FERC last week approved MISO’s proposal to shorten the window of time it allows generation owners to alter estimated capacity volumes for projects in the interconnection queue.
The commission’s decision clears MISO to require interconnection customers to finalize their requested network resource interconnection service (NRIS) megawatt values during “Decision Point II” — roughly 200 days into the queue (ER18-835). The revision became effective April 11.
FERC said requiring a final figure earlier in the process should help MISO achieve its goal of reducing unscheduled queue restudies in order to cut down on the number of months projects spend in the queue.
“MISO’s current proposal is a modification to further streamline its interconnection process and to prevent unscheduled, ad hoc restudies late in the interconnection process. We agree with MISO that unscheduled restudies will be less likely under the timeline established by MISO’s proposal,” FERC said.
The RTO’s previous process allowed interconnection customers to revise their requested level of NRIS up until after the final system impact study of the definitive planning phase of the queue.
MidAmerican Energy protested the change, saying that MISO and neighboring balancing authorities often do not complete affected-system studies on each other’s territories in time for Decision Point II, making an informed decision on NRIS levels impossible. But FERC ruled MidAmerican’s argument was underdeveloped and that “the benefits of reducing the potential for restudies and keeping the queue process on schedule outweigh MidAmerican’s concerns about potentially having less information at the earlier decision point.”
NEW YORK — Hundreds of investors, utility executives and others gathered last week for Bloomberg New Energy Finance’s Future of Energy Summit, where electric vehicles, energy storage and renewables dominated discussions. Here’s some highlights.
Robert Murray has been trying for more than a year to persuade President Trump and Energy Secretary Rick Perry to provide subsidies for the utilities that buy Murray Energy’s coal. (See Photos Show Murray’s Role in Perry Coal NOPR.)
Last week, he took his message — that the grid cannot be resilient without coal generation — to a skeptical audience at the BNEF conference.
“I’m probably the only coal guy in the room. I’m also an American,” he said, pausing to gather his composure after tearing up. “The recent polar vortex shows our grid is not as reliable as grid operators would like you to believe.”
Murray criticized FERC for rejecting Perry’s proposal to subsidize coal and nuclear plants with onsite fuel and said Perry should approve FirstEnergy’s request for an emergency declaration to protect coal plants. (See Perry Hints DOE Won’t Grant FES ‘Emergency’ Request.)
The declaration “has to be [made] or we’re going to have a disaster. … Will we have to have a system collapse before recognizing that something has to be done about the security, resiliency and reliability of the power grid?” he asked. “Barely one-half of [remaining coal] plants generate enough revenue to cover their expenses. There has to be a capacity payment there.”
Lynn Doan, head of power and renewables for Bloomberg News, asked Murray about reports by NERC and others that some coal plants were unable to run during recent cold spells because of frozen coal piles. “Did not happen ma’am,” he insisted.
“The poorest 25 million families in this country are putting out 31% of their income for energy — gasoline, oil and electricity,” he continued. “We have an energy poverty problem in this country. We don’t have a global warming problem.
“All of you are building your businesses around climate change. The best thing that could happen is overturning the [EPA’s CO2] endangerment finding — that artificial thing that has put political correctness ahead of getting the lowest-cost electricity for the people on fixed income, for that single mom, for that manufacturer.”
Power Markets Under Stress
Although most of the conference focused on advances in renewable technologies, there was some discussion of the impact of those resources on organized power markets.
“We know that clean, zero-marginal cost energy does fundamentally change the way the power markets work,” said Albert Cheung, BNEF’s head of global analysis. He cited BNEF modeling on the impact of adding 5 GW of solar in Texas. “It creates $300 million going toward solar. But you also destroy about $2 billion worth of revenue for other generators, whether it’s gas or coal or wind or nuclear. In California we already see this happening,” he said, with even solar “cannibalizing itself already.”
“Be wary of capacity mechanisms which bake in solutions of the past,” he added.
Former FERC Commissioner Nora Mead Brownell said she is confident organized competitive power markets will survive state and federal interventions to protect favored generation resources.
“I think it’s easy to sit in a vertically integrated market where you have elected regulators who pretty much approve what [utilities] wish and say this life is perfect. What we’ve seen in organized markets is a decrease in price, an increase in innovation and an increase in reliability and investment.”
FERC, she said, is acting properly in considering market redesigns to respond to decreased prices resulting from renewables and cheap shale gas. “They’re doing it in a methodical way based on a fact pattern, unlike kind of throwing subsidies at old solutions. They want to keep the market open for this continuing innovation that you will only see if you let the market drive decisions. You don’t see big huge mistakes in organized markets with big huge ratepayer-funded R&D projects. You don’t see that at all. There’s financial discipline, there’s transparency and there is encouragement of new solutions. It’s not happening fast enough … but I think it’s moving forward now. So, we need to step back and make economic decisions and not political decisions.”
Storage vs. Gas?
David Nason, CEO of GE Financial Services, was asked whether he sees storage as a threat to investments in gas-fired generation.
“I don’t know if storage is a complete competitor to gas yet,” he said. “It’s just one of the variables that we [consider in projecting] a long-term return for these investments. The difficulty with investing in gas without a structured market or without [power purchase agreements] is that these are 30-year, very capital-intensive investments. So, if I can’t get some level of confidence that I’m going to get an adequate return on my cost of capital, I’m just never going to put the money to work there.”
Reza Shaybani, co-founder and interim CEO of The EV Network, said the EV industry must not be paralyzed by concerns over which charging technologies and business models will survive. “This is going to evolve. This is going to change. What we see today is not necessarily going to be the future business model,” he said. “But it has to start from somewhere.”
Shaybani’s company, which is developing the charging infrastructure in the U.K., conducted a survey of EV buyers in the country and found that 90% were “middle-age men, well educated, very affluent and living in the Southeast and they have at least two or three other cars in their household. That’s … not going to take this revolution forward.”
The revolution will need cheaper vehicles and many more charging stations so that the drive from London to Manchester takes only three hours. “That should not take 18 hours if you are going to stop every 150 miles to charge,” he said.
Bryan Urban, executive vice president of Leclanche North America, said there is already a compelling business case for EVs and fast-charging infrastructure for mass transit and fleet vehicles. His company is conducting a pilot project in India for its plan to separate city buses from the batteries to make the capital expenditure model similar to that for diesel vehicles.
The company’s plan — which he dubbed, “taking the sun and putting it on the run” — replaces buses’ depleted batteries for charged ones three or four times daily, a swap which he says takes about three minutes each.
Mary Nichols, chair of the California Air Resources Board, said EVs need more marketing. “Even in California, where we pride ourselves that half of all EVs have been sold in the U.S., we … have done polls that show most people who are in the market for a new car aren’t even aware that there might be an electric car that could serve their needs,” she said. “So, we have a long way to go to really penetrate the thinking of customers.”
Nichols talked of Nissan’s hope to lease the batteries for its Leaf when it launched the first widely available all-electric car in Los Angeles. The plan was to include a mileage guarantee on the batteries, like the miles-per-gallon ratings for gasoline vehicles. “The only way they could do that at a level price was if they could negotiate with the electric utilities a product that would cut across state lines and local lines,” she said. “And after a period of time, they gave up on that idea. There was no practical way to do it.”
“And that’s in a relatively vertically integrated market, as most of the Western U.S. is,” added Colin McKerracher, the head of BNEF’s advanced transportation coverage. “It’s … even harder if you were to be in an unbundled market.”
Utilities are “unfortunately a very fragmented industry in the United States,” acknowledged Pedro Pizzaro, CEO of Edison International. “I think as an industry, we realize that and we’re trying to come to terms with that to help solve that issue. … We get your point, that from an automaker perspective or from a charger manufacturer perspective, they’re looking for as cohesive a national market as possible.”
LNG: No Glut Worries
Speakers at a panel on U.S. LNG exports expressed little concern over a potential glut in supply.
Meg Gentle, CEO of LNG exporter Tellurian, said she expects strong demand from China, which is converting coal furnaces to gas and adding natural gas-powered autos. Gas only represents 6% of total primary energy in the country, she said. Boosting that share to 10% would represent a nearly 70% increase in Chinese demand for the fuel.
She predicted Henry Hub benchmark prices will stay at $3/MMBtu or less for the foreseeable future, noting that it can now be produced for less than $1.
Greg Vesey, CEO of LNG Limited, which provides liquefaction for LNG export terminals, said he expects demand for gas to continue despite the growth of energy storage.
“Obviously the trend toward renewables and the need for storage with those is something to keep watching. … But in all cases, natural gas is going to provide that backup,” he said. “It’s been called the bridge fuel. I think we’re going to see that for a long time.”
Even if EVs supplant internal combustion vehicles, BP Chief Financial Officer Brian Gilvary said, oil will remain a “baseload” fuel.
“When I first joined the industry 32 years ago, people talked about peak oil supply. We now talk about peak oil demand,” he said. BP projects that peak to hit between 2035 and 2040.
“But we don’t think of it as a peak; we think of it as a plateau,” he added. Even under a scenario in which all internal combustion engines are banned by 2040, “we can see oil demand plateauing at round about 100 million barrels, which is what it is today.”
Corporate Purchasing of Renewables
Rob Threlkeld, global manager for renewable energy General Motors, said he’s been encouraged by the increasing number of utilities offering “green” tariffs to corporate buyers who want to purchase renewables. “I want price stability. I want to be able to understand what my costs are today and tomorrow. That allows me to be able to then [make] long-term commitments.”
“For a while, there was this huge tension between the renewable energy market and the regulated utilities. There was a significant pushback for years and years,” said Conor McKenna, managing director at investment bank CohnReznick Capital. “It was like when you were going into the regulated markets, you just had to put your mouthpiece in because it would be a battle. Now it feels like a lot of the guys that are coming to us [to deploy renewables] are regulated utilities [asking], ‘How can we incorporate a greater allocation of these resources into our portfolio?’”
MISO last week said it has concluded that a short-term capacity reserve product would be cost-effective and beneficial to reliability.
An evaluation paper released last month said the product would “strengthen MISO’s vision for reliable and economically efficient markets.”
MISO Market Design Advisor Bill Peters told an April 12 Market Subcommittee meeting that the RTO plans to design a market product that can provide capacity within 30 minutes on the recommendation of the Independent Market Monitor, who last year said a local reserve product could provide voltage support, local reliability and subregional capacity. (See MISO Board Hears State of the Market Recommendations.)
Last year the RTO incurred about $35 million in revenue sufficiency guarantee payments to cover load pocket needs and regional dispatch transfers over its contract path on SPP transmission from MISO Midwest to MISO South. The annual amount was “much more in some previous years,” MISO said.
Make whole payments MISO has incurred to manage the MISO-SPP contract path between MISO Midwest and MISO South | MISO
The RTO currently makes “inefficient, out-of-market commitments to address operational needs” in both load pockets and regional areas, Peters said.
Staff have said that a short-term capacity reserve would be especially helpful in South, which has less than 500 MW of offline capacity available within 30 minutes. West of the Atchafalaya Basin (WOTAB) has 100 MW of 30-minute reserves, while Amite South has none. (See MISO Researching 30-Minute Reserves, Multiday Commitments.)
Peters said MISO envisions the short-term capacity reserves as an ancillary service to be deployed in late 2019. The RTO will now move into a conceptual design phase.
Minnesota Public Utilities Commission staff member Hwikwon Ham asked how MISO arrived at the requirement that the reserve product must be delivered within 30 minutes rather than another length of time.
“Some of the needs, particularly the [regional dispatch transfer] constraint, are 30 minutes,” Peters replied.
Northern Indiana Public Service Co.’s Bill SeDoris asked if the cost of maintaining a reserve product would be shared footprint-wide.
Peters said MISO is considering employing a “nesting” approach for the product in which load needs are determined by specific demands on load pockets.
“I’m just concerned that the entire footprint could be responsible for what are very localized problems,” SeDoris said.
Peters said MISO must still iron out numerous details of a new reserve product, including determining how the service would interact with other existing ancillary services, creating scarcity pricing and demand curves for the new reserves, and identifying how commitment would be justified in settlements.
MISO Manages Chilly February
MISO reported a 76-GW average load during February, down from the average 83 GW in January as winter wound down across the footprint.
Average prices likewise decreased month over month from $41.75/MWh to $25.05/MWh in the day-ahead market and $39.68/MWh to $25.36/MWh in the real-time. Systemwide energy prices in February were “kept flat” with the help of natural gas prices below $3/MMBtu. Average Henry Hub gas prices were $2.64/MMBtu.
Past February Market Comparison | MISO
Load peaked for the month at 94.6 GW on Feb. 8, 7.5 GW above the previous February’s peak load of 87.1 GW. MISO said average monthly temperatures were lower than the prior two years but higher than in February 2015.
PJM’s Board of Managers announced in a letter to members last week that the Nominating Committee is recommending former InterGen CEO Neil H. Smith to replace Chairman Howard Schneider, who will retire from the board at the RTO’s Annual Meeting next month.
Smith
The committee also recommended re-electing current board members Neel Foster and Sarah Rogers. The Members Committee will vote on the candidates at the Annual Meeting.
Smith was selected following a national search, assisted by the Heidrick & Struggles search firm, that included candidates suggested by current board members. He retired from InterGen in 2016 after 25 years with the company, working his way up from development director.
InterGen operates 11 power plants with a generation capacity of 7,686 MW, three compression facilities and a 40-mile gas pipeline. The facilities are located in the U.K., Netherlands, Mexico and Australia. The company is jointly owned by the Ontario Teachers’ Pension Plan and China Huaneng Group/Guangdong Yudean Group.
Smith also served as a non-executive director and board member of The Wood Group, a worldwide service provider for the oil-and-gas and power generation industries. He was on the board for nine years, between 2004 and 2013, according to his LinkedIn profile.
Stakeholders learned Wednesday that MISO will delay for another year a plan to account for previously un-forecasted planned outages at times of peak demand after getting mixed feedback from market participants.
Speaking at an April 11 Resource Adequacy Subcommittee meeting, MISO Resource Adequacy Coordinator Ryan Westphal said the RTO will wait until the 2020/21 planning year to implement a new, unspecified calculation that accounts for planned outages during peak demand, which could increase the RTO’s planning reserve margin requirement.
MISO had proposed to factor the effects of planned and maintenance outages on peak in its loss-of-load expectation (LOLE) study by the 2019/20 planning year. (See MISO RASC Zeroes in on Priorities.)
Westphal said some stakeholders asked the RTO investigate further before making any changes to the LOLE study. Others urged it to define “safe” periods during the summer months to take planned outages.
Director of Resource Adequacy Coordination Laura Rauch said MISO would delay accounting for planned outages on peak until it develops solutions based on a more comprehensive conversation about the RTO’s shifting resource availability. (See MISO Looks to Address Changing Resource Availability.)
Some stakeholders expressed frustration that the RTO first presented the issue as requiring expeditious treatment, then moved it into a discussion about resource availability and needs, only to again this month single it out to proceed separately. (See MISO to Fold Outage Forecasting into Larger Resource Effort.)
Reprieve for Out-year Import and Export Limit Estimates
MISO is taking a cue from stakeholders and switching gears on a previous proposal to discontinue its practice of forecasting long-term capacity import and export limits, instead proposing to modify the process that produces the forecast.
MISO’s Matt Sutton said the RTO expects by early 2019 to revise its process for predicting capacity transmission limits for its 10 local resource zones. It had proposed in February to altogether scrap out-year import and export limits, saying results were too unreliable and volatile, but stakeholders countered that the limits provided useful information. (See “Scrapping Out-Year Import and Export Limit Estimates?” MISO Resource Adequacy Subcommittee Briefs: Feb. 7, 2018.)
While the RTO still plans to compile the long-term limit estimates, it will use more zone-specific information, including data from past Planning Resource Auctions and the Organization of MISO States-MISO annual resource adequacy survey.
Sutton said the RTO would not commit to annual restudies for capacity zones that don’t experience notable changes.
“If a zone could potentially bind, a study isn’t necessary every year unless a significant supply or transmission change occurs,” he said. “The number of studies is being reduced significantly. … We’ll have fewer zones to review.”
The selective study process will allow MISO to focus on zones that could bind on their import and export limits or carry capacity surpluses beyond their export capability, Sutton said.
The more thorough process to estimate out-year limits should spark discussions around new transmission and generation projects and the impact of external system changes on capacity zones, he said, not just the usual conversations about transfer limits, constraints and redispatch options.
MISO will pass its recommendations for improvements to its stakeholder-led Loss of Load Expectation Working Group, which will produce a new prediction methodology for stakeholder review as early as September, Sutton said. He asked stakeholders to submit written comments on the RTO’s plan by April 27.
Different Method for Economic Uncertainties in LOLE Study?
MISO is exploring how to improve its modeling of economic load uncertainties in the LOLE study.
For the 2018/19 planning year, the RTO relied on a GDP growth comparison to account for the uncertainties, which increased the annual planning reserve margin by 0.2 percentage points year-over-year.
In June, MISO will have a 17.1% planning reserve margin, which represents the extra generation the RTO should have on hand to meet a probability of shedding load no more than one day in 10 years. MISO maintained a 15.8% planning reserve margin in the 2017/18 planning year.
MISO staff have attributed the increase to an upswing in generation outages and a change in the dispatch model for demand resources, but it was partially offset by reduction in anticipated load growth. The RTO last year also added the new modeling step to capture economic load uncertainty that increases risks associated with high peak loads, which also boosted the reserve margin. (See MISO Planning Reserve Margin Climbs to 17% for 2018/19.)
“We’re reviewing our methodology and investigating other approaches for the 2020/21 planning year model,” MISO Resource Adequacy Senior Engineer William Buchanan said.
In future years, the RTO may model economic uncertainty using a calculation based on comparisons between forecasted and actual demand in past years, Buchanan said.
New Jersey lawmakers on Thursday passed a pair of bills that could significantly shape the state’s generation portfolio over the next decade.
One bill would provide two Public Service Enterprise Group nuclear power plants with subsidies costing ratepayers about $300 million per year. The other would require the state’s power sellers to get half their electricity from renewable sources by 2030.
New Jersey’s State Capitol Building
By a 29-7 vote, the state Senate passed S2313, which would create a zero-emission certificate (ZEC) subsidy for nuclear plant operators that can show the New Jersey Board of Public Utilities their plants need financial support to remain operating. The bill passed the General Assembly on a vote of 60-10.
The bill now goes to Gov. Philip Murphy, who will have 45 days to decide whether to sign the bill, veto it or allow it to become law without his signature. He could also conditionally veto the bill and send it back to the Legislature with proposed changes.
ClearView Energy Partners gave Murphy a 65% chance of signing the bill but said he may conditionally veto it, in which case the Legislature could agree to his proposed changes with a simple majority vote. If he vetoes it, the Legislature would need a two-thirds majority vote for the bill to become law.
If Murphy does sign the bill, ClearView says it expects opponents will file a lawsuit in the U.S. District Court for New Jersey challenging the ZEC program on grounds similar to those of lawsuits challenging similar programs in New York and Illinois. ClearView also said it thinks New Jersey lawmakers structured their state’s ZEC program with such lawsuits in mind.
The nuclear subsidy bill drew a mixed reaction. The Natural Resources Defense Council has said it will not oppose the bill, while Jeff Tittel, director of the New Jersey Sierra Club, said it would have “a chilling effect on spending more for renewable energy, because to build out renewable will cost much more.”
The Electric Power Supply Association and New Jersey Petroleum Council also panned the nuclear bill, while PSEG spokesman Michael Jennings called it “a sensible solution that protects the viability of nuclear energy and its benefits for New Jersey, while at the same time ensuring consumers are protected, as well.”
The other bill (A3723) would require electric power suppliers to procure 35% of their power from renewable resources by 2025 and 50% by 2030.
KANSAS CITY, Mo. — While Midwestern grid planners aren’t certain about the future of energy infrastructure, they do agree that planning must yield to a convergence of trends, including low-cost renewables, energy storage, escalating cyberattacks, flat demand and legacy generation verging on the antique.
Those trends will dictate the direction of new buildouts, according to industry experts speaking Tuesday on a infrastructure panel as part of the Midwest Energy Policy Series hosted by the Missouri Energy Initiative.
Missouri Public Service Commission Chairman Daniel Hall said new infrastructure placement must take into account a blend of national trends, including declining wind and solar costs, the natural gas fracking boom, aging power plants and transmission lines, and declining demand for electricity due to household energy efficiency and the country’s downsized manufacturing sector.
“Most distribution lines were constructed in the 1950s and 1960s, and they were expected to last 50 years,” Hall said.
Many utilities are planning utility-scale renewable projects, he said, pointing out that Ameren has requested a certificate of convenience and necessity for a 700-MW wind farm by 2020.
“If completed, that would account for almost 10% of Ameren’s power generation,” Hall said.
While renewables could fill in for aging baseload generation, RTO planners questioned whether the demand-light Midwest needs an abundance of new generation development. Other panelists agreed that years of 3% annual load growth are a thing of the past.
SPP Manager of Transmission Services Charles Cates said SPP’s queue holds 70 GW of generation, which, if built, would exceed the RTO’s current peak loads.
David Van Beek, MISO external affairs manager, said his RTO is still experiencing a “drastic generation shift” toward renewables even with the uncertainty surrounding the Clean Power Plan. He noted that solar projects account for one-third of MISO’s record-setting 90-GW-plus generation interconnection queue.
The Promise of Storage
Even with the addition of all that proposed generation, panelists said storage projects could facilitate local consumption of the output, precluding the need for the new transmission lines planned for in the past.
Jay Lohrbach, manager of generation projects for City Utilities of Springfield, Mo., said a joint 1-MW battery storage project between his utility and NorthStar Battery at the Cox substation will likely defer the need to build transmission infrastructure in that area.
Lohrbach said that by the end of 2019, the utility will be supplying the city with 40% renewable power.
“This is Springfield, Mo., not California,” Lohrbach reminded the audience. “That’s amazing.”
Lohrbach said utilities are in the unenviable position of balancing when to retire uneconomic and slow baseload coal and nuclear units with a duty to provide capacity. “The bar has been placed pretty high in how efficient we have to be,” he said. “It’s a tough situation economically for utilities.”
He said NorthStar’s batteries can be designed exclusively to manage small spikes of demand, catering to a country with otherwise flatlining loads.
“Battery storage can scale down to the size of your house pretty readily,” Lohrbach said. He added that storage batteries have no fixed costs, only upfront construction costs and fairly well-defined variable costs.
“It’s pretty easy to decide when to discharge the battery,” Lohrbach said. “And if I don’t deploy it, it can just sit there and not cost me anything. It’s a completely different economic model than anything we’ve seen before, and we need to wrap our heads around it.”
Lohrbach said RTO transmission planners aren’t yet planning for the full impact of storage developments.
In response to an audience member’s question about the prospect of planning transmission explicitly to accommodate energy storage in the wake of FERC’s Order 841, Van Beek said the order was too new to shape transmission planning. Both this year and last, MISO incorporated a fourth future scenario into its transmission planning process as distributed and emerging technologies become more widely used. (See MISO to Recycle Tx Planning Scenarios for 2019.)
Chris Neaville, asset development director of St. Louis-based mining company Doe Run, said large industrial consumers also want storage projects.
“We think the future for us is really developing our own microgrid,” Neaville said.
Doe Run envisions a microgrid that could shave its peak loads through 21 to 50 MW of behind-the-meter, onsite solar power and up to 16 MW of battery storage, which could also serve as back-up generation for its mines’ critical systems.
“We could become interruptible load,” Neaville added.
He said electricity is Doe Run’s single biggest operating cost at about $23 million annually, and that 1960s-era transmission lines deliver power to its remotely situated mines.
Neaville said he’s worried that Ameren is currently being granted about 5% rate increases about every 18 months, with each hike subtracting about $2 million to $3 million from the company’s bottom line.
“Our concern for the future is that if it continues at that rate, it’s not sustainable,” Neaville said. “There’s a break point where we have to do something differently. We can’t keep increasing these rates.”
Doe Run would prefer not to build its own generation, Neaville said, so the company hopes to partner with a utility on a microgrid project.
Grain Belt Express
Discussion veered to Clean Line Energy Partners’ embattled, high-voltage Grain Belt Express transmission project, whose fate is now in the hands of the Missouri Supreme Court. The stalled $2.3 billion, 780-mile line was designed to transmit Kansas wind generation to the western border of Indiana after crossing Missouri and Illinois.
Hall said that although the Missouri PSC found the project worthy, its hands were tied in denying the application because the Caldwell County Commission refused consent for the transmission line to cross public roads.
He said the commission was bound to follow the Western District Court of Appeals’ decision that the certificate could not be lawfully granted without county approval.
“That is essentially a road map for county commissioners to focus on their voters. … It doesn’t make sense from my perspective that you’ve got county commissioners that can decide the fate of interstate transmission lines,” Hall said.
Clean Line’s situation highlights the need to either change state law or have the federal government supersede state jurisdiction, he said.
“Hopefully, the [Missouri] Supreme Court will get it right.”
Hall also hopes the court’s opinion “would not say that the PSC erred” in denying the certificate, as the commission was legally bound to issuing a denial.
Van Beek and Cates discussed whether their RTOs would approve a first-ever interregional project along their seam, especially near Kansas and Missouri. Both agreed their two-year joint modeling process can sometimes delay project approval.
“The time frame of modeling is quite extensive,” said Cates, adding that while the RTOs’ can usually agree about what areas need a transmission project, they can get stuck on how to divide costs. MISO and SPP staff have recently suggested abandoning their joint model in favor of more closely aligned regional models. (See MISO, SPP Look to Ease Interregional Project Criteria.) The two RTOs plan to wait a year before embarking on another joint study in hopes of improving their process to gain approval for an interregional transmission project.
ITC Holdings’ Chris Winland said his company wants to be on the “cutting edge” of planning transmission infrastructure for future wind developments in Kansas and Oklahoma. He said those areas are home to the “best wind in the country” and predicted more development.
Whatever infrastructure is built, it needs to withstand increasingly sophisticated cyberattacks, said Ameren Chief Information Officer Mary Heger.
Ameren uses a combination of systems monitoring, virus scanning, network segmentation, quarantine programs for suspect email and “whitelisting” — which authorizes which applications are allowed to run, thereby excluding all other programs, she said.
“The program we put in place is designed to protect us against a broad scope of actors.”
Heger said Ameren also has an in-house training program called Cybersafe, where the utility will test employees by sending simulated phishing emails — the kind of which that set in motion the 2015 cybersecurity attack on Ukraine’s grid.
“People really are one of the weakest links,” Heger said.
“As long as people click on links … that will be a very popular way to get a foot in the door,” said Galen Rasche, Electric Power Research Institute senior program manager.
Rasche said a more mobile utility workforce, dynamic supply and demand balancing, increasing automation of operations, customer self-generation and home energy management programs all create more opportunities for cyberattacks.
He said an integrated — or “multiparty” — grid, in which generation and storage assets are not necessarily owned and operated by utilities but are aggregated by a third party, presents a more complex security challenge. He predicted that some aggregation vendors will go out of business within five years and asked what will happen to their data after they fold.
“Cybersecurity now can’t be the sole responsibility of the utility,” he said. “We need to make sure we’re having this conversation with everyone in the room.”
KANSAS CITY, Mo. — A small group of SPP members have asked the Board of Directors to reconsider its decision to move forward with the Mountain West Transmission Group’s integration until “there is more consensus within the SPP membership as to how to proceed.”
In a letter filed for inclusion in the background materials for the board’s April 24 quarterly meeting, the group called for reopening negotiations with Mountain West to create a path “towards a single RTO with a single set of rules for all participants.”
It reflects growing stakeholder concerns over the board’s March 13 approval of policy recommendations intended to govern the terms of Mountain West’s membership in SPP. The board approved 18 policy statements and directed staff and stakeholders to begin revising SPP’s Tariff, bylaws, membership agreement and other governing documents. (See SPP Begins Work of Integrating Mountain West.)
The letter, dated April 6, was signed by load-serving entities Kansas City Power & Light, Municipal Energy Agency of Nebraska, Nebraska Public Power District, Oklahoma Gas & Electric and Western Farmers Electric Cooperative.
No Prior Notice
It charges that SPP’s full membership did not see the policy recommendations — such as new Mountain West-only stakeholder systems to manage regional cost allocation and zonal rate design — prior to board approval.
Based on the analyses presented so far, it is impossible for the board and stakeholders “to evaluate the potential impacts associated with the East-West bifurcation of SPP’s governance structure,” the companies said.
“The process has afforded neither the ability of the existing members to be well-informed nor the opportunity for the policy recommendations to be supported by the collective membership,” the five utilities wrote. “We want to see one set of rules applied to all entities — East and West — unless there is a physical or legal limitation (e.g., federal exemption) that must be honored. Any expansion of SPP to include new transmission-owning members must be designed so that both SPP’s existing members (and thus their customers) and the new entrant receive benefits. And if existing SPP customers are assigned additional costs, there should be corresponding benefits.”
MOPC Discussion
Separately, OG&E’s Greg McAuley brought the issue to the fore as SPP’s Markets and Operations Policy Committee meeting ended Wednesday. He asked that the minutes note as “we participate in the working groups [on Mountain West’s integration], it should not be reflected as overall acceptance of the proposal.”
“We’re still opposed to the Mountain West integration as proposed,” McAuley said. “Some of the revision requests are very complicated. They’re very difficult and complex, and they need to be reviewed appropriately. We don’t want our participation in that work to be viewed as demonstrating approval of the overall proposal or, conversely, intentionally slowing the process of getting the revision requests approved.”
Saying he did not want to leave McAuley “hanging out there by himself,” American Electric Power’s Richard Ross said his company also has “significant reservations about the structure of the proposal.”
“We don’t feel like it’s as good as it could have been done or should have been done. It brings risk to the existing membership,” he said. “But we will work through the stakeholder process. When given lemons, we’ll try make as good a batch of lemonade for the RTO as possible.”
One of AEP’s concerns is the cost of potential upgrades to the four DC ties connecting SPP and the Mountain West entities. The upgrades have been proposed as an approximate 70-30 split on a load-ratio share between East and West. SPP and Mountain West say that incorporating the ties into the RTO’s market will lead to lower production costs and savings from sharing operating reserves.
Yet to be determined is what happens should any Mountain West entities leave the expanded RTO after the DC ties are upgraded.
“I don’t want be in a situation where new members join and then they turn around and leave, and I have to continue paying for their DC-tie cost under the exiting provisions of the bylaws,” Ross said.
SPP: Not Surprised
SPP said the pushback was not unexpected, noting that its stakeholder process is built around collaboration, consensus-building, candor and open dialogue.
“In short, concerns expressed by our members to our board is a natural part of our established process, and we welcome dialogue with them,” the RTO said in a statement. “Now that we’re transitioning to a more public, inclusive phase of the integration process, we fully expect and welcome questions from our members regarding implementation of the board-approved policies.”
Xcel Energy spokesman Mark Stutz, speaking for the Mountain West entities, pointed out the SPP board’s March approval was of policy terms agreed to by the group’s utilities.
“The Mountain West members are now engaged in the public stakeholder process to develop the implementing language in the SPP Tariff and related contracts. Although final decisions have not been made, we plan to continue work in the established SPP public stakeholder process to complete these efforts,” Stutz said.
$500 Million not Sufficient
There was little other public support for McAuley and Ross at the MOPC meeting, but away from the microphones, stakeholders said the $500 million in total net benefits promised by SPP to existing members over the first 10 years of Mountain West’s membership is not sufficient.
They also expressed concerns about the time needed to vet Tariff and governance revisions and the exit provisions for Mountain West entities. SPP has said it hopes to bring a package of revision requests to the board in July for its approval.
Sunflower Electric Power Cooperative’s Tom Hestermann asked SPP COO Carl Monroe what was the sense of urgency driving the stakeholder process. Hestermann noted that the Regional Tariff Working Group has scheduled 17 meetings (five of which are multiday affairs) before the July 31 board meeting to manage the 12 revision requests before it.
“It’s always an issue of how do you ensure there’s due diligence,” Monroe said. “When setting a schedule, how do you ensure the parties have adequate time and the urgency to get something done and also have the ability to push back when key issues arise that need to be resolved. That’s the goal that’s been set.”
The Market Working Group faces a similar work load. It has scheduled seven meetings before the board meeting to handle the 20 Tariff changes it currently faces.
Monroe also told stakeholders that SPP and Mountain West are still negotiating a transition service agreement, but that staff have “every intention” of providing “all the protections that have been requested” should Mountain West walk away from the deal.
He said SPP has exhausted the funds allocated by the Finance Committee for integration work, which has led to a temporary halt in the effort.
“We’re not doing anything for integration until they sign the agreement,” Monroe said. “We’re pushing to get it done.”
SPP projects it will take about two years to fully integrate the Mountain West entities as members, but it plans to begin reliability coordination services in late 2019.
MISO’s sixth annual Planning Resource Auction cleared at $10/MW-day in all but one zone, a nearly seven-fold jump over last year’s single clearing price of $1.50/MW-day.
The RTO reported clearing 135 GW of capacity on Thursday, with nine of its 10 local resource zones clearing at $10/MW-day. The lone outlier was Zone 1 — covering parts of Wisconsin, Minnesota and the Dakotas — which cleared at $1/MW-day. MISO’s Independent Market Monitor has reviewed and certified the results.
“This year’s auction results reflect an adequate availability of resources for the planning window and the grid’s capability to effectively and efficiently transfer resources among local resource zones,” MISO Executive Director of Market Operations Shawn McFarlane said in a press release.
| MISO
MISO said this year’s price increase was driven by “an increase in the planning reserve margin requirement, a decrease in supply and changes in market participant offer behavior.” Come June, the RTO will have a 17.1% planning reserve margin, based on limiting the likelihood of shedding load to no more than one day in 10 years.
MISO Manager of Resource Adequacy John Harmon on Friday said zero-price offers declined compared to last year’s auction.
“It does seem that participants had a greater appetite for risk,” Harmon said.
MISO maintained a 15.8% planning reserve margin for the 2017/18 planning year, when all zones cleared at $1.50/MW-day. Last spring, CEO John Bear said that the 2017/18 price resulted from high supply and low demand. (See All Zones at $1.50/MW-day in 5th MISO Capacity Auction.)
The last two auctions were a departure from three years ago, when almost all of MISO Midwest cleared at $72/MW-day for 2016/17, and four years ago, when Illinois’ Zone 4 cleared at $150/MW-day for 2015/16.
The RTO also said auction results were in line with the results of last year’s Organization of MISO States-MISO resource adequacy survey, which predicted sufficient capacity to meet near-term planning requirements through 2022. (See Capacity Survey Shows MISO in the Black.) McFarlane said the results demonstrate the “grid’s capability to transport those megawatts across the zones.”
MISO said this year’s auction continued the increase in non-traditional resources. About 1,600 MW of additional demand response, energy efficiency and behind-the-meter generation cleared, bringing the total to 11,000 MW, 8% of all resources. McFarlane said the increasing use of load-modifying resources to meet capacity needs underscores the need for MISO to continue its discussions on resource availability and need. (See MISO Looks to Address Changing Resource Availability.) The RTO said it will “continue to focus on the importance of long-term resource adequacy as the industry and generating fleet continues to evolve. MISO will also continue to support state processes around resource adequacy planning.”
During a Market Subcommittee meeting Thursday ahead of the auction results, Independent Market Monitor David Patton said he expected low auction capacity prices to continue “indefinitely.” In late February, FERC rejected the Monitor’s latest request to order MISO to apply a sloped demand curve, which he said would result in more efficient pricing. The commission said the RTO’s vertical curve was just and reasonable, noting that 90% of load is served by vertically integrated utilities. FERC also said pricing takes a backseat to the auction’s main objective to maintain reliability. (See FERC Vacates, Upholds MISO Resource Adequacy Rules.)
Zone 1
Harmon said 142 GW was offered in this year’s auction, 4 GW above the reserve margin requirement even when factoring in capacity stranded by transmission constraints, which would’ve accounted for another 2 GW in excess capacity.
“Zone 1 did bind on its capacity export limit this year. This binding did occur on the same transmission facility as last year,” Harmon said during an April 13 conference call with stakeholders.
WPPI Energy’s Steve Leovy expressed concerns over improper binding and price separation in Zone 1. In stakeholder meetings, Leovy has repeatedly called attention to MISO’s capacity export limit, which does not distinguish imports sourced outside the RTO from those sourced inside, making available transmission capacity appear scarcer than it really is, according to Leovy.
“I wouldn’t expect that line to bind. I would expect that line to have a lot of slack,” Leovy said. He said MISO must change the calculation behind its capacity import limits.
MISO staff on the conference call promised more information on capacity export limits and the RTO’s simultaneous feasibility test at the May 9 Resource Adequacy Subcommittee meeting.
Consumers Energy’s Jeff Beattie said it would be helpful for MISO develop a presentation showing how transmission capacity might increase around Zone 1 when the RTO’s multi-value transmission projects come online.
Winter is coming — or at least it will be coming again — and the PJM Board of Managers wants at least some energy price formation restructuring by then.
In a letter to stakeholders released on Thursday, the board acknowledged the heavy lift that implementing staff’s original price formation white paper might entail, but it said there is consensus between PJM staff and the Independent Market Monitor on changes to improve reserve pricing. The letter directs staff to identify changes that can be implemented for next winter and “respectfully requests stakeholders to deliberate timely” so that the revisions can be completed by the third quarter, in time for FERC approval for winter 2018/19. (See “Additional Reserves Needed?” PJM MRC/MC Briefs: March 22, 2018.)
The graphic explains the issue PJM hopes to resolve with its energy price-formation restructuring. | PJM
“We have been informed that PJM staff and the IMM agree that PJM should implement a 30-minute reserve product in real time to comport with the current day-ahead scheduling reserve product, address issues with the current implementation of the synchronized reserve market, implement a more dynamic establishment of reserve requirements so as to better capture operator actions taken to maintain reliability, and enhance the operating reserve demand curves used to price reserves during reserve shortage conditions,” the board wrote.
“Given the level of agreement between the IMM and PJM staff, the board believes that this more targeted issue may present an excellent opportunity for the stakeholder community to come together and demonstrate that the PJM stakeholder process can deliver thoughtful and timely consensus action.”
Dual Issues
The board reiterated its position that energy and reserve market pricing issues must be examined because “there are times when operators commit resources to ensure reliability but these commitments are not reflected through market clearing prices such that those prices can be suppressed and result in undesirable outcomes.”
The energy market issue has been the focus of the Energy Price Formation Senior Task Force, which is considering the revisions proposed in PJM’s white paper as part of a wider stakeholder analysis. (See “PJM Pushes Price Formation Plan,” FERC, RTOs: Grid Performed Better in Jan. Cold Snap vs. 2014.)
“The board is well aware of questions stakeholders have raised regarding this proposal. The board has listened to stakeholders and appreciates that changes to the LMP calculation require careful consideration,” the board wrote.
In recent PJM stakeholder meetings, the reserve market issues have become the central focus.
“We are hopeful that on an issue such as this one where there appears to be ample, empirical evidence that a market design change is needed, where there is significant alignment between PJM staff and the IMM concerning the need for change, and where there is clear direction as to the nature of the improvement required, such timely consensus can be achieved,” the board wrote.
It asked that the remaining issues be resolved by the first quarter of 2019 so they can be approved and implemented by the summer of 2019.
“Such timely action, if it can be achieved, will reinforce confidence in the ability of the stakeholder process to deliver timely consensus solutions,” the board wrote.
