Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members Committees on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider. RTO Insiderwill be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:30)
Members will be asked to endorse the following manual changes:
C. Manual 14A: New Services Requests Study Process and Manual 14G: Generation Interconnection Requests. PJM is seeking to split out part of Manual 14A into a new Manual 14G to better organize interconnection information. (See “Interconnection Procedure Split,” PJM PC/TEAC Briefs: June 7, 2018.)
3. Governing Document Revisions for Seasonal Demand Response Registration (9:30-9:45)
Members will be asked to endorse revisions to Manual 18: PJM Capacity Market, the Tariff and the Reliability Assurance Agreement associated with the registration process for aggregated seasonal demand response resources. (See “Seasonal Aggregation,” PJM Market Implementation Committee Briefs: July 11, 2018.)
4. Revisions to RAA and Manual 18: PJM Capacity Market (9:45-10:00)
Members will be asked to endorse revisions to the RAA and Manual 18 associated with changes developed by the Demand Response Subcommittee to address issues identified with atypically low customer load during winter peak load calculation period. The Market Implementation Committee endorsed the changes in June.
5. Fuel Requirements for Black Start Resources Problem Statement & Issue Charge (10:00-10:20)
Members will be asked to approve a proposed problem statement and issue charge on fuel requirements for black start resources. (See “Black Start Fuel Assurance,” PJM Operating Committee Briefs: July 10, 2018.)
6. FTR Credit Proposal (10:20-10:50)
Members will be asked to endorse proposed Tariff revisions to implement a 10-cent/MWh minimum monthly credit requirement for financial transmission rights bids submitted in auctions and cleared positions held in FTR portfolios. (See “Credit Requirements,” PJM Market Implementation Committee Briefs: July 11, 2018.)
Members will be asked to endorse one of four proposals on what maintenance cost components should be included in generators’ cost-based offers. A proposal sponsored by American Electric Power will be considered first, followed by proposals from PJM, the Independent Market Monitor and Rockland Electric. (See “VOM Update,” PJM Market Implementation Committee Briefs: July 11, 2018.)
Members Committee
1. FTR Credit Proposal (1:10-1:25)
Members will be asked to endorse proposed Tariff revisions to implement a minimum per-megawatt-hour FTR credit requirement. (See MRC item 6 above.)
Members will be asked to endorse the proposal on where and how to include VOM costs in generators’ offers that is endorsed in the MRC meeting. (See MRC item 7 above).
Middle America is falling behind other U.S. regions in the adoption of electric vehicles, but utilities could play a key role in turning that around, according to a group of industry leaders, government officials and automakers.
“We clearly are not anywhere near California in terms of adoption to date,” Great Plains Institute Vice President Brendan Jordan said of the MISO footprint during an interview with RTO Insider.
Jordan said the midcontinent region — the Midwestern states and those directly south of them — lacks state-by-state policies like a zero-emissions mandate on car sales or incentives that automakers refer to as “cash on the hood” that can reduce the cost of a new EV.
He pointed out that — for a time — Georgia had one of the highest rates of EV sales in the country because of a state policy that offered a $5,000 tax credit. Sales in the state dropped sharply when Georgia ended the program in 2015.
Jordan’s views are backed by findings in an April white paper from the Midcontinent Transportation Electrification Collaborative (M-TEC), a joint effort of GPI and ChargeUp Midwest. The group comprises more than two dozen state government representatives; electric utilities and cooperatives; charging companies; environmental organizations; and automakers General Motors and Nissan.
The group’s aim: to increase EV use and infrastructure and decarbonize the transportation sector. It says that with some grid transformation, meeting EV demand could concurrently benefit utility customers, the economy and the environment.
But the MISO footprint — along with Ohio — currently has inadequate charging infrastructure to support widespread EV adoption, the white paper contends.
“The midcontinent region is falling behind other regions and falling behind what analysis indicates is needed in preparing for increased EV adoption. … Adequate public charging is a prerequisite for increased EV adoption as cited by numerous studies that establish a connection between EV adoption and adequate charging infrastructure,” M-TEC said.
Utilities Need to Lead
ExxonMobil estimates about 100 million EVs will be in use worldwide by 2040; Bloomberg puts that figure at 530 million. The National Renewable Energy Laboratory recently predicted that about 600,000 charging plugs will be needed to support about 15 million EVs in the U.S., with 400 DC fast-charge stations needed along interstates for long-distance travel.
Jordan said utilities should take the lead in encouraging adoption when states elect not to create incentives.
“Some investment from utilities might help adoption,” he said.
Utilities can provide education and outreach, monetary assistance for charging and reduced rates for charging times, Jordan said.
And he thinks that while states’ roles in stimulating EV purchases should not be ignored, utilities are positioned to act today, a sentiment echoed in the white paper.
“We’re not saying that states won’t or shouldn’t take action. Obviously, states should take action. We wanted to separate out that role that utilities can play independent of state policy,” Jordan said. “I think the point is the utilities don’t need to wait around for states to take action. There are moves they can make that are good for the environment and good for their customers. They shouldn’t wait around for states to take the lead.”
That’s not to say midcontinent utilities are completely inactive on the EV front. Earlier this month, DTE Energy filed a $328 million rate request with the Michigan Public Service Commission that includes a $13 million pilot program for EV charging stations, while Consumers Energy also recently proposed a $7.5 million EV pilot program.
AEP Ohio’s $10 million EV pilot program won approval from the Public Utilities Commission of Ohio in April, and Xcel Energy that month also rolled out a revised charge-at-home pilot program for 100 customers after gaining approval from the Minnesota Public Utilities Commission. Madison Gas and Electric also maintains charge-at-home pilot program where customers can have a car charger installed for a $20 monthly fee.
While private charging companies and automakers’ public stations should exist, Jordan said the reality is most EV charging will be done at the residential level.
“Charging on a public station at a fast-charge station while on a road trip isn’t a big part of use, but it will be critical,” Jordan said. “The fact is that 90 or 95% of charging is going to take place at home.
“I don’t think anyone is saying that utilities should make all those investments, but the fact is that there’s a gap there,” he said. Jordan pointed out that up to 15% of each state’s settlement from the Volkswagen emissions scandal can be spent on light-duty EV infrastructure, and Minnesota has already issued a request for proposals for DC fast-charging stations using its Volkswagen settlement funds.
Electric demand from EV charging could boost sluggish load growth, M-TEC says. “Transportation electrification is a huge part of that,” Jordan added.
Jordan thinks EVs can absorb MISO’s abundant nighttime wind generation. The M-TEC white paper argues EV adoption would only minimally increase the daily system peak, and that the controllable nature of EVs can over time can flatten the load curve and increase overall system efficiency.
“I think, generally speaking, there needs to be programs in place to control when charging takes place,” Jordan said. “At high levels of EV adoption, you can make a real observable difference in the load curve.”
The white paper points out that multiple studies from consulting firm M.J. Bradley project that additional utility revenues from EV charging will likely exceed the cost to supply the demand, putting downward pressure on utility rates.
Jordan also says interested consumers don’t have to wait until the later 2020s to purchase EVs, when costs are expected to fall into parity with traditional vehicles.
“I would argue that regular folks can afford some form of EV today,” he said, adding that used EVs are becoming more available as leases are turned in. Operations and maintenance are much cheaper over the life of the car despite a high upfront cost, he added.
Jordan also said EV fuel costs tend to be spent locally because they draw from a local electric source. “You can power a car on electricity a lot cheaper than you can power it on fuel or diesel,” he added.
Decarbonized Everything
With the white paper published, the group will now focus on modeling a completely decarbonized transportation system in the midcontinent to show it is economically feasible. Jordan said the modeling will be completed this fall.
Meanwhile, the group will hold a one-day conference July 24 to reveal a plan to completely decarbonize the electric sector by 2050.
“Step 1 is electric sector decarbonization and step 2 is transportation decarbonization,” Jordan explained.
He also said GPI and Midcontinent Power Sector Collaborative are in the process of raising money to model decarbonized buildings, industry and agriculture.
“We plan to model the entire [decarbonized] economy eventually,” Jordan said.
SCOTTSDALE, Ariz. — The Electric Power Research Institute says electrification of transportation and buildings could boost U.S. electric load growth by as much as 52% by 2050. That’s 1.2% per year.
“Compared to 2005 to 2015, that’s a lot. … Compared to the 1990s, that’s not much,” said Tom Wilson, EPRI’s principal technical executive, who briefed state regulators on the organization’s April 2018 National Electrification Assessment at the National Association of Regulatory Utility Commissioners’ Summer Policy Summit last week.
The promise of electrification, and the challenges to achieving it, were recurrent themes at the NARUC conference, which attracted more than 800 regulators, utility officials and others.
Charging Infrastructure
Speakers said reducing electric vehicles’ costs and increasing charging infrastructure are among the biggest obstacles to reaching the top end of EPRI’s forecast (its “Transformation” scenario, which assumes a $50/ton CO2 price in 2020).
Transformation scenario projections for U.S. total final energy by fuel (left) and electric demand by sector (right). | National Electrification Assessment, EPRI
“We have to get cost out of the vehicle without sacrificing durability, reliability,” Britta Gross, General Motors’ director of advanced vehicle commercialization policy, said during a dinner panel sponsored by the Brattle Group on the sidelines of the conference. “The next four or five years will be crucial.”
Former NARUC President Phil Jones, now executive director of the Alliance for Transportation Electrification, decried the “woefully inadequate” vehicle charging infrastructure during the Brattle panel and an earlier NARUC session on the effects of electrification.
Jones said developing DC fast-charging infrastructure will be challenging for regulators because the system is likely to see low utilization rates initially. That will call for creative rate structures, said Jones, who served 12 years on the Washington Utilities and Transportation Commission.
“The problem is demand charges kind of kill the business case for that. So, for utilities to put that into a proposal, you all are going to have to grapple with that,” he told the regulators. “Do you spread those costs out over two years, five years, 10 years?”
Gross said the U.S. has only 1,300 DC fast chargers, which can deliver 50 kW and provide a 90-mile charge in 30 minutes. “We need 10 times as much DC fast charging and 20 times as much Level 2 charging,” a 240-V AC outlet that can charge in 5.5 hours.
“Benefits accrue at scale,” she said. “How do we get there?”
Utilities’ Role
The Brattle panel focused on whether utilities should help build some of the infrastructure.
High level overview of modeling results | National Electrification Assessment, EPRI
“Absolutely they should [be involved] … because there are market failures and gaps today,” Jones said. “The infrastructure we have through the non-utility competitive model today is totally insufficient in each of the states that you live in. Do the utilities need to do everything? No, but the utilities in our view … have a very important role in catalyzing the market.”
Attorney Paul Afonso, a board member of Braemar Energy Ventures, disagreed with Jones’ declaration that the market has failed. Braemar has invested $141 million in ChargePoint, which builds EV charging infrastructure.
“We can’t condemn [the market] to failure before we get it to start,” he said. “The utility has a relationship … with their customers that’s unique. … There need not be, nor should there be, disintermediation between that. So [ChargePoint is] working with pilots in Columbus with [American Electric Power]. That [charging] station [is branded] AEP. And it’s our network that runs the network software.”
Brattle principal Jurgen Weiss said European regulators have generally opposed utility ownership of charging infrastructure. “There are lots of potential players out there. It’s entirely understandable how it could be a competitive service — in the long run. But we’re not in the long run; we’re hardly in the short run. … We’re trying to get something to scale.”
Weiss insisted the need for capital is so large there will be room for investments both by utilities and private capital.
“It’s worth considering utilities being part of this game for the next ‘X’ years, and then … we can collectively reconsider whether this is not a flourishing competitive market,” he said.
To overcome range anxiety, drivers need to know charging stations are available “even if they will never use” them, Weiss continued. “We will probably need to build more than we need.”
Indeed, according to Gross, 95% of vehicle charging currently occurs at home or work. How the charging network is marketed may be more important than its size, she said.
“If you could just find a way to tell a story better with 20 stations around your state, it’s a lot better than wasting your money on 200 stations. … In Michigan, if every DC fast-charge station was near a lighthouse in Michigan you’d [say], ‘Oh, I know what that means,’” she said. “Storytelling can go a long way to raising the perception of the availability of infrastructure without having to make it ubiquitous.”
Jones said the development of charging infrastructure has been hurt by proprietary charging systems that “can’t talk to each other.”
“It reminds me of the telecom days 10 to 15 years ago. So, we have Tesla with a proprietary system. We have many … vendors building out proprietary systems, both on the network management side — the back end — and even on the front end, we have plug issues.”
Jones said regulators should insist on open standards as a condition for ratepayer-funded investments by utilities.
Utilities also will have a role in planning systems, Jones said. “We have the West Coast electric highway. This was politically driven by the governors and state [transportation departments]. They decided [to use] DC [fast charging]. … Has that been incorporated into the utility [integrated resource plans] in Oregon, Washington and California? No. … We have the Electrify America Network that’s building out a charging infrastructure on its own. Is that coordinated with the [state] commissions? … No. … From a planning standpoint it’s kind of a mess, so I would just posit that the utilities have a big role to play.”
Jones said several states are leading the transition to EVs, naming Michigan, Maryland, Ohio, Washington, California and Oregon.
Role for Oil Companies?
From the Brattle audience, Betty Ann Kane, chair of the D.C. Public Service Commission, asked why service stations haven’t jumped at the chance to install charging stations.
Gross said oil companies have shown little interest “in what feels like a logical answer.”
Jones said his organization has talked with the American Petroleum Institute and National Association of Convenience Stores.
“They are studying the opportunity … but they aren’t coming around to the realization that this is a real opportunity. And in fact, in many states in the Midwest, they are opposing us. … And others in the industry are kind of aligning with the oil and gas interests to oppose utility investments in this infrastructure.”
Weiss was blunt. Oil companies “want to slow this [transition away from gasoline-powered cars] down as long as they can,” he said. “The oil companies are going to come around. The question is how quickly.”
New Value Proposition
Weiss said EV proponents need to change the way regulators look at benefits and costs, noting that electricity purchases represent only 1.6% of disposable income. “There’s just not a lot of money in there compared to the [fuel cost] savings [of] changing from internal combustion engine car to driving an EV. … You probably don’t even have to look at greenhouse gases” as a benefit.
Emily Levin of the Vermont Energy Investment Corp. raised a similar concern in a second NARUC session on energy efficiency’s role in electrification.
“The boundaries we’ve drawn in a lot of cases around energy efficiency programs are too narrow, in having goals around kilowatt-hour savings,” she said. For example, EE programs on heat pumps “often don’t count the fuel savings, the gas or the oil savings. … They only count the increment of savings from an efficient heat pump over a baseline heat pump. … They’re leaving a lot of savings on the table.”
She called for “next generation” goals that consider carbon emissions or focus on peak demand reductions rather than baseload cuts.
In the same session, Jim Lazar, senior adviser for the Regulatory Assistance Project, recalled his work on projects 30 years ago that concluded that natural gas space and water heat were superior to electric space and water heat for new construction. “But then heat pumps weren’t very efficient. Heat pump water heaters weren’t available. Wind and solar were not real grid resources,” he said. “Every assumption we made in those papers is now obsolete.”
Now, he said, the most efficient new homes use too little energy to justify both natural gas and electric service connections.
Sheryl Carter, director of the Natural Resources Defense Council power sector, briefed regulators on the findings of the organization’s 2017 study outlining a strategy for reducing greenhouse gas emissions by 80% by 2050 from 1990 levels through increased efficiency, electrification and renewable generation. It envisions electricity supplying 45% of all energy needs, up from the current 20%.
NRDC says its strategy would increase U.S. energy costs by only 1%, an annual cost of $22 billion that it says would produce more than $154 billion a year in health and environmental benefits.
In an earlier NARUC session, Chris McGill, vice president of energy analysis and standards for the American Gas Association, criticized those who want to quickly eliminate fossil fuels.
“What problem are you trying to solve?” he asked. “Is natural gas no longer a good consumer value? Do we no longer have an enormous resource base? Do we no longer have a huge legacy infrastructure? … Natural gas use in the household here in the U.S. accounts for 4% of greenhouse gas emissions … a pretty small target.”
McGill cited an AGA-funded study that found a “policy-driven” electrification of the residential sector would cost $590 billion to $1.2 trillion by 2035, the equivalent of $572 to $806/ton of CO2.
“When I hear discussions around electrification — that it’s going to happen very quickly … and it’s not going to cost anybody anything, I believe that is preposterous.”
SCOTTSDALE, Ariz. — It used to take SUEZ in North America four years to apprentice an operator at its Boise, Idaho, water utility, with its 90 “pressure planes” (service territories), 80 tanks and 60-plus source wells.
But after developing an algorithm based on 10 years of supervisory control and data acquisition throughout its network, SUEZ created a system that sets the optimal setting for every pump and integrates data from its power utility to determine the best time to run them.
The result: a 10% reduction in the water company’s energy demand and a $350,000 rebate from the power company.
But that wasn’t the biggest achievement, David Stanton, SUEZ’s president of utility operations and federal services, told the National Association of Regulatory Utility Commissioners’ Summer Policy Summit last week. Stanton was invited to speak at Monday’s general session by NARUC President Jack Betkoski, who has made the “water-energy nexus” the centerpiece of his year as head of the state regulators.
“Because we’re capturing knowledge in the system, we now can train operators within six months,” Stanton said. “So we’re actually solving what I think is a much more systemic big problem” — an aging workforce.
Stanton said the new system illustrates his company’s need to “reinvent” its information technology. “Traditionally we talk about technology in the context of physical assets. But more and more I’m thinking that the data … that’s coming is going to change the physical technology asset that we want to deploy dramatically. So we really have to solve for data innovation first.”
That means not using enterprise resource planning (ERP) systems like SAP and Oracle for managing big data. “You need ERPs for financials and maybe billing, but you want an innovative environment … that is safe and secure and isolated from your ERP. The future of IT has much more to do with the sources of data and operations than it does big back-office ERPs.”
‘Benchmark Like Crazy’
Four years into what Stanton called the company’s “smart utility” program, he shared his lessons learned.
“We benchmark like crazy. Everything we do that we like, we go find somebody that’s already done it and does it really well. And we go worldwide with the benchmarking.”
SUEZ implemented innovations “at scale” but at one regional utility at a time, Stanton said. “And then once it worked, we hopscotched that out to other regions.
“We never went out and did everything at once, and as a result, we were running 12 or 14 projects around our utility footprint nationwide. … We never bet the ranch on one idea. If something didn’t work, we could throw it out.”
But getting other regions to buy in was a problem, Stanton said. “A lot of utilities run their regions with a strong president or general manager for each region. Getting them to work together … is like a ‘Game of Thrones’ type of activity.
“Once we had enough of these project implementations working, I made 50% of the bonus of each leader dependent on their ability to get what they implemented adopted by the other utilities. So half their bonus all the sudden was based on, ‘If I do it your way for your project, you have to do it my way for my project. We’ve got to work this out.’
“In two weeks, we had everything worked out. We had heard for years that New York couldn’t do it like New Jersey. … So that solved the cultural problem almost overnight.”
Also appearing on the panel was Oded Distel, founder and director of Israel NewTech, a program in the country’s Ministry of Industry, Trade and Labor that supports research in the water and renewable energy sectors. Distel described how Israel overcame the reluctance of utilities to become the “first customer” for new technologies.
“We encourage utilities … and tech companies to come together. They form a joint project for the first implementation of a new technology and then the government supports those projects. The money is not huge but … the guy who has to make the decision — the head of the utility, the chief engineer — feels that he’s not alone. He’s part of a national effort. … If something fails, he’s not left there alone to pay the price,” Distel said. “The influence over the utilities was amazing. All of the sudden, they opened up, and they started thinking and having discussions in a totally different manner.”
Dan Arvizu, recently appointed chancellor of New Mexico State University, told regulators about his experience as director of the National Renewable Energy Laboratory between 2005 and 2015.
“Even though our public policy at the federal level — and many times at the state level — aspired to do certain things, the technology was typically ahead of the policy, and the finance was way behind,” he said.
He offered his own advice for innovating: “You need to think big, you need to try small, you need to fail fast and then regroup and then try and scale again.”
And he had a warning for utilities about the new customer choices that will become available from the falling prices of renewables and energy storage. “If utilities are not on the forefront [of the transformation], they could become obsolete,” he said.
SCOTTSDALE, Ariz. — The natural gas industry found itself on the defensive at the National Association of Regulatory Utility Commissioners’ Summer Policy Summit last week as panelists debated pipelines’ resilience and ability to withstand cyberattacks.
During a panel ominously titled “Handling and Preparing for Attacks on the Natural Gas Network from Rising Cyberthreats,” Rebecca Massello, of the Interstate Natural Gas Association of America (INGAA), noted there were no gas outages during last winter’s “bomb cyclone” for generators with firm service.
“What history shows is that pipeline outages are very rare, and when they do occur they’re localized in nature. And I want to tell you, that’s not by accident,” said Massello, director of security, reliability and resilience for the group, which represents interstate pipelines. “It’s actually inherent in the way the system is designed and the way it has continued to evolve over time. Today we have more supply diversity than ever before, with natural gas regions all over the country. We also have more looping lines and multiple pathways to reroute gas in the event there is an incident.”
“Interconnects and multiple pipeline feeds support system resilience, help with contingency planning and keep disruptions localized,” said Kimberly Denbow of the American Gas Association, which represents local distribution companies. “Because of the way natural gas utilities must operate, blackouts … and rolling brownouts are not operationally feasible. We build resilience on the front end.”
Paul Stockton, managing director of security and risk management firm Sonecon, said he’s less concerned about weather than Chinese and Russian hackers.
Stockton, former assistant secretary of defense for homeland defense and Americas’ security affairs, quoted Director of National Intelligence Dan Coats, who told a think tank earlier this month that the Department of Homeland Security and FBI “have detected Russian government actors targeting government and businesses in the energy, nuclear, water, aviation and critical manufacturing sectors.”
“The warning lights are blinking red again” the way they were before the Sept. 11 attacks, Coats said.
Gas Industry Cybersecurity
Denbow pushed back on suggestions that the gas industry is vulnerable because it lacks the mandatory cybersecurity rules of the electric sector.
“The argument that natural gas systems lack resilience because they lack cybersecurity regulations is unfounded,” she said, calling gas industrial control systems “our crown jewels.”
She said the industry’s cybersecurity procedures are informed by standards, including the Transportation Security Administration’s pipeline security guidelines, the National Institute of Standards and Technology cybersecurity framework, American Petroleum Institute standards and the Department of Energy’s cybersecurity capability maturity model. AGA in 2014 helped create a downstream natural gas information sharing and analysis center (ISAC), which is now located on the floor of the electricity ISAC in D.C.
Communications Disruptions
Stockton cited retired boxer Mike Tyson’s often repeated adage that “‘Everybody has a plan until they get punched in the mouth.’
“I think that’s true for information sharing,” Stockton said. “In a blue-sky day like today — no event going forward — everybody’s sharing better and better. … If there is an attack by a major state on the energy sector represented here, you bet we should assume that adversaries will go against Internet-based communications, public switched telephones — none of that stuff is gonna work. Power companies and natural gas companies have pretty good [communications] inside their own company — push-to-talk radios, things like that. But between sectors: nada, nothing” will work.
Stockton said regulators should identify single points of failure such as multiple utilities using the industrial control systems of the same vendor. “That’s why I’m a big fan of fuel diversity for electric generation,” he said. With nuclear and coal in addition to renewables and gas, he said, “it’s much harder for the adversary to take everything down simultaneously.”
Solutions
Stockton, a consultant for Exelon, which is seeking subsidies for its struggling nuclear plants, says state regulators should help define attributes of fuel resilience and create a “design basis threat” for the electric and gas sectors, like that issued by the Nuclear Regulatory Commission.
“You can fly a 747 into [a nuclear plant] and the containment vessel can survive,” Stockton said. “That’s no accident: There’s a design basis threat that they have to meet.”
(Stockton overstated the NRC’s requirements. In 2009, the commission required all new nuclear plants to ensure their reactor containments could withstand a crash by a large commercial aircraft. But it rejected proposals that existing reactors be retrofitted with similar protections. “Deliberate attacks by large airliners loaded with fuel, such as those that crashed into the World Trade Center and Pentagon, were not analyzed when design requirements for today’s reactors were determined,” the Congressional Research Service wrote in a 2014 report.)
Stockton said industry should prepare for threats like Timothy McVeigh’s 1995 truck bomb attack in Oklahoma City and the coordinated hijackings by al-Qaeda terrorists on Sept. 11, 2001.
“Folks, Russia is not going to attack a single gas pipeline and expose themselves to retaliation. They’re going to try and take down the energy sector. It will be a comprehensive attack.”
Gas industry representatives urged against overreacting to what Massello called the “fear and uncertainty and doubt [of scenarios that haven’t] happened before.”
“Rather than try to fix portions of the system that are not broken, let’s hone in on those areas where concentrated problem-solving will yield measurable results,” said Denbow, who noted that the leading cause of pipeline disruptions is third-party excavation damage.
“For as long as gas utilities must contend with third-party excavators who hit our lines and disrupt our systems, gas control operators will continue exercising their training with respect to rerouting gas supplies and with respect to workarounds, resort[ing] to manual operations when necessary and minimizing the impact to firm service and residential customers,” she said. “This is what they do on a daily basis. This is not new to us.”
In a second panel (“What Does the Future Hold for Gas-Electric Interdependencies and Where Does Resilience Fit In?”), Todd Snitchler, director of market development for the American Petroleum Institute, had a similar message.
“We can’t underestimate the importance of getting this right, but I think we have to keep in balance … to be realistic in our assessment,” he said. “There is a long track record of successful performance.”
In the same panel, Kathleen Barron, Exelon’s senior vice president of federal regulatory affairs and wholesale market policy, said it was too soon to discuss concerns over the potential cost of resilience efforts.
“Our perspective is all this conversation about what’s the remedy, who gets paid, is your interest aligned with mine … is really premature. The question we need to answer is … based on a reasonable set of assumptions, what we should be planning for.”
Referring to PJM’s current fuel security study, she said, “Once that evaluation is done, and we figure out what our vulnerabilities are, then we can figure out how we should … adjust the market rules to accommodate them.” (See Stakeholders Debate PJM Fuel Security Scope.)
Moderator Angela O’Connor, chair of the Massachusetts Department of Public Utilities, disagreed. “I don’t think that any part of that conversation is premature,” she said.
Amanda Frazier, vice president of regulatory policy for Vistra Energy, said it is “disheartening … that the conversation has switched and there’s so much discussion around moving away from markets in the name of resilience.”
“I would dispute the narrative that there’s any particular fuel source that is at risk of extinction,” she said, noting that half of the active nuclear plants receive regulated rates of return. “If all of the subsidized and unsubsidized but at-risk merchant nuclear plants closed tomorrow, we would still have 80% of our civilian nuclear plants up and operating,” she said.
While Vistra’s 10-K securities filing mentions catastrophic events as a material risk, “we mention regulatory intervention in about six different ways … because those are what really keep us up at night: Are the regulators [and] politicians going to continue to support competitive markets, which have delivered resilient and reliable electric generation across this country?”
Pennsylvania Public Utility Commissioner John Coleman said regulators’ decisions have become more complex “as we’ve added in all the other fuel source attributes into this dialog.”
“I hope that we have the intellectual horsepower in this room and within the NARUC community to be able to solve this. … The drama around all of these discussions need[s] to go down a level. … I am confident that we have the ability to figure that out without having external forces trying to dictate how this is going to work.”
PJM on Wednesday ordered its second load-shed event since implementing Capacity Performance in 2015, less than two months after ordering the first. (See PJM Experiences First Load Shed in the CP Era.)
Both events were in the American Electric Power zone.
The July 18 event occurred on the border between West Virginia and Virginia, PJM spokesperson Jeff Shields said. An AEP equipment issue led to other equipment being taken out of service, which resulted in “severe” low voltages in the area around Bluefield and Princeton in West Virginia.
PJM called on AEP at 11:14 a.m. to reduce load in the area by 32 MW to return the voltages to acceptable levels. Keeping the voltages low would have risked “potential further voltage problems and equipment damage that could cause wider problems,” Shields said, but assured that didn’t include any potential for cascading outages.
The order lasted for 83 minutes until PJM canceled it at 12:37 p.m. after the equipment was returned to service. Approximately 13,000 customers were affected.
While both events trigger the significant performance-related bonuses and penalties introduced with CP, no resources were impacted by either incident. The May 29 event was caused by transmission equipment unexpectedly tripping offline in the area of several planned transmission line outages, causing constraints that had potential to cause a cascading outage. (See “Load Shed Details,” PJM Operating Committee Briefs: July 10, 2018.) Prior to these events, PJM last ordered load shedding during the 2013 heat wave.
PJM plans to review the most recent event at its Members Committee meeting on July 23.
VALLEY FORGE, Pa. — PJM on Tuesday rolled out a proposal to procure reserves on a more granular level, a move the RTO hopes will shift more generator revenues back into the energy market.
“I do think that, philosophically, energy is the primary product in these markets,” PJM’s Stu Bresler said at a July 17 meeting of the Energy Price Formation Senior Task Force.
PJM is “not pricing reserves as well as we could,” Bresler said, adding that he expects the revenue distribution between energy and capacity markets to effectively work itself out if reserves prices are developed “as right as we can” make them.
The meeting began with PJM’s Cheryl Mae Velasco and Patricio Rocha-Garrido explaining that under current rules, a unit’s capacity can count as both synchronized reserves and more general primary reserves (which includes non-synchronized reserves), and that a unit would be compensated at a price that reflects providing each. For example, a unit can count as both $20/MW synch and $10/MW primary reserves and be paid a combined $30/MW. The amounts are calculated using “shadow prices” indicated by operating reserve demand curves (ORDCs) that are based on the probability of falling below the minimum reliability requirements for synch and primary reserves.
The shadow prices can vary extensively based on system circumstances, and even fall to $0/MWh, but the penalty factors are capped at $850/MWh. The payment, which is then also combined with a locational LMP, is designed to entice units to respond when called upon.
PJM’s Angelo Marcino discussed staff’s thoughts on how the ORDC can be adjusted to give grid operators more operational flexibility but still make sure that activity is captured in the market. They had been considering developing an “extreme day” ORDC but are now looking at revising on a case-by-case basis to adjust the reserve requirement rather than the slope of the curve, he said. The changes would be classified as either “market” adjustments that are determined through PJM’s clearing engine or “out of market” adjustments that grid operators assign based on issues observed that are not modeled in the RTO’s software.
PJM would ensure real-time notification of the adjustments and be responsible for keeping a historical record of them.
PJM’s Lisa Morelli also discussed staff’s concerns that current reserve zone modeling of the RTO zone with the Mid-Atlantic Dominion (MAD) sub-zone “doesn’t always accurately reflect the constraints dispatch is most concerned with overloading,” which can exacerbate constraints and result in reserve prices that don’t accurately reflect system conditions.
PJM is recommending including nodal reserve pricing and flexible sub-zone modeling in the task force’s discussion. The RTO would define several reserve sub-zones but only tackle one at a time. They could be defined by three categories of constraints: reactive transfer interfaces; 345-kV or larger actual overload constraints; or contingency overloads exceeding the load dump limit on a facility that is 345 kV or larger. PJM would notify participants about their use as early as possible, but provide at least one day’s advance notice.
Each subzone would have its own ORDCs for synch and primary reserves that would remain consistent with the RTO-wide methodology. Staff confirmed that units that hadn’t been assigned for reserves and are offline for some other reason wouldn’t be eligible to receive primary reserve payments.
‘Philosophical Issues’
The proposal sparked discussion from stakeholders about the potential implications.
Susan Bruce, representing the PJM Industrial Customers Coalition, said she was “comforted” to hear that the issues the proposal is meant to address don’t happen often but said she has “philosophical issues” with the market ramifications.
“PJM benefits as a reserve-sharing concept,” she said.
Bresler’s comments about energy as a primary market prompted Roy Shanker, a consultant for several generators, to warn that when the energy and ancillary services markets become “large enough, the behavior of the demand curve has to be examined.”
Bresler agreed that the capacity market’s variable resource requirement demand curve and the energy market’s ORDCs are connected.
Bruce asked that PJM and its Independent Market Monitor attempt to find “areas of consensus” on the topic.
“As much as can be done to narrow those gaps, especially from a customer perspective, that would be highly valued,” she said.
Bresler said staff are “working pretty hard” with the Monitor to come to agreement and that “the sooner that happens, the better off we and the stakeholder community will be.”
PJM also remained noncommittal on Bruce’s request for simulations to see how the proposal shifts revenues between the capacity and energy markets.
“Certainly industrial customers are concerned given their high volume usage,” she said.
PJM staff expressed concerned that stakeholders would judge the proposals on the simulated outcomes rather than the logic of the methodology.
“We do want to have principled reasons for the changes we’re making,” Bruce said, but she added that insight into the potential impact “would be a useful tool … so we can make the right choices before it’s too late.”
James Wilson of Wilson Energy Economics, who consults for several member states’ consumer advocates, said he was interested in “understand[ing] the consequences at a nitty-gritty level, not at an aggregate level.”
Bresler said that could be helpful with the caveat that nothing can be extrapolated to suggest larger consequences.
The meeting concluded with PJM’s Vince Stefanowicz explaining the next steps for developing the real-time 30-minute reserves product. The operational justification and methodology for defining the procurement target were endorsed at the July meeting of the Operating Committee and are moving on to be considered by the Markets and Reliability and Members committees. (See “Real-time 30-minute Reserves,” PJM Operating Committee Briefs: July 10, 2018.)
The price formation task force will focus on pricing the reserve target and optimizing with other ancillary services, determining what resources are eligible and coordinating real-time dispatch, he said.
GT Power Group’s Dave Pratzon asked that the discussion include an analysis to identify why the reserve deficiencies are occurring in the first place.
While the U.S. is keen to benefit from the declining costs of developing offshore wind energy, it appears less focused on learning how the industry matured in Europe, where it was pioneered in 1991.
That’s the assessment of two industry experts who, admittedly, have a stake in the issue.
“We see [regulators] focusing on the generation resource and assuming the transmission is going to be there, and not providing for the transmission necessary to get to scale,” said Stephen Conant, partner with Anbaric Development Partners, an independent transmission company.
The U.S. may be late to the game, but East Coast states are moving fast to join in.
The levelized costs for U.S. offshore wind has fallen steadily, making its development increasingly attractive in the relatively shallow waters off the Northeast coast. | DOI, DOE
In May, New Jersey set a goal of 3,500 MW of offshore wind by 2030, while Massachusetts awarded a contract for 800 MW and Rhode Island agreed to procure 400 MW. In June, Connecticut signed on for 200 MW, while New York regulators this month authorized state agencies to procure 800 MW by next year, the first phase of a plan to develop 2,400 MW by 2030. (See NYPSC: Offshore Wind ‘Ready for Prime Time’.)
Conant and his colleague Kevin T. Knobloch spoke to RTO Insider about Anbaric’s efforts to develop open access offshore transmission grids to facilitate offshore growth, particularly off the coasts of Massachusetts and New York.
Integrated Planning
In contrast to the U.S. approach, the European energy sector first builds out the transmission system and then has generators compete to an offshore interconnection point, Conant said.
“For example, in Germany, rather than have independent generators lead, they have 14 export cables with 34 different generators connecting to them,” Conant said. “That optimizes the export cables so you get the maximum amount of capacity and you optimize the terrestrial interconnection points.”
FERC in February granted Anbaric the right “to charge negotiated rates for transmission rights on a proposed integrated offshore transmission system that includes two HVDC transmission lines connecting Massachusetts offshore wind generation to the ISO-NE transmission system” (ER18-435).
The company’s Massachusetts Ocean Grid project would have two 1,000-MW HVDC transmission lines capable of delivering power from off the coast of Massachusetts to ISO-NE’s Southeast Massachusetts load zone.
Two 1,000-MW offshore platforms with AC switching stations would be linked by a subsea AC cable, and the electric energy would be converted to DC and transferred by two subsea HVDC cables to onshore convertor stations at two separate 345-kV substations.
Legislative Remedy
The Massachusetts offshore wind solicitation (83C) called for an expandable — and nondiscriminatory — transmission system, which means it would be open to all comers and not limited to one developer or generator.
However, nothing in the legislation authorizing the solicitation obligated it to be open to entities other than the generation developers that own the offshore leases.
“We’re in the process right now of some legislative activity to try to make changes in Massachusetts that would allow transmission to be separate from the generation and allow independent transmission companies to participate in that process,” Conant said.
As Massachusetts lawmakers consider a bill (H.4756) to increase the state’s renewable energy and reduce high-cost peak hours, Anbaric is lobbying to include an amendment that would allow independent transmission developers to participate in the next offshore wind solicitation.
“We thought things could be done better, and some of that comes from our looking at what’s been done in Europe, where they really develop the transmission separate from generation, which is really how they do the onshore grid here in the U.S.,” Conant said.
One of the upshots of the European approach: Generators are submitting zero-subsidy bids into the market.
“So you’ve got the generators essentially bidding in at market prices, and we think that’s where folks in Massachusetts and up and down the East Coast want to be,” Conant said. “You don’t need these long-term contracts and subsidies in order to do that.”
New York Groundwork
Anbaric has a history of bringing energy into New York under water. The company was part of the consortium that built the 660-MW Neptune HVDC cable linking PJM to Long Island, and also helped construct the 660-MW Hudson project connecting midtown Manhattan to the RTO.
Knobloch, president of Anbaric subsidiary New York OceanGrid, said the company is preparing a FERC filing for authority to sell transmission rights at negotiated rates both in New York and New Jersey.
Anbaric is focusing much of its efforts on areas off the coast of Massachusetts, which is seeking aggressively to develop offshore wind. | BOEM
Beyond having to navigate multiple regulators, there is also the matter of working through the NYISO interconnection queue, where Anbaric has an advanced position (363) for a 500-MW line connecting into Ruland Road on Long Island because of its work on the Poseidon transmission project, which was intended to bring in power from New Jersey.
“And we have follow-on interconnection requests for an additional 700-MW DC at Ruland Road, and then for a 800-MW AC line up into Ruland Road,” Knobloch said. “Because the queue 363 was part of the Poseidon project, our hope is to win the blessing of NYISO to repurpose that for our offshore wind project, because the on-land route is precisely the same … the material facts are identical.”
Anbaric has also filed an HVDC interconnection request with NYISO for 1,200 MW and additional 800 MW AC into the Farragut substation in Brooklyn for its hoped-for offshore wind grid.
“We wish that the [Public Service Commission] had decided to incorporate planned open access offshore transmission into Phase 1 [of the solicitation], but we note that they signaled that [the New York State Energy Research and Development Authority] should begin thinking about a planned transmission approach now and use the next year or two that way,” Knobloch said. “We appreciate that.”
Anbaric has also nearly completed the New York Department of Environmental Conservation’s environmental permitting process for both the on-land and state waters portions of its offshore grid.
The company several months ago submitted an application with the U.S. Bureau of Ocean Energy Management for rights of way and right of use, which Knobloch expects to be approved within a year, given the Trump administration’s willingness to speed up permitting processes. The process from conception to start of construction for any large transmission project takes roughly eight years, he said.
“Any offshore wind generator who wants to develop transmission, they’re going to have to go through these same processes,” Knobloch said. “To our knowledge, no one else has put in their interconnection requests to NYISO for offshore wind.”
Skewed Background
New York is making a competitive solicitation with only one company, Equinor, owning an offshore wind area lease close to the city. BOEM plans to lease two new areas off the Massachusetts coast later this year and is studying a proposal from New York for additional leases there.
| BOEM
“You’ve got some very large European developers who’ve been successful in Europe, and I think it’s fair to say there’s a degree to which they’re trying to corner the market a bit,” Conant said.
“They’re using a lot of influence and spending a lot of time in capitol buildings, and some of it is a little bit of disinformation,” he said.
For example, Conant contends, those developers don’t tell the full story of Germany’s experience. Although they emphasize the mistakes the industry made in the early years of the offshore wind industry, they neglect to relate all of what they learned.
“But the lesson learned is that you need to do the transmission first,” Conant said.
“Early on in Germany, the delays caused costly headaches. Developers cite that as a reason to have control over transmission, but it’s only part of the story, the beginning,” agreed Knobloch. “The Danes and the Germans quickly moved to planning transmission before soliciting offshore wind generation.”
FERC on Thursday signaled a change in its thinking about how RTOs should allocate costs for projects that improve grid stability, reopening proceedings regarding PJM’s controversial Bergen-Linden Corridor (BLC) and Artificial Island projects in New Jersey.
For reliability projects, PJM assigns 50% of the costs of regional facilities (500-kV lines or higher and double 345-kV lines) and “necessary” lower-voltage facilities required to support regional lines on a load-ratio share basis. The other 50% is allocated using the solution-based distribution factor (DFAX) method. All costs of lower-voltage facilities not supporting regional lines are allocated via DFAX.
Complaints against both projects argued that the DFAX method failed to align allocations with benefits.
In addressing requests for rehearing of complaints about cost allocations for the BLC project, FERC on Thursday ordered settlement judge procedures to urge the parties into settlement, saying the underlying facts in the complaint “have significantly changed” (EL15-67-003, et al.).
FERC also granted rehearing of its April 2016 order rejecting a complaint by Delaware and Maryland regulators, who argued that the DFAX method, as applied to Artificial Island, does not produce an allocation of Regional Transmission Expansion Plan project costs roughly commensurate with the benefits (EL15-95-003).
BLC
The commission urged a settlement of the BLC dispute rather than rule on a rehearing request over its April 2016 order denying a complaint from Linden VFT over the projects and two others totaling $1.3 billion. Linden, Consolidated Edison, the New York Power Authority and Hudson Transmission Partners — the operator of another merchant transmission line into New York City — requested rehearing of the decision.
Since then, one of the projects was canceled and the costs for another were reassigned entirely to Public Service Electric and Gas, so that only the allocations for BLC, totaling $1.2 billion, remain in contention.
Linden’s complaint was that the reliability issues upon which the projects were based are not related to power flows, so PJM’s solution-based DFAX method, which identifies beneficiaries based on flows, did not align costs with benefits. While the formula is split 50/50 between load-ratio share and DFAX, the allocation ends up weighted toward the DFAX. Of the $1.3 billion in allocations Linden initially complained about, approximately $400 million was allocated on a load-ratio share basis and $900 million based on DFAX.
Even though BLC is in PSE&G’s zone, the company was allocated only about $88.4 million of the costs. Con Ed was allocated approximately $720.4 million, Linden $9.6 million and Hudson $103.2 million.
FERC denied Linden’s complaint, ruling that the company failed to prove the DFAX method was unjust and unreasonable. In urging a settlement before ruling on rehearing, the commission said, “the circumstances regarding the cost responsibility assignments … have significantly changed.”
In May 2017, Con Ed canceled a wheeling agreement with PSE&G that had made the wheel part of cost responsibility assignments in the RTEP. With the wheel eliminated, PJM reassigned the costs that had been allocated to Con Ed.
In December, FERC granted Linden’s and Hudson’s request to convert their firm transmission withdrawal rights to non-firm rights, allowing the merchant facilities to escape RTEP cost allocations. PJM subsequently reassigned to PSE&G the costs Hudson and Linden had been allocated. (See PSE&G on the Hook for Bergen-Linden Costs.)
The chief judge has 15 days to assign a settlement judge, who will report back in 30 days after being appointed. The chief judge will then allow more time if a settlement remains unfinished or inform FERC that there’s an impasse that can’t be settled.
Artificial Island
As in the Linden complaint, the commission initially rejected the Delaware and Maryland regulators’ complaint over the use of the DFAX cost allocation for Artificial Island. The project would add new transmission between New Jersey and Delaware to address stability limits on generation at the Salem and Hope Creek nuclear plants and transmission constraints that sometimes prevent the generators from exporting power at full capacity.
The Hope Creek and Salem nuclear units on Artificial Island in southern New Jersey | BHI Energy
About $242 million (87%) of the cost of the project was assigned under DFAX and the remaining $38 million assigned based on load-ratio share.
The state commissions requested rehearing in April 2016, along with the states’ public advocates, Old Dominion Electric Cooperative, Easton Utilities and the Delaware Municipal Electric Corp. LSP Transmission Holdings also requested rehearing separately.
In granting a paper hearing, FERC said it now believes the DFAX method is unjust and unreasonable for projects that address stability-related reliability issues. The commission cited a statement from PJM in the docket that “stability is analytically unique compared to voltage or thermal overloads” because it results from “an imbalance of generation and load caused by a sudden event on the transmission system where the rotational inertia of the generator could cause the generator to lose synchronism with the rest of the transmission system.”
Generators oscillate to re-establish balance, but the severity of the oscillation is dependent on the strength of the transmission system, FERC said. A weaker transmission system will cause the issues to last longer and be more severe, which could ultimately result in damage to the generator and cause additional outages of other system elements. Stability-related projects “provide additional outlets” for generators to address the issues.
FERC established a paper hearing to consider an appropriate alternative. Stakeholders have 60 days to provide their comment on proposals from PJM and Exelon. The PJM proposals were filed in the docket by the state commissions after the RTO unveiled them last year. (See PJM: AI Costs Would Shift to NJ, PA Under New Allocations.)
The first alternative, which PJM called a “direct extension” of the DFAX, would reduce Delmarva Power & Light’s responsibility to about 7% while raising the bill for PSE&G to more than 42%. New Jersey’s other utilities — Jersey Central Power & Light and Atlantic City Electric — would pick up 13% and 7.3%, respectively. PECO Energy would shoulder about 20% of the costs.
PJM’s second “stability deviation method” would allocate 19% to PSE&G, 15% to PECO, 12.5% to PPL, 12.4% to JCP&L, 10.4% to Delmarva Power & Light, 7.2% to ACE and about 5% to Met-Ed.
Exelon presented its proposal as comments in the docket. Its “hybrid method” could assign some portion of cost responsibility for benefits identified by flows on transmission projects that address stability issues in proportion with the benefits identified by PJM’s approaches.
With two commissioners calling for additional action to protect consumers, FERC this week issued a final rule requiring natural gas pipelines to reflect the federal corporate income tax cut in their rates (RM18-11).
The July 18 order largely follows the commission’s Notice of Proposed Rulemaking in March, prompted by the Tax Cuts and Jobs Act, which reduced the federal corporate income rate to a flat 21%. (See FERC Orders Rate Revisions to Reflect New Tax Law.)
The NOPR would have required interstate pipelines to file a one-time report (FERC Form 501-G) to estimate the company’s return on equity before and after the tax cut took effect Jan. 1.
FERC staff present the final rule at Thursday’s commission meeting. | FERC
The final rule makes changes to the proposed form, including eliminating accumulated deferred income tax (ADIT) from the cost of service for pipelines that do not pay taxes — consistent with a separate order on rehearing of its revised policy statement on income taxes, also issued Wednesday (PL17-1-001).
The rule gives a pipeline several options for addressing changes to its revenue requirements, including making a filing under Section 4 of the Natural Gas Act to reduce its rates. Companies that do so will be granted a three-year moratorium on NGA Section 5 rate investigations if the pipeline’s Form 501-G shows an ROE of 12% or less.
Pipelines also can file either a prepackaged uncontested rate settlement or a general NGA Section 4 rate case. The commission said it will not initiate Section 5 rate investigations for pipelines that choose this option by Dec. 31.
The rule will take effect 45 days after publication in the Federal Register.
Call for Congressional Action
Democratic Commissioners Cheryl LaFleur and Richard Glick issued a joint concurrence calling on Congress to amend NGA Section 5 to provide the commission with refund authority like that for electric rates under the Federal Power Act.
“We believe that current law provides a perverse incentive for protracted litigation and creates an asymmetry of leverage between pipelines seeking a rate increase under Section 4 of the NGA and complainants or the commission under Section 5,” they wrote.
| National Fuel Gas
“We believe that our lack of refund authority affected the balance the commission was able to strike in today’s order. It is a clear tenet of cost-of-service ratemaking that tax savings should flow through to ratepayers, and the commission is rightly pursuing that goal in the final rule. However, because our Section 5 ‘stick’ under the NGA cannot effectively deliver timely relief to customers, the final rule proffers a series of ‘carrots’ in the hope that pipelines will exercise their Section 4 filing rights to quickly flow those tax benefits back to their customers. While we think the balance struck in the final rule is reasonable in light of our limited refund authority, we believe that the commission would be better equipped to protect customers if the law were amended.”
Dissents on Certificates
On Thursday, LaFleur and Glick also continued their campaign to force the commission to assess pipeline projects’ impact on greenhouse gas emissions. (See Dem Dissents Show FERC Divide on Carbon.)
Glick dissented on four gas pipeline certificate orders (Columbia Gas Transmission, CP17-80; Texas Eastern Transmission, CP18-10; Northwest Pipeline, CP17-441; and Millennium Pipeline, CP16-486-001).
LaFleur also cited the lack of GHG considerations in concurring opinions on three of the orders and indicated she would issue a partial dissent later on Millennium Pipeline.
GHG emissions are also certain to be a point of contention as the commission reconsiders its 1999 policy statement on pipeline certificates (PL18-1). Comments on the Notice of Inquiry are due Wednesday. (See FERC Outlines Gas Pipeline Rule Review.)
