ST. PAUL, Minn. — MISO released a five-year operations business plan last week that calls for new products, technology upgrades and a better-trained workforce.
The Board of Directors reviewed the plan at its Markets Committee meeting last week.
The plan includes “investment in forward-looking, strategic products to respond to tightening reserve margins, increasing reliance on renewables and need for increased gas-electric coordination.”
“Looking forward, the confluence of technology, market, policy, regulatory and other external drivers will accelerate the pace of change,” MISO said. “To continue to deliver and to extend [MISO’s] value proposition, we must invest in our markets, organization and technology.”
It also calls for developing existing staff and “modifying hiring criteria” to improve the organization’s strategic and commercial skills while also streamlining current processes and incorporating more automation.
MISO said the plan would cost $13 million and yield $30 million in benefits next year. The RTO expects the entire plan to cost $51 million in operating and capital expenses and deliver annual benefits of more than $100 million through 2021.
“I’m not accustomed to seeing [returns on investment] in the thousands percent, so … it makes me somewhat skeptical. We’re going to need some more information,” Director Thomas Rainwater said.
Jeff Bladen, MISO’s executive director of market design, said the annual benefits assume that the RTO can allocate the research costs and that the technology is in place in time. He said MISO would make more presentations on the plan.
“This assumes that we have the people and technology in place that allow us more flexibility,” Bladen said.
The plan includes MISO’s introduction of a separate forward capacity auction for competitive areas next year, followed by seasonal and locational capacity market changes in 2018.
The plan also sets the following goals for 2018-21:
Replacing the 2004 “freeze date” reference point in MISO’s flowgate allocation process by 2018;
Allocating feasible auction revenue rights and nominating infeasible long-term transmission rights in 2019;
A multiday financial commitments market, a multiyear financial transmission rights auction and a short-term capacity reserve market by 2020; and
A special pricing structure for voltage and local reliability (VLR) commitments and a virtual spread market product by 2021.
Among the benefits cited by MISO are a reduced likelihood of outages; more capacity availability; improved reliability; improved congestion hedging; reduced production costs; and more efficient real-time interchange and better price convergence with its neighbors.
Independent Market Monitor David Patton said it would be helpful if MISO designed more flexible software so entirely new code isn’t needed every time the RTO makes a market change.
SARATOGA SPRINGS, N.Y. — The last panel of the Independent Power Producers of New York’s fall conference last week featured an environmental activist and representatives of the energy storage, wind and solar industries.
And then there was Karen Moreau, charged with making the case for the long-term future of natural gas. She decided to try humor.
“If natural gas was on an online dating site … the profile would be ‘clean, reliable, affordable and flexible,’” said Moreau, executive director for the American Petroleum Institute in New York. “I don’t know how many people would take a look, at least not at first. They’d probably go to some of the other, more attractive, sexy forms of energy like wind and solar.
“But then again, online dating does involve a certain element of hope and fantasy, and so let’s talk about statistics,” she continued.
And the statistics, she said, indicate gas will be needed for the foreseeable future to help balance intermittent renewables.
Moreau quoted a 2016 National Bureau of Economic Research study that concluded a 1% increase in fast-reacting fossil fuel generating capacity was needed to support a 0.88% increase in renewable capacity. She also cited NYISO’scontroversial prediction that full implementation of the state Clean Energy Standard will require increasing the installed reserve margin to at least 40% from the current 17.5%.
And renewables are not well suited to provide ancillary services such as voltage support, regulation and frequency control, operating reserves and black start, currently provided by gas-fired generation, she said.
Anne Reynolds, executive director of the Alliance for Clean Energy New York, agreed that gas will have a role. Jackson Morris, Eastern energy director for the Natural Resources Defense Council, said that role could persist even through midcentury under the state’s plan to reduce greenhouse gas emissions by 80% by 2050.
Stranded Assets?
But Morris said policymakers must beware of overinvesting in gas infrastructure that could become stranded assets.
“What’s going to happen is if we’re not careful — if we’re building out 40- to 50-year infrastructure, whether its pipelines or combined cycle plants — we could easily be either running into a brick wall and not meeting the necessary climate trajectory we need to be on, or alternatively … you could end up with a ton of sunk costs.
“If you don’t have that time horizon right, if you don’t build out a regulatory framework that has the right foresight, you could literally be on a path that looks really promising and run square into a giant brick wall when you get to 2030.”
Need for Storage
Moreau acknowledged that gas’s future is tied to the cost curve for energy storage. If storage gets cheap enough, it could compete particularly with simple cycle gas peaking plants, some say.
New York’s climate goals also will require as much as 4 GW of energy storage by 2030, said Denise Sheehan, senior advisor to the New York Battery and Energy Storage Technology Consortium. The group is proposing a “no regrets” target of 1 GW of multihour storage by 2022 and 2 GW by 2025.
“These projects are happening. They’re real,” she said.
Offshore Wind Essential to 2030 Target
While conceding a continuing need for gas, Morris and Reynolds were far more bullish on the role offshore wind will play in New York’s future.
“You cannot get to 50% [renewables] by 2030 without offshore wind. Period,” Morris said. “If we lay the groundwork right now [for] 2030, could we have potentially thousands of megawatts of over 50%-capacity-factor, carbon-free resources located close to the highest load pockets in the state? We absolutely could. There’s no question.”
Levelized costs for offshore wind in Europe have dropped 50% in the last seven years, with recent projects coming in below 8.5 cents/kWh, Morris said. A June 2016 paper by the National Renewable Energy Laboratory and Lawrence Berkeley National Laboratory forecast that offshore wind costs will drop as much as 30% more by 2030.
But that assumes a pipeline of projects, according to Reynolds, who said that “critical mass” could be reached by developments in New York, Massachusetts, New Jersey and Maryland.
Offshore wind, common in Europe, has been slow to gain a foothold in the U.S. The Cape Wind project in Massachusetts, which advertised itself as the first offshore project in the U.S., has stalled following years of litigation, local opposition and legislative battles.
But the potential — particularly in the shallow waters of the Atlantic coast — is compelling and advances have begun occurring at a faster pace.
The U.S. Bureau of Ocean Energy Management has awarded 11 commercial offshore wind leases, including two sites each off New Jersey, Maryland and Massachusetts, one off Virginia and two off the Rhode Island-Massachusetts border.
In June, BOEM identified New York’s first “wind energy area,” 12 miles off Long Island. BOEM is expected to auction off development rights in December.
Construction of the nation’s first offshore commercial wind farm, off Block Island, R.I., was completed in August and is expected to begin operations by the end of 2016.
Earlier this month, the U.S. departments of Energy and the Interior released their second National Offshore Wind Strategy.
On Sept. 12, Reynolds’ group, which represents wind and solar developers, announced a spinoff organization, the New York Offshore Wind Alliance.
And on Thursday, New York Gov. Andrew Cuomo and the New York State Energy Research and Development Authority released an offshore wind blueprint outlining the state’s plan to identify the most promising wind development sites within a 16,740-square-mile area.
Meanwhile, the Long Island Power Authority could vote as soon as Wednesday to authorize a 90-MW offshore project 30 miles northeast of Montauk.
Morris said he was undaunted by the fate of Cape Wind. “You had technology in a different place. You had public policy in a different place,” he said. “We’ve learned a lot from Cape Wind.”
VALLEY FORGE, Pa. — PJM will add a new section to its Operating Agreement specifying that substation equipment issues that can be solved by transmission owner upgrades are excluded from Order 1000 competitive windows, PJM’s Mark Sims told the Planning Committee last week.
The usual solution to an overload of substation equipment is to replace it with higher rated equipment or add additional equipment to achieve required performance, Sims said during a presentation that identified the types of equipment typically involved.
Sims said PJM will open a competitive window if an analysis shows that a greenfield project is possible, but the default assumption will be that substation equipment violations be excluded from competition. PJM will seek stakeholders’ endorsement of the OA language next month.
A study of the installed reserve margin found that the recommended percentage has risen 0.1% to 16.6% since last year. The analysis will establish the initial IRM for the 2020/2021 Base Residual Auction in May and reset the IRMs for delivery years 2017/2018 through 2019/2020.
“The IRM has been quite stable,” PJM’s Tom Falin said.
The analysis found that the August-to-July peak ratio, which measures the August peak as a percentage of the annual peak in July, rose from 95.5% in 2015 to 96.9% this year. The flatter load increased the IRM, but the capacity benefit of ties partially mitigated the increase.
The loss-of-load-expectation risk also was more spread out this summer compared to last year, another factor that increases the IRM. In 2015, 80% of the LOLE risk occurred in the peak week. This year, it dropped to 68% in that week and more shifted to week 12 in early August, where it nearly doubled from 11% to 21%.
RTEP Case Build Scheduled
PJM is requesting feedback by Sept. 23 on draft summer, winter and light load cases for the Regional Transmission Expansion Plan. Updated load profiles and contingencies are scheduled to be released by the end of October, with feedback requested by Nov. 17. PJM is asking that TO-submitted cases provide bus numbers at the primary buses so it can better line up short-circuit and power-flow cases.
“These activities are really central to our ability to … get the whole case-development process moving earlier and have consistency from year to year,” Vice President of Planning Steve Herling said. “This hopefully will put us in a much better position to manage the RTEP cycle [and] all the Order 1000 work, so this is really a big effort for us.”
Input Sought for TEAC Redesign
PJM is seeking stakeholder feedback as it considers a redesign of the Transmission Expansion Advisory Committee. PJM’s Fran Barrett said he envisions a more dynamic system that incorporates video streaming, blogging and social media.
He said his team has younger staff that are familiar with those media. “I have challenged the team … to be industry leading. … This by its very nature introduces generational differences,” he said. “Our processes were built way before Order 1000. Just because this is the way we’ve done things, doesn’t mean it should continue that way.”
SARATOGA SPRINGS, N.Y. — Stuart Nachmias, president of New York Transco, said that New York’s plan to build as much as 1,000 miles of new transmission to accommodate renewables and meet its emission targets will be “a marathon, not a sprint.”
NY Transco, a joint venture of Consolidated Edison, Avangrid, National Grid and Central Hudson Gas & Electric, was formed to propose new transmission projects in response to FERC Order 1000 and Gov. Andrew Cuomo’s New York Energy Highway initiative.
Speaking at the Independent Power Producers of New York’s fall conference, Nachmias noted that the Transmission Owner Transmission Solutions (TOTS) projects, completed in June to counter the potential loss of the Indian Point nuclear plant, were the first major projects built in the state since the 1980s.
NYISO is currently conducting a viability and sufficiency report on proposals submitted in response to the state Public Service Commission’s AC Transmission Upgrade proceeding. Those projects — the Edic-New Scotland and Knickerbocker-Pleasant Valley 345-kV lines — were slowed because they got caught in the transition to rules under FERC Order 1000, said Nachmias, also a vice president of energy policy and regulatory affairs for Consolidated Edison of New York.
In May, the ISO identified 10 proposed transmission projects as finalists to relieve congestion in western New York and connect wind and solar generation to load centers. The ISO acted in response to a 2015 PSC order that said relieving congestion in the Buffalo area would produce environmental and reliability benefits and satisfy a public policy requirement under Order 1000. (See NYISO Identifies 10 Public Policy Tx Projects.)
Nachmias said the ISO, which will ultimately select developers, is learning as it goes.
“The first couple of times it’s not going to be fast because the NYISO is doing this for the first time. They’ve never actually had to select a transmission developer before. So when they do it, they’re probably going to go a little more slowly than they otherwise could.”
Order 1000’s public policy requirement should make more projects possible, Nachmias said. “We had been trying to develop transmission based on economics alone for some time, and it was very difficult to justify.”
The Valley Electric Association board of directors last week approved an agreement to sell the cooperative’s 230-kV transmission network to GridLiance for about $200 million.
The transaction, which still requires approval by two-thirds of Valley Electric’s members, is slated to close in late 2016 or early 2017.
Nevada-based Valley Electric is the only transmission-owning member of CAISO outside of California. The co-op serves 45,000 customers across a 6,800-square-mile service territory located along the southern Nevada-California border.
The deal will provide GridLiance with a foothold in an area that bridges the California market with the interior West.
“This transaction allows us to enter the region with assets located in a strategic area and with a utility partner with impressive foresight in developing the high-voltage transmission system as a gateway between California and the rest of the West,” GridLiance CEO Ed Rahill said.
Valley Electric’s 230-kV line, which connects the cooperative’s service area with key delivery points in Nevada, will provide Gridliance with strategic access to the CAISO market. Map source: Valley Electric Association
Those assets consist of 164 miles of 230-kV lines linking Valley Electric’s base in Pahrump, Nev., with both Las Vegas and the Mead substation — a major delivery point for power wheeled into California — as well as substations along the length of the system. The co-op completed the network in 2013 in order to increase redundancy and improve reliability for its sprawling but sparsely populated service area.
The sale will return Valley Electric 2.4 times its investment in the system, which the co-op says significantly increased in value when it joined CAISO in 2013.
“At that time, our lines became a crucial part of the regional electric grid,” Valley Electric CEO Thomas Husted said.
Husted said Valley Electric sought a buyer for the system because “the premium earned on a sale would be so substantial that it far exceeds the rate of return we currently are earning.” The sale will allow the co-op to retire $82 million in debt and distribute $17.2 million in funds to active and former members who paid into the system. The co-op also plans to reduce its retail rates by 9.9%.
Under the terms of the sale, Valley Electric will still operate and maintain the system. The acquisition will not affect the co-op’s distribution system.
“This is a great moment for Valley Electric member-owners,” Husted said, referring to the agreement as a “partnership” with one of the country’s “foremost” transmission companies. “That’s the way GridLiance looks at it too: forming a relationship with our cooperative as they enter the Western markets. There are no downsides to this partnership.”
Launched in March 2015 with backing from the Blackstone Group, GridLiance bills itself as the nation’s first competitive transmission company focused on collaborating with public power entities. It made its first two acquisitions — 420 miles of 69-kV and 115-kV lines in Missouri and Oklahoma — a year ago. (See GridLiance Makes First Acquisitions.)
ST. PAUL, Minn. — MISO’s external affairs operation wants to reboot its website and is seeking a separate $1 million budget to begin research and development.
The RTO’s project is aimed at freshening its online presence for the public and its membership, and increasing the use of website-usage analytics.
The external affairs division handles MISO’s online communications, meetings, and member and stakeholder relations. Its current $11 million budget is expected to become a $13 million budget over the next five years while membership grows.
Vice President of MISO South Todd Hillman told the Board of Directors’ Corporate Governance and Strategic Planning Committee that the RTO may be lagging behind customers’ technology expectations, as it has performed only two website redesigns in 12 years. It still uses a call center — each of the 430 market participants are assigned customer representatives — to handle issues that Hillman said could be better addressed online or with an app.
“We’ve focused on the touch of our customers, but not the tech of our customers,” Hillman said.
Hillman said MISO has just “scratched the surface” of data analytics. He asked the board to approve a $1 million budget for next year to hire a third party to conduct a comprehensive analysis on a possible new online interface and social media presence that can be adjusted using data analytics.
Directors asked if $1 million was enough to develop improvements. Hillman said if MISO was “diligent,” the amount could work. He said consultants could bid against each other for the best prices.
Director Paul Bonavia also said he hoped MISO would get “a little crazy” with the scope and not restrict it unnecessarily.
Hillman said there is no reason MISO should be limited in its web presence. It could look to other companies who communicate online across multiple channels. “We need to stop looking to other RTOs’ [websites]; maybe we look at Amazon for some ideas,” suggested Hillman, who said a MISO membership app could become a reality.
Hillman said MISO relies heavily on an annual customer service survey for feedback, which Bonavia called “a blunt instrument.” CEO John Bear agreed that more periodic feedback would be helpful.
SARATOGA SPRINGS, N.Y. — Gavin Donohue, CEO of the Independent Power Producers of New York, opened the group’s fall meeting last week by declaring as its top priority NYISO’s reset of the installed capacity demand curve.
Donohue noted the ISO’s prediction that New York’s Clean Energy Standard will significantly increase the need for reserve capacity and highly dispatchable resources.
“Combined with the uptick in announced plant retirements, it has never been more critical to get the demand curve reset right,” Donohue said. “The demand curve is responsible for setting reference prices. It will determine what resources enter the market over the next four years.”
The reset, which has been conducted every three years, is moving to a four-year cycle (with annual updates of some parameters). The ISO staff released its final recommendations Sept. 15 on the new parameters, which include net energy and ancillary services revenues and the gross cost of new entry in addition to reference point prices.
Staff adopted the recommendations of its consultant, The Analysis Group, for reference points for all but the New York Control Area. The firm recommended the reference points for all regions be based on dual-fuel requirements, while staff said the NYCA — the rest of state, excluding Long Island, New York City and the Lower Hudson Valley — should be based on gas only. Staff also shaved the proposed price for NYCA by 4.5%, rejecting the consultant’s proposal of $11.22/kW-month in favor of $10.72/kW-month.
Donohue also noted generators struggled with low load growth and record low gas prices, which he said are “driving previously economic facilities to the brink and resulting in various forms of state intervention.”
“It’s not clear how this effort will play out. But it’s clear that market-based solutions are always preferable to out-of-market solutions in New York state,” he said.
The ISO will accept written comments on the proposed demand curve through Oct. 3, with oral presentations to the Board of Directors on Oct. 17. The board’s finalized parameters will be filed for FERC approval by Nov. 30 with the revised curves taking effect May 1, 2017.
ST. PAUL, Minn. — MISO Steering Committee members are asking if there is a need to formalize the creation and retirement of task teams following the Resource Adequacy Subcommittee’s contentious decision in July to retire the Competitive Retail Solution Task Team.
“There’s no formal process for retiring a task team, and there’s good reason for that. Task teams do not follow the Stakeholder Governance Guide,” Steering Committee Chair Tia Elliott said. “I heard from stakeholders that it’s important to keep that process outside of formalization.”
American Electric Power’s Kent Feliks said he opposed formalizing task team creation and that, like PJM, MISO could use special meetings to discuss issues that would cut down on the number of task teams that parent entities create.
Resource Adequacy Subcommittee Chair Gary Mathis said it may be helpful to insert language into the Stakeholder Governance Guide to define how task teams are formed and dissolved.
Ameren’s Ray McCausland said Robert’s Rules of Order currently govern the creation and disbanding of task teams, because the Stakeholder Governance Guide defers to Robert’s Rules when directions “aren’t otherwise stated.”
Mathis said the bylaws are worded so that only parent entities are required to follow Robert’s Rules, not task teams. Feliks said he preferred leaving the creation and dissolution of task teams up to parent entity leadership.
After discussion, the issue was tabled until the Steering Committee’s Nov. 3 Stakeholder Governance Guide workshop.
Steering Committee members also discussed whether changes are needed to get callers queued up more quickly during meetings. Currently, entity chairs are in charge of recognizing callers with opinions and questions.
Currently, McCausland said, operator-assisted calls are in violation of the governance guide. He said callers should be able to interrupt the speaker directly by deselecting their mute buttons. He argued that people attending in-person have rights that those dialing in do not have.
“It’s a brainer. We have to think about this,” Mathis added.
Elliott said the issue could be handled by MISO with a technology fix, possibly through a function that allows callers to immediately open lines without operator assistance.
FERC last week approved Macquarie Energy’s request to revise its market-based rate tariff to allow the company to engage in short-term simultaneous transactions along a key Pacific Northwest transmission system partly controlled by Puget Sound Energy — a Macquarie affiliate (ER16-2198).
The commission’s decision enables Macquarie to trade energy and capacity with an unaffiliated counterparty on the California Oregon Intertie (COI) north of the California Oregon Border (COB) trading hub while at the same time executing an opposite transaction at the John Day hub in central Oregon.
COB is a major delivery point for wheeling Northwest generation intended for markets in California. The John Day hub is predominantly used to price bilateral transactions involving output from hydroelectric and wind resources in central and eastern Oregon and Washington, often intended for delivery into California.
The John Day Dam and its substations comprise a primary pricing point for bilateral transactions involving output from hydroelectric and wind resources in central and eastern Oregon and Washington — often intended for delivery into California. Photo source: Oregon Dept. of Energy
PSE is one of six holders of capacity on the northern portion of the COI, with Seattle City Light, Pacific Northwest Generating Cooperative, Snohomish County Public Utility District, Tacoma Power and PacifiCorp’s merchant arm making up the rest of the group. The COI’s owners — Bonneville Power Administration, PacifiCorp and Portland General Electric — also control capacity on the system, which consists of three parallel transmission lines.
Macquarie Energy and PSE are both subsidiaries of Australia-based investment bank Macquarie Group.
Headquartered in Houston, Macquarie Energy operates as an independent power marketer throughout the U.S. The company does not own or operate generation or transmission assets in the Northwest, controlling only a small amount of generation, in the PJM balancing authority area, through long-term contracts. PSE is a vertically integrated utility serving about 1.1 million electricity customers in northern Washington. The utility also operates a wholesale marketing arm.
In 2012, the commission ruled that “when a simultaneous exchange transaction involves the marketing function of a public utility transmission provider, the public utility must seek prior approval from the commission if the transaction involves its affiliated transmission provider’s system.” Approval of such transactions would be made on a case-by-case basis, the commission said.
Macquarie’s July 14 FERC filing requesting the tariff change contested the need for the company to obtain prior authorization to engage in transactions at COB and John Day. The company said that while it is technically an affiliate of PSE, it does not function as PSE’s wholesale marketer or buyer.
The commission rejected that contention.
“We are not persuaded by Macquarie Energy’s argument that, because Macquarie Energy neither markets any of Puget Sound’s generation nor purchases any power for or on behalf of Puget Sound and only purchases point-to-point transmission from Puget Sound, its affiliate relationship with Puget Sound is not equivalent to acting as the wholesale merchant function of a transmission provider and therefore merits different treatment,” the commission wrote, adding Macquarie could potentially perform PSE’s wholesale market function.
The commission nonetheless authorized Macquarie to engage in the proposed trades, saying the company provided FERC with sufficient information to evaluate the transactions.
“We find that Macquarie Energy has adequately addressed the commission’s concern regarding circumvention of open access requirements and has demonstrated that its proposed transactions are not an attempt to offer transmission service without reserving transmission,” the commission wrote.
More important to the commission was the fact that Macquarie cannot use PSE’s network transmission to engage in the transactions, but must instead purchase point-to-point service in order to move energy between COB and John Day.
“The inability to use network transmission service mitigates the concern that Macquarie Energy’s proposed transaction will allow Puget Sound to earn revenue from both the explicit sale of transmission service and the implicit sale of transmission service via Macquarie Energy’s proposed transactions,” the commission wrote.
Furthermore, given the diverse ownership of capacity on the COI, Macquarie is not limited to purchasing point-to-point service from just PSE.
“Moreover, any transmission service obtained by Macquarie Energy on the COI would be under the [tariff] of the entity providing the service, including Puget Sound,” the commission said.
AARP and the Public Utility Law Project want New York regulators to provide more documentation to justify the Clean Energy Standard’s estimated $2/month rate increase for the average consumer.
The groups wrote to the New York Public Service Commission last week, saying the commission’s Aug. 1 CES order did not explain the costs to keep upstate nuclear power plants operating with zero-emission credits. (See New York Adopts Clean Energy Standard, Nuclear Subsidy.)
“AARP and PULP are very concerned that the Clean Energy Standard implementation (particularly the subsidy for power plants) may have costly impacts on New Yorkers already facing among the highest electricity rates in the nation,” the letter states. “The mention of a potential $2/month residential bill impact from the Tier 3 purchase of zero-emission credits in the order was not accompanied by any details or citation to where such an estimate was derived and fails to provide sufficient cost and bill impact information for each customer class, for each utility, or for the entire 12-year commitment to support these power plants.”
The groups cite estimates by PSC staff that the ZEC program could cost up to $8 billion over its 12-year term.
They also cite other utility programs that will be borne by ratepayers, including a $1.5 billion smart meter program in the Consolidated Edison territory, cost recovery for distributed energy demonstrations projects and $5 billion for clean energy and energy efficiency programs run by the New York State Energy Research and Development Authority.
These cases and the CES “simply cannot be viewed separately,” the groups add.
The letter comes days after downstate legislators complained that the ZEC program costs were disproportionately burdensome on New York City-area ratepayers. The PSC pushed back in a reply, saying the economic benefits and reduced emissions benefited ratepayers statewide. (See New York Legislators Question Nuclear Subsidy.)
