimously, included nine revision requests and a new baseline cost estimate for SPS’ 115-kV loop rebuild in West Texas. The project’s original cost of $28.4 million was reduced almost 23% to $21.9 million.

- BPWG RR307: Clarifies that partial service may be offered to short-term transmission service requests when the full amount requested cannot be granted.
- CTPTF RR279: Modifies the competitive project proposal process to allow a re-evaluation request before awarding a notice to construct.
- MWG RR177: Clarifies references to NERC standards in the Integrated Marketplace’s protocols and the Tariff’s Attachment AE, the marketplace’s governance, to eliminate confusion over whether entities are performing obligations for market or NERC standard reasons. Also modifies the attachment’s definition of operating reserve to that defined in the Tariff.
- MWG RR277: Corrects language in Attachment AE to accurately reflect the settlement formula for the auction revenue rights daily amount by reversing the sequence of the source and sink.
- MWG RR310: Adds three reporting requirements to comply with FERC Order 844: zonal make-whole payment reports, resource-specific make-whole payment reports and operator-initiated commitment reports. Also requires public posting of transmission constraint penalty factors; circumstances if violation relaxation limits (VRLs) could set prices; and procedures for temporarily changing VRLs in the Tariff.
- ORWG RR309: Removes section 7.3.1 (FAC-011-3 System Operating Limits Methodology) from SPP’s planning criteria and places it in a separate document for reliability coordination purposes.
- RTWG RR278: Corrects Attachment O’s Addendum 1 to include only current and applicable interregional coordination agreements and an update link to the joint operating agreement with MISO.
- RTWG RR315: Removes references to the SPP RE in the governing documents.
- RTWG RR314: Adds clarifying language to the ITP manual addressing ambiguity in the base reliability and short-circuit model builds.

— Tom Kleckner