CAISO last week launched an initiative to develop a greenhouse gas accounting system suitable for an expanded ISO.
The challenge for the ISO is to strike a balance between the requirements for California’s load-serving entities, which face increasingly stringent GHG emission limits under the state’s cap-and-trade program, and the needs of out-of-state utilities not subject to that mandate.
CAISO is seeking to determine how it can modify its market dispatch process under a regionalized footprint to ensure that energy transactions serving load in California reflect GHG compliance costs, while at the same time allowing deliveries outside the state to exclude any emissions component.
“As the ISO explores a transition from a predominantly single-state balancing authority area to a multistate balancing authority area, the ISO will need to model and identify market flows between market nodes subject to GHG compliance and nodes that are not subject to GHG compliance,” CAISO said in an issue paper.
Before expanding into other Western states, CAISO must develop a GHG accounting system that enables the ISO market to track and price emissions from all participating resources (such as the Jim Bridger plant shown above) while allowing bids from out-of-state generators to exclude GHG costs when not serving California demand Photo Source: PacifiCorp
At present, all energy serving ISO load regardless of its geographical source is subject to cap-and-trade. Internal and external generators alike embed their GHG compliance costs within their day-ahead and real-time market bids, including start-up and minimum load costs. During market runs, the ISO’s market software selects from among those bids to determine the least-cost dispatch to cover all load.
In other words, the energy cost component of the market’s LMP, which is the same for all nodes within the ISO, always reflects a GHG compliance cost.
Complications
While that works for a California-only market, it becomes problematic for an expanded ISO in which LSEs in other states would effectively be forced to pay a premium for compliance with rules that do not apply to them.
CAISO is seeking a way to extract the GHG compliance cost from energy bids by resources serving load outside California while retaining it for in-state loads within the state, all within a single market run.
Because California thermal generators must include a GHG cost in their bids regardless of the location of the sink, however, the only deliveries excluded from the cost will be those in which both source and sink are outside the state.
Another complication is that CAISO currently uses e-Tags to track GHG compliance obligations for energy imported into California. But as the ISO absorbs neighboring balancing authority areas, it will discontinue tagging of transfers from those areas as what were once considered imports become internal ISO transactions.
The Western Energy Imbalance Market (EIM) could provide a model for an expanded ISO, with some limitations.
Rather than embedding GHG costs within energy bids, the EIM allows a participating resource to submit a secondary “GHG adder” — in addition to the bid — to signal its willingness to deliver power into California. If the adder is set to zero, the resource’s output is ineligible for delivery into the ISO but can still serve load in other balancing areas.
“The ISO designed the [EIM] so that the GHG compliance costs will not affect the price in an EIM balancing authority area when load is met from generation external to the ISO,” CAISO said.
Leakage
But California’s Air Resources Board (ARB), which oversees the cap-and-trade program, has expressed worry that the EIM’s dispatch model is inadvertently facilitating carbon “leakage.”
Leakage occurs when the emissions program logs a reduction, despite the fact that no actual decrease in atmospheric GHGs has occurred because of a secondary dispatch: The model attributes balancing energy from a low-emitting out-of-state resource to CAISO, while not accounting for the dispatch of a higher emitting resource serving external demand that would have been covered by the first resource absent the EIM. (See CAISO, ARB to Address Imbalance Market Carbon Leakage.)
CAISO has acknowledged ARB’s concerns and is working with the agency to address the problem. The ISO also wants the board to consider the counteracting effect of atmospheric emissions reductions that occur when the EIM displaces out-of-state thermal generation with renewable exports from California, an approach that could inform GHG accounting in an expanded ISO.
The ISO’s effort to address the GHG accounting is taking shape amid uncertainty about the adoption of cap-and-trade in the West at large. Any design has to be “mindful of the potential need to support multiple GHG trading programs” in the region, the ISO said.
“As more trading models are supported, the complexity will increase and transparency will decrease, which is very likely to lead to a less efficient achievement of carbon reduction goals,” CAISO said, adding that it seeks input that “can foster regional cooperation.”
CAISO will discuss the issue paper during a stakeholder call today. Written comments on the initiative are due by Sept. 20.
All storage resources wanting to qualify as capacity should register as behind-the-meter for the 2017/18 planning year, MISO said at last week’s two-day Resource Adequacy Subcommittee meeting.
The AES Corporation partnered with Indianapolis Power and Light to open the first battery storage facility in MISO in June.
Manager of Resource Adequacy John Harmon said the requirement is a way to accredit storage resources using MISO’s existing framework for load-modifying resources while the RTO develops more comprehensive definitions for storage.
MISO said it is attempting to “clarify the framework” for allowing storage that can provide four hours of continuous energy to offer capacity while also participating as Stored Energy Resource (SER) in the regulation market.
Harmon said more discussion is needed for qualifying storage resources that do not wish to be classified as behind-the-meter. MISO also has yet to develop procedures to support sustained power from storage resources, Harmon said.
“We worked through that [research and development] process and found it would not be feasible for registration in time for the 2017/18 planning year,” Harmon said.
In preparation for next year’s auction, MISO is proposing to certify the capability of storage as capacity based on data from the Generating Availability Data System. Class or fleet averages will be used for storage with less than 12 months of GADS data.
The RTO is asking stakeholders this week for input on incorporating storage using the existing qualification process.
Kent Feliks, manager of regulatory and RTO policy at American Electric Power, asked how many storage resources are going to be able to register as capacity in the near future.
“It’s pretty small. It’s probably less than 100 MW, and that’s being generous,” Harmon said.
Consumers Energy’s Jeff Beattie asked how many megawatts of storage are currently in the interconnection queue.
“I can’t answer that, but I do hear interest from individual market participants. From what I see, we’re at the early stages. That’s why we have rules dealing in the short term and are talking about developing solutions to get ahead of this as much as we can,” Harmon said.
RASC to Take Up Gas-Electric Coordination
Renuka Chatterjee, MISO executive director of resource adequacy and transmission access planning, told the RASC to send ideas and comments on a plan to improve gas-electric coordination.
Chatterjee also said the RASC would probably take over management of MISO’s winter fuel survey, which was previously handled by the now-closed Electric and Natural Gas Coordination Task Force.
IRVING, Texas — SPP’s transmission buildout, interregional processes, new generation resources and cyber threats highlighted the Gulf Coast Power Association’s third annual SPP Regional Conference on Sept. 1. Here’s a summary of what the more than 150 attendees heard.
Three influential SPP stakeholders debated the merits of FERC’s Order 1000’s competitive transmission process and just how much more transmission needs to be built, after more than $9.7 billion in upgrades since 2004.
“As one who serves members, we know transmission has to be built to get the energy out, but we don’t want it built on the backs of the consumers of SPP,” said Mike Wise, chair of the RTO’s Strategic Planning Committee and senior vice president of commercial operations and transmission for Golden Spread Electric Cooperative. “Transmission is an inter-generational asset. The stuff we’ve built is providing those dividends. The question is how do you get transmission built and paid for by those who are really benefiting from it.”
“Is the current transmission funding method working? Yes,” said GridLiance COO Noman Williams, who chairs SPP’s Markets and Operations Policy Committee. SPP’s “highway/byway regional cost [sharing] allocates the cost for future transmission facilities based on voltage level. What we’re seeing is pockets of load growth and load shifting. Ultimately, we’re going to see additional build in SPP. If you look at the age of the infrastructure in SPP … there’s a lot of old stuff.
“So will there be a need to have additional transmission built? I’d say yes, if that’s the goal,” Williams said. “The real frontier for transmission in SPP the next 10 to 15 years is at the seams. How do you deal with that, and how do you get energy to the seam?”
Former Missouri Public Service Commissioner Steve Gaw, SPP policy director for The Wind Coalition, said Order 1000 is not yet providing needed solutions to interregional planning. “Order 1000 really needs to be strengthened so we are … implementing [interregional] transmission in the best interest of consumers, the same way we do it regionally.
“I think it should be a top priority for FERC to work on that issue. I think it’s already clear there’s a substantial problem with the order,” Gaw said. “There are significant questions about what type of upgrades will be necessary, and whether or not we can ever get those paid for in the [generation interconnection] process we have now. We need a mechanism to try and figure out whether there’s another way to do this.”
Wise agreed with Gaw, saying the RTOs could use some help from above in building interregional projects.
“There’s a little bit of transmission that needs to be built for load pockets, but I think the projects that need to be built are across the regions,” Wise said. “We need some sort of national directive for getting transmission built across regions. Is Order 1000 the right way to do this? Quite possibly, but we need a federal directive and federal help to get these interregional projects built.”
Williams said competitive transmission is off to a slow start in SPP, contrasting the withdrawal of the RTO’s only awarded project with the ability of PJM and CAISO to approve competitive projects. “We recognize we can do it better and we can do it cheaper,” he said. “We devoted a fair amount of cost to participating in that process, but in the end, we didn’t build a project that didn’t need to be built.”
“The caution I have for Steve and Noman is the load has to pay for this. We need to make sure the [transmission] projects show a real cost-to-benefit,” Wise said. “We do not want to build transmission that benefits the load if the load isn’t going to pay for it.”
Wise said wind generation enabled by transmission had produced economic development in his company’s footprint. “Golden Spread landowners … they love to have these wind farms built on their land,” he said. “It’s generating huge amounts of money for them. We want to encourage this.”
As chair of SPP’s Seams Steering Committee since its creation in 2010, Paul Malone is well aware of the difficulty the RTO has had in developing interregional projects with MISO.
“We’ve hit a wall when it comes to building interregional transmission,” said Malone, transmission compliance and planning manager for the Nebraska Public Power District. “We’ve built a lot of transmission in the SPP footprint, but we’re having difficulty of finding solutions that cross the borders.”
Alan Myers, director of regional planning for ITC Holdings, lamented the lack of infrastructure across the RTO seams, saying it’s a nationwide problem.
“People have been saying we need some sort of a national policy and vision for some of those things, but we don’t have it,” he said. “That doesn’t mean we can’t stop asking for it. We need a national view to provide correct signals. Each RTO serves their own masters and interests, but sometimes, you need another view to close those gaps.
“One of the things we’ve consistently done as an industry is undervalue transmission construction. … If a project is good across the seams, does it really matter if it’s a low-voltage project? Can’t it just be a good project? How about we start talking about beneficial projects, rather than reliability, economic and policy projects?”
Merchant transmission projects have their own difficulties, said Jonathan Abebe, manager of engineering and transmission for Clean Line Energy Partners. Two of the company’s six proposed projects focused on delivering wind energy from the Great Plains to the seaboards, the Grain Belt Express Clean Line and the Plains & Eastern Clean Line, begin in SPP’s footprint.
“Some projects are more challenging than others, specifically the financing,” Abebe said. “We cross multiple states, so we need approval in multiple states. It’s much easier to make the case for the line in states where wind is being built and where it’s being delivered. Some of issues we’ve had are in the fly-by states that are not getting the wind.
“A lot of these RTOs are used to approving projects coming in front of them. There’s not a process for RTOs to study merchant projects, which causes regulators difficulties in approving them.”
Former MISO CEO Graham Edwards (2006-2009), an SPP director since January, gave the keynote address, urging RTOs to remember their end consumers and to continue to improve interregional processes.
“We need to demonstrate value, and we need to communicate the value,” he said. “We haven’t been very good about communicating the benefit we bring to the … residential and industrial consumers that are on your systems.”
Edwards also said the difficulties SPP and MISO have had in approving interregional projects is partly because of criteria that discount lower-voltage transmission lines.
“The lower-voltage projects need some attention, in my opinion. Interregional planning has some merit to it. … I think the RTOs can, and should, get together and better implement those processes across the seams,” he said.
Renewables, Storage Growing but ‘There’s Still Life’ in Coal
With the Clean Power Plan looming and cheap gas having replaced coal as the dominant generation source, it probably shouldn’t come as a surprise that SPP’s generation interconnection queue does not include a single megawatt of coal.
It does list 22,000 MW of wind and 2,800 MW of solar. The queue also lists 700 MW of gas-fired generation.
Tenaska Power Service’s Courtney Mehan, director of SPP origination, called the CPP “the elephant in the room.”
“Some speculate 2 [GW] of coal retirements as a result of the Clean Power Plan. That overhanging [regulation] and cost is going to drive most of these coal retirements, but there’s still life in these plants.”
Noting a NERC forecast from December that SPP won’t dip below its 13.6% reserve margin until 2024, Mehan said, “Without these kinds of reserve margins, without significant retirements, you aren’t going to see a push to build” non-renewable generation.
Bill Grant, director of strategic planning for Xcel Energy’s interests in New Mexico and Texas, said declining water tables are making it difficult to site new thermal generators that require cooling.
“What are your options?” he asked, before referencing another speaker’s comment on plant maintenance. “Maybe it’s the old utility concept of putting duct tape on the [existing] plant and keeping it going for 50 years.”
Or maybe it’s wind energy, which has provided nearly half of SPP’s total generation at times in 2016. (See “Integrated Marketplace Adds Participants, Wind Energy,” SPP RSC Briefs.)
Grant, who chaired SPP’s first wind integration study, recalled its analysis assumed 13 GW of available wind energy.
“Well, guess what? We’re there. We’re taking that much wind energy right now,” he said. “I think we’ve overcome some of the concerns and myths and operational impediments to do that.”
Ben Lowe, director of policy and market development for energy storage provider Alevo USA, said grid-scale storage, with its ability to integrate renewable energy, and provide voltage and ramping support and frequency regulation, makes it “the grid’s Swiss Army knife.”
“Storage makes the grid more efficient, and its costs are only coming down,” he said. “We’re pretty optimistic about what the future holds.”
Members of SPP’s Market Working Group said it has been successful even though it has not produced a large number of new products.
The group is “extremely open. Sometimes, I feel like maybe it’s too much discussion,” said Robert Safuto, director of SPP market intelligence for Customized Energy Solutions. “I think it’s better to lean towards what SPP does. Anyone can show up or listen in and offer an opinion. Other markets I deal with are not like that.”
“I feel like coming into the market, we had a voice right away with the major decisions going on,” said Valerie Weigel, manager of marketing financial analytics for Basin Electric Power Cooperative, which joined SPP last October. “We’ve brought our concerns forward and we’ve been heard.”
Cliff Franklin, a senior regulatory specialist with Westar Energy, said the MWG has discussed only one possible new market offering, a ramping product “that isn’t something you bid or offer or clear in the market.”
“It’s more of an opportunity-cost kind of a thing,” Franklin explained. “Here’s the theory: You allow slower-ramping units to start up in the morning and save your faster units for when you really need them. Why do this? If we can manage ramp better, we might reduce the amount of headroom, which reduces production costs.”
“It’s hard to build a business case around market design or a market element, like battery storage,” said Kevin Galke, a structure and pricing analyst with The Energy Authority. “I don’t think you really want to be the last person to bring a product to market, but I applaud SPP for learning from what others are doing to make a full functioning and operating market.”
Cybersecurity Experts: not if, but when Grid is Attacked
A pair of cybersecurity experts had dire warnings for the audience and suggestions on the protective actions utilities can take.
“A lot of things you’re doing now is [Internet Protocol]-based,” said former Secret Service agent Steven Bullitt, vice president of cyber forensics and investigation for NTT Security, a subsidiary of Nippon Telegraph and Telephone. “I always say you’re either a victim of opportunity or a victim of choice. You’re mostly victims of choice, because you have aging systems and are moving into IP-based solutions, which exposes you to the Internet.
“You’re going to see more attacks in this industry. Other companies may just lose data, but if they hit you, that’s going to have severe consequences.”
Bullitt recalled attending a conference last October, where he was joined by former National Security Agency directors Gen. Keith Alexander and Gen. Michael Hayden. “Gen. Alexander said we’re experiencing the greatest transfer of wealth in our history. He said our intellectual property is being stolen by China and Russia. Gen. Hayden said, ‘Folks, the cavalry is not coming. If you think the government is going to step in, it’s not. You’re on your own.’”
“One thing we know is, it’s not if we’re going to have a cyberattack on the grid, but when,” said former FERC Chairman Curt Hébert, a partner with Brunini, Grantham, Grower & Hewes. “We know this threat has evolved and it’s not standing still. That means we can’t stand still, either. It’s going to be expensive, and I hate that, but it’s necessary so that we can protect our systems.”
Jim Eckelberger, chair of SPP’s Board of Directors, closed the conference with a look 20 years into the future. He predicted “really sophisticated gas plants” will replace all coal plants and that SPP’s 14-state footprint will have so much renewable energy it may not need fossil-fueled generation.
“The Southwest Power Pool is one of those places where green energy is immensely abundant. … It’s the cheapest energy source anywhere in the United States, besides hydro,” he said.
Unlike some of the other speakers, Eckelberger said he isn’t seeking a national energy policy to guide the way forward. “The president is responsible for federal matters, but governors, not presidents, are in charge of what happens in the land mass. … I think the federal government is pretty useless in this process.”
Arizona Public Service and Puget Sound Energy have met the milestones to participate in the CAISO-run Western Energy Imbalance Market and will begin trading in the market on Oct. 1.
“For APS and PSE, the bulk of the work is behind us,” Janet Morris, CAISO’s program management office director, told the EIM’s governing body during an Aug. 30 meeting.
The ISO last year developed a series of readiness criteria to ensure that new EIM participants are prepared to link up with the market.
Among the requirements: executing necessary agreements, establishing forecasting and balanced scheduling capabilities, producing accurate market settlements, and exchanging sufficient data to allow the ISO to monitor market performance.
The implementation process takes about 18 months and requires a new participant to integrate its network model — essentially a detailed blueprint of the balancing authority area’s operations — with that of the ISO. The process culminates in two months of market simulation, in which the participant operates in real conditions without transactions becoming financially binding. (See Arizona Public Service, Puget Sound Energy Enter EIM Testing Phase.)
Morris pointed out that the go-live date for APS and PSE will coincide with a significant update to the EIM’s market software. All participants, including existing members PacifiCorp and NV Energy, are required to “validate” the new market features. In the future, CAISO plans to schedule new member implementations for spring in order to avoid overlap with fall software releases.
“What’s one or two of the top things you learned from implementations to help others out there” planning to join the EIM? asked governing body member John Prescott.
“I think one of the first challenges in the early part of implementation is organizational change management,” Morris said, referring to the need for utility staff to adapt to the EIM’s operational practices. Those participants “need to understand how all the data fed into the market influences the market’s outcomes.”
Later in the implementation, new participants come to recognize the need for the two months of parallel testing, Morris added.
Governing body member Carl Linvill wondered if new participants have realized any “side benefits” from integrating their network models with the ISO.
“I think there’s a lot of benefits of having that visibility [into another balancing authority area] to enhance reliability,” Morris said. “That’s absolutely another benefit besides those coming out of the market.”
Morris told the governing body that Portland General Electric is on track to join the EIM in October 2017 after completing a scheduling coordinator agreement, identifying all participating resources in its area and providing a full network model ready for CAISO integration.
Idaho Power is also on schedule for an April 2018 start-up. An implementation agreement has been approved by FERC, and the utility plans to file for approval with the Idaho Public Utilities Commission by the end of summer. The company expects to export its network model to the ISO late next month.
Circling back to the upcoming APS and PSE implementation, governing body member Valerie Fong pointed out that it will be the first in which two utilities are integrated into the EIM on the same day — and at opposite ends of the Western Interconnection.
“We’re confident, but with that confidence we rely on a very robust support plan,” Morris said. “We plan for the worst and expect the best.”
Numerous stakeholders have called for rehearing of New York’s Clean Energy Standard, raising objections over the subsidy for nuclear power, the elimination of support for some legacy renewable energy plants and the potential loss of renewable energy credits (REC) to adjoining states (15-E-0302).
Most of the requests were filed shortly before the mid-week deadline following the New York Public Service Commission’s Aug. 1 order approving the standard. (See New York Adopts Clean Energy Standard, Nuclear Subsidy.)
The CES is designed to support the state goal of 50% renewables by 2030, with nuclear power seen as a bridge until renewable energy facilities are built at scale.
Nuclear Subsidy Under Attack
The most controversial part of the order created a new “Tier 3” subsidy — zero emission credits (ZECs) — for nuclear power. Critics say the program would cost more than $7 billion over its 12-year lifespan. Without ZECs, nuclear owners said their plants would close, and state officials said carbon reduction goals could not be met.
The Alliance for a Green Economy and a coalition of environmental, anti-nuclear groups and elected officials objected to the subsidy as counter to the goals in the state Energy Plan and the Reforming the Energy Vision initiative.
“The PSC has failed to demonstrate that imposing exorbitant surcharges which inure solely to the benefit of nuclear operator(s) is in the public interest and consistent with existing statute and policy,” the coalition wrote.
Canadian Hydro’s Complaint
Canadian hydropower developer HQ Energy Services said additional resources from Quebec would not be credited for their environmental attributes. “For reasons unexplained, the CES order excludes significant amounts of hydroelectric power, including incremental hydroelectric power relying on new storage impoundment, from inclusion in the CES Tier 1 solicitation and REC process,” it wrote.
Tier 1 establishes the obligation of load-serving entities to invest in new renewable energy resources with an in-service date of Jan. 1, 2015, or later.
Tier 2 in the order is limited to run-of-river hydroelectric facilities of 5 MW or less, wind farms and biomass direct combustion plants that were operating before Jan. 1, 2003.
PSC staff had advocated splitting legacy renewables into two groups: Tier 2a for those resources able to sell their attributes in other states; and Tier 2b, for those unable to sell attributes because of their age or other restrictions imposed by neighboring states.
The order said splitting the “maintenance tier” for existing renewable energy resources was premature. Facilities eligible for these payments would have to demonstrate they would likely close because of their unprofitability without additional support from the state.
“It is very possible that New York will have to replace the clean attributes of existing facilities that are sold in Massachusetts with clean attributes from new facilities at a higher cost to meet the 50-by-30 goal,” IPPNY wrote. (See Massachusetts Bill Boosts Offshore Wind, Canadian Hydro.)
Likewise, Transmission Developers Inc. seeks rehearing because of this “change in circumstances” since the order was adopted. “Such an initiative by a neighboring state very well could have the effect of siphoning off a significant portion of the renewable energy supply that would otherwise be available to New York state,” it wrote.
Procedural Complaint
The Public Utility Law Project alleged the compressed schedule under which the PSC considered ZECs violated the State Administrative Procedure Act (SAPA). The group contends the law requires 45 days for public comment instead of the 10 that the PSC allowed after the staff proposal that included ZECs was released in early July.
“Nowhere in SAPA, however, is there authorization for ‘add-on’ rules or rules resulting from the ‘logical outgrowth’ of the process since the issuance of a prior notice that did not cover the changes contemplated,” PULP wrote.
Last month, small hydropower owner Ampersand Hydro filed a complaint with the PSC, seeking inclusion in the ZEC tier as a non-emitting resource. (See Hydro Owner Wants in on New York Nuke Subsidy.) A similar request was made last week by Energy Ottawa.
Exelon also sought clarification to protect ZEC payments to its R.E. Ginna and Nine Mile Point nuclear plants in the event its proposed acquisition of the FitzPatrick plant falls through. (See FitzPatrick Sale Filed with New York Regulators.)
The New England Power Pool (NEPOOL) is considering redesigning its market rules to align them with the region’s efforts to reduce carbon emissions from the generation sector.
Gordon Source: PSEG
The first of six scheduled stakeholder meetings on the Integrating Markets and Public Policy (IMAPP) process was held Aug. 11.
The goal is to provide guidance to ISO-NE on how wholesale markets could be adapted to meet the public policy goals of the New England states. The group hopes to complete its work by the RTO’s annual meeting Dec. 2 with market rule changes filed with FERC beginning next year.
NEPOOL, created in 1971, has more than 440 members (with about 260 voting members), including utilities, independent power producers, marketers, load aggregators, end users and demand response providers.
RTO Insider recently spoke to its chairman, Joel S. Gordon, whose day job is director of market policy at Public Service Enterprise Group’s PSEG Power Connecticut unit. The interview has been edited for clarity.
New England has usually had an active public policy agenda related to energy, but this is a rather different way to approach this topic. So, why now?
“If you look at the New England states, there has been a rather large consensus that the environmental objectives that the individual states have are all heading in the same direction. The states have different means to achieve them, but they are all part of the Regional Greenhouse Gas Initiative, and some of them have even more aggressive targets than RGGI.
“They have outlined means to achieve [decarbonization] through mandates for aggressive carbon reduction and renewable energy goals, so in order to meet those targets that have been legislatively mandated, they needed to take some actions that are outside of the market.
“Right now, the markets, as we’ve designed them, are not designed to drive the [decarbonization] of the generation fleet. It is designed to find the most efficient set of resources and to meet a reliability need, which has been the mission of NEPOOL and ISO-NE throughout the entirety of their existence.
“The recognition of our members has been that over the last couple of years, as we’ve seen more programs come out of the states, we’ve recognized that the markets were not really not going to give them what they needed, so the states took these out-of-market actions. [IMAPP] is a recognition that the states have legitimate public policy goals, so the markets should be designed to help achieve those public policy goals.”
“From the states’ perspective, the markets weren’t moving fast enough to get them where they needed to be and that’s where these big RFPs come from, and the Massachusetts legislation. Our goal at NEPOOL and for the region is to create a competitive market signal to get the states what they need so they don’t have to act on their own. If we’re successful, the markets on their own will find the most cost-effective means in meeting those state objectives.”
In remarks to stakeholders, you said, “No other RTO has done this before.” Are you optimistic that you can meet these challenges, or is it a bit frightening that New England is out there a bit alone, perhaps the first region trying to integrate markets to this extent with public policy?
“I’m incredibly optimistic that we can find solutions to the problems that we face, the challenges before us. That’s what NEPOOL is really good at as a stakeholder organization. We have six different governing sections that look at our industry from all different perspectives. This is what the IMAPP initiative is, reaching out to the members as they try to find solutions to the challenges.
“I’m also optimistic that the states have encouraged us to do this. They recognized that in [the multistate requests for clean energy] that there’s potential in what the markets have developed. But recognizing they have objectives mandated in their legislation, we can provide a pathway to achieving their objectives using the discipline of competitive markets.”
You seem to have a pretty aggressive schedule in what seems to be a large task ahead of you. Are you confident you will have a consensus document to present to ISO-NE in December?
“The process that we’ve set up [six meetings over four months] is an aggressive schedule. But it’s also important that we put ourselves in that schedule so when we start out in 2017, that we’ll be in a position to respond to the mandates that are out there legislatively. They have carbon reduction goals, so we have to start the process sooner, rather than later, to go to a market-based solution. It also provides the states with an opportunity to see what NEPOOL is doing. They may see there is less pressure for them to act if they see what we’re doing. Really, it’s our first step. I think we’ll be able to get to a high-level framework document by December.
“We hopefully will have a framework for a suite of solutions that would achieve a set of objectives, then we would get into the traditional NEPOOL process that works with ISO-NE and begins to analyze how it would work with the market rules. Then we would begin to work that into the Tariff revisions that would implement it.”
Do you see this process being informative for other RTOs, or do you see New England’s situation as unique?
“We are looking to the other regions as well to understand other concepts that are out there that may help to achieve our goals, which are somewhat unique to New England. We see some of this discussion in PJM in their Grid 20/20 process. [See PJM’s Grid 20/20 Ponders Mixing Public Policy, Competitive Markets.] But integrating public policy is not part of their mandate. In New England, we are fortunate in there are six states and they’re pretty much aligned, as opposed to [PJM’s] 13 states [which are not].”
Would it lead to inefficient market outcomes if rules that go into effect 10 years from now run counter to commitments that states make now through long-term power purchase agreements?
“Timing is going to be a challenge, there’s no question. We’ve talked about two timelines that we need to deal with [10-year goals and 30-year goals for emission reductions.] … I think we’re going to have to work on integrating the short-term and the long-term. I’m not sure how that happens. That’s one of the things that this process is going to have to deal with.”
MISO officials said last week they are still finalizing their forward auction proposal for competitive areas, but the changes won’t be significant and won’t affect a late fall FERC filing. Meanwhile, simulations including the new proposal suggested it could result in large price disparities.
Jeff Bladen, executive director of market services, said MISO is now targeting a Nov. 1 filing, with implementation in the 2018/19 planning year. The RTO plans to release another version of draft Tariff language at a Sept. 19 Resource Adequacy Subcommittee meeting and collect stakeholder feedback by the Oct. 6 RASC meeting. The Brattle Group will also present more forward auction findings at the September meeting. (See MISO Delays Forward Auction Filing; Issues Draft Tariff and Business Rules.)
“At this point, we’re not anticipating any meaningful changes,” Bladen said at a two-day RASC meeting last week.
Bladen said MISO is still working on a materiality clause to determine which retail choice load participates in the forward auction in Michigan and Wisconsin, where the zonal boundaries straddle state lines.
The RTO also is considering changes to its cap on the safe harbor provision that excuses supply from having to offer capacity.
The current cap is based on historical planning reserve margin requirements (PRMR) and an “open-ended” exception process. MISO is considering a cap based on projected PRMR and a “prescriptive” exception process, and one based on projected PRMR plus additional prescriptive adjustments with no exception process.
Based on stakeholder feedback, MISO is reworking transmission modeling compatibility between the forward and prompt Planning Resource Auction and a simultaneous feasibility test, which judges the system’s ability to handle all megawatts of capacity dispatched during a maximum generation event. Bladen said MISO is still refining a possible congestion charge to remedy infeasible capacity delivery through cost allocation.
“We want to make sure that anything that clears in the FRA [Forward Resource Auction] will be feasible with the rest of the footprint,” Bladen said.
Mark Volpe, senior director of regulatory affairs for Dynegy, asked if MISO is still working with Independent Market Monitor David Patton on his concerns over price formation.
“We speak with the Market Monitor on a regular basis. While we continue to have a difference of view, we are open to his advice and feedback on how and when to improve the FRA, [but] the price formation concerns that he’s raised are not what we’re seeing,” Bladen said. “I think the nature of his role as an adviser is not in question. But at this point, we have a difference of view in what the data shows, and that’s not uncommon with topics like this.”
When pressed by stakeholders on how much of the Monitor’s advice would be incorporated, Bladen became less conciliatory, suggesting the RTO would rely on Brattle’s suggestions. “There’s nothing [in the Tariff] to suggest that Potomac Economics is the sole [adviser] for MISO,” he said. “And FERC is the ultimate arbiter.”
RASC Chair Gary Mathis asked if MISO could leave certain details out of the filing to work out later. Bladen said he expected the filing to include all relevant details.
“Like most FERC filings, everything is up for grabs once FERC gets its hands on it,” Bladen added.
Michael Chiasson of Potomac Economics asked if MISO would leave any details out of the filing in favor of providing a reference to the accompanying Business Practices Manual. Bladen said MISO would not.
MISO-IPL Analysis Produces Disparities
MISO also collaborated with Indianapolis Power and Light on a forward auction pricing analysis, which used results from last year’s Planning Resource Auction in a forward auction and PRA simulation.
The two simulations yielded disparate results. A first simulation that used a sloped demand curve produced clearing prices of $1.99/MW-day for MISO South, $1/MW-day for Zone 1 and $222/MW-day for the remainder of MISO North in the prompt auction, and $110/MW-day in the forward auction, which will be limited to retail choice areas. IPL said the PRA demand curve moved to the right during its simulation, noting “cleared FRA resources offered at zero … in the PRA are not a direct offset to the shift in demand curve.”
On a second simulation using a demand curve shaped closer to what Brattle used in its analysis, IPL results produced $210.10/MW-day in the forward auction, and a $2.99/MW-day clearing price in MISO South and a $5/MW-day clearing price in MISO North. (See chart.)
IPL analyst Ted Leffler said the outcomes of the auction are “in line with expectations” even though the forward clearing prices were disproportionately higher than PRA prices.
“Should we be concerned that we’re going to be introducing more volatility? I don’t know. It’s something we need to think about,” Leffler said.
Leffler said IPL used the Zone 4 PRMR as a representation for all competitive zones and didn’t change any offers or capacity import or export limits. The analyses only used the most expensive offers in Zones 1, 2, 8 and 10. For the second analysis, he said, IPL assumed just 78% of Zone 4’s resources were offered in the forward auction, as that was the percentage considered competitive.
Leffler also said the simulations’ use of 2015 PRA results was “imperfect” because it was a “sold-out” auction, with all supply megawatts clearing except for some in Zones 4 and 7.
While a seasonal and locational auction filing is also on hold until the 2018/19 planning year, MISO said it could consider implementing pieces of the locational construct in the 2017/18 planning year. Namely, said Executive Director of Resource Adequacy Renuka Chatterjee, MISO could apply external resources toward local clearing requirements in next year’s auction if the RTO can file with FERC and get approval in time.
South-North Limit
Meanwhile, MISO continues to solicit stakeholder opinion on whether the 876-MW South-North transfer limit should be adjusted in planning for next year’s auction. (See “South-North Transfer Limit in 17/18: Higher or Lower? Firm or Non-Firm?” MISO Resource Adequacy Subcommittee Briefs.)
The RTO brought six days’ worth of 2016 summer data to the RASC to illustrate peak usage on the sub-regional transfer. The data showed North-South flow averaging 2,446 MW on June 17 (with a peak of 2,840 MW) when a maximum generation alert was issued in MISO South, and an average 1,618-MW South-North flow (peak 2,225 MW) on July 22 when Midwest load peaked at 88 GW.
Volpe said the results show that MISO should continue to be “somewhat conservative” for constraints on real-time flows between the regions. Dynegy, which independently examined flows during two peak summer days this year, concluded MISO should continue to subtract firm reservations from the 2,500-MW South-North limit.
Other stakeholders agreed, saying MISO should account for all firm reservations across the interface, as only non-firm reservations could be guaranteed after all firm flows were granted, even if the firm flows weren’t in use.
MISO said of the 10 respondents that provided feedback on the regional transfer limit, seven supported using the maximum 2,500-MW limit as a starting point. Two others opted for a 1,000-MW starting limit. The final stakeholder to provide comment asked for a study of firm-flow reservations before a decision is made.
The RTO is expected to present a draft proposal on the 2017/18 sub-regional limit at the Oct. 5 RASC meeting.
The Omaha Public Power District has notified the Nuclear Regulatory Commission that it will permanently shut down its Fort Calhoun reactor on Oct. 24. The OPPD board unanimously approved a recommended shutdown in June, but officials had not provided a date for when the plant would stop operating, only saying it would by the end of the year.
With the shutdown date set, the plant’s decommissioning will kick into gear. That includes the removal and transfer of nuclear fuel from the reactor into the spent fuel pool, where fuel rods will be placed for about 18 months while they cool to a level that permits transfer into longer-term storage.
The decommissioning process could take up to 60 years and will cost OPPD as much as $1.5 billion. The 43-year-old, 478-MW Fort Calhoun is the smallest nuclear plant in the country, which made it financially untenable to continue operating.
Firm Lands DOE Grant for Flameless Combustion Plant
Southwest Research Institute has received a $3.28 million grant from the Energy Department to develop a project that could eliminate smokestacks and reduce emissions from coal-fired power plants.
The project is described as a “flameless pressurized oxy-combustion plant” by Rep. Joaquin Castro (D-Texas), who announced the grant. The organization also received nearly $900,000 in private industry support for the research.
SwRI, a research and development nonprofit, said the smoke produced from burning coal will be purified in a process that captures carbon dioxide and results in zero emissions. The captured CO2 will be kept out of the atmosphere by injecting it underground.
Energy Department representatives said that retrofitting the Colstrip coal-fired power plant in Montana to reduce greenhouse gas emissions would cost at least $1.2 billion, but that price tag could be partially offset by selling captured carbon dioxide for use in oil fields. Colstrip emitted about 16.5 million tons of CO2 in 2014, two-thirds of the state’s total, according to EPA.
The department presented its analysis of reducing emissions from the Colstrip plant at the request of Montana Gov. Steve Bullock. A Democrat up for re-election in November, Bullock has faced a barrage of Republican criticism for not doing enough to protect the aging plant.
“We need to be saying, what can we do to find solutions?” Bullock said to utility and mining executives gathered at the governor’s office in Helena to hear the Energy Department’s findings. “Those discussions only become more urgent given recent developments at Colstrip.”
FERC Approves Dominion Pipeline Expansion in Md., Va.
FERC has approved an expansion of one of Dominion Transmission’s natural gas pipelines necessary to serve new generating stations in Maryland and in Virginia. Dominion filed to expand the Leidy South Project in May 2015.
The project involves adding compressor stations and other equipment to the pipeline, which crosses Pennsylvania, Maryland and Virginia. Ultimately, it will allow natural gas to be carried to the Panda Stonewall generating station planned for Loudoun County, Va., and the Mattawoman Energy project in Prince George’s County, Md.
Dominion estimates the expansion will cost $209 million.
The Nuclear Regulatory Commission cited FirstEnergy for failing to provide accurate medical information after a nuclear operator at the company’s Davis-Besse plant lied about taking his prescribed medication.
The commission found that the operator, who resigned before the investigation began, failed to notify the plant when he stopped taking medicine for diabetes and high blood pressure. As a result, the commission said, the company unknowingly provided it with inaccurate information.
A FirstEnergy spokesperson said the operator’s failure to take his medication did not impact the plant’s operations. The company has agreed to modify its fitness-for-duty procedures as a result of the incident.
A main transformer fault at the Tennessee Valley Authority’s new Watts Bar 2 nuclear station caused a transformer oil fire and tripped the reactor last week. The incident occurred during testing of the unit before it goes into commercial operation.
TVA had achieved 99% of maximum output during the test before the fire broke out. It completed construction of the plant this year.
The fire was extinguished and there were no injuries. TVA said it is completing a full examination of the incident and the plant before resuming the testing. It said it didn’t know when it would go back online.
The Clean Power Plan poses no threat to PJM’s reliability, but compliance costs are highly sensitive to gas prices and whether states go it alone or combine efforts with a regional approach, according to a study released by the RTO last week.
If gas prices remain low, states within PJM’s footprint are likely to meet EPA-mandated emissions reductions simply through the replacement of coal plants with new combined cycle generators. However, compliance costs could more than triple if states decide to meet their CPP targets individually while also regulating emissions from new sources, the RTO’s analysis concludes.
Issued by EPA in August 2015, the CPP requires PJM’s states to reduce carbon dioxide emissions by 36% from 2005 levels by the year 2030. The analysis, requested by the Organization of PJM States Inc., compared seven compliance “pathways” employing mass- and rate-based trading at regional or state levels. Rate-based plans would mandate that generators meet a pounds-per-megawatt-hour target, while mass-based plans cap state emissions in tons per year.
PJM also looked at several sensitivities, including the impact of retirements on resource owners’ exit decisions based on five- and 20-year horizons. Also modeled were the impact of lower natural gas prices, a multistate split of rate- and mass-based compliance within the PJM region and state renewable portfolio standards.
Regardless of the pathway used, the CPP would not have a substantial impact on resource adequacy as “the capacity and energy markets [will be] able to attract sufficient new investment to satisfy PJM’s reliability requirements,” the RTO said.
Regional Compliance Reduces Costs
The analysis found that levelized compliance costs would range from $0.61/MWh (1.1% of the average total wholesale cost) for regional plans and $1.93/MWh (3.3%) for individual state plans that include regulation of both new and existing sources.
“The cost of compliance for the entire PJM region differs according to the compliance pathway chosen, but regional compliance leads to lower costs than does individual state compliance under both mass-based and rate-based compliance pathways,” the report said.
Regional compliance would result in fewer coal generator retirements and less new combined cycle gas plants than individual state compliance “due to the greater flexibility and options for emissions reductions offered across the entire PJM region,” the study said.
As a reference case, PJM also ran a simulation in which the CPP, which has been stayed by the U.S. Supreme Court pending legal challenges by numerous states, is not implemented. The simulations begin in 2018, thelatest that compliance plans can be submitted if the rule survives.
Impact of Gas Prices
The study found that continued low natural gas prices — assuming they remain in the $3 to $4/MMBtu range (in 2018 dollars) over the 20-year study period — “has a greater effect on emissions levels, the retirement of fossil steam resources and new entry of natural gas combined cycle resources than even the most stringent of the studied compliance pathways that also regulate the CO2 emissions of new natural gas combined cycle resources.”
“Because of accelerated [coal] retirements, there would be no cost to achieve compliance, and the resulting emissions would be below the final Clean Power Plan targets, even without the Clean Power Plan,” PJM said.
Challenges for Nuclear, Boon for Renewables
Compared to the reference and mass-based options, PJM found that rate-based compliance would create lower energy market prices because subsidies for renewable resources would allow them to submit offers below production costs. This would increase capacity prices, however, as resources seek to replace lost energy revenue.
This would drive growth in renewables — which would earn more revenue from emissions rate credits than from the increase in energy market revenues under mass-based compliance — but “results in increased economic challenges for existing nuclear resources,” PJM said.
Mass-based plans, on the other hand, would increase energy market prices by adding costs for allowances. They would allow low-emission resources to depend less on non-market revenue and provide no incentive to price generation below cost. They would also make nuclear facilities more viable by pricing their low-emissions status.
The analysis also evaluated the impact of different time horizons on the nuclear and coal fleets.
If generation owners make retirement decisions based on a five-year horizon from 2018 through 2022 before initial compliance targets take effect, the study predicted up to 6 GW of nuclear retirements (in addition to the already-announced decommissioning of the Oyster Creek nuclear plant) and less than 1 GW of incremental coal-fired retirements. Gas prices would drive the reductions in the short run, but the study found nuclear plants become viable again in 2026 under CPP.
Steam Turbine and Nuclear Units Age 40+, Combined Cycle Units 30+ (As of 2018)
“What the analysis shows is that over a 20-year horizon, the existing nuclear fleet can become economic, but in this near term, they face a lot of stress given the low gas prices and current market prices,” PJM’s Muhsin Abdur-Rahman said during a media briefing on the report Thursday.
The analysis found congestion will decline by 2025 under every compliance pathway compared to the reference scenario. Congestion related to historical west-to-east flows drops because of coal retirements in western PJM, although it is accompanied by more localized congestion.
Energy Efficiency
Rate-based plans would also require precise measurement and verification of energy efficiency to earn emission rate credits. A sensitivity that assumed states can convert only 50% of energy efficiency included in load forecasts into credits resulted in cost increases that were more than double the cost of trade-ready mass-based compliance, although still less than $1.50/MWh.
CAISO’s Board of Governors last week approved proposed Tariff revisions that will require new renewable resources be capable of providing grid-stability services as a condition for interconnecting with the ISO’s system.
CAISO’s Tariff changes will require new and upgraded renewable resources to be capable of providing reactive power and voltage control. Photo of San Gorgonio Pass Wind Farm source: Wikipedia
While stakeholders largely support the amendments, some market participants contend they don’t go far enough in guaranteeing adequate compensation for what has become an increasingly important service as more intermittent resources link up with the grid.
The proposed revisions follow FERC’s June issuance of Order 827, which requires that all newly interconnecting non-synchronous generators have reactive power capability. Resources undergoing upgrades would also be subject to the new rules.
“We are pleased to now take this next step, in which clean power resources can contribute to the reliability of the grid,” CAISO CEO Steve Berberich said in a statement. “By providing reactive power, these resources are better suited to help us integrate increasing numbers of renewable resources.”
“It’s really good utility practice to require all resources in the fleet to have reactive power,” Keith Johnson, CAISO manager of infrastructure policy and contracts, told board members during an Aug. 31 meeting.
The ISO’s Tariff changes go beyond FERC’s mandate for reactive power capability by adding a provision requiring that non-synchronous resources also provide voltage regulation.
“Maintaining voltage is very important for how we operate in the West,” Johnson said, explaining the ISO’s rationale for the additional requirement. “The incremental cost of [automatic voltage regulation] equipment is very, very minimal.”
Thermal Generators Seek Raise
Although the new requirements had broad support among stakeholders, a disagreement arose over CAISO’s decision not to use this FERC filing to alter its compensation for reactive power — a move that would especially benefit thermal generators that are steadily losing market share to renewables.
Under current ISO practice, any generator that is dispatched down to provide reactive power is paid its opportunity cost for lost energy revenues. Generators want the ISO to implement a new market provision that would compensate them for the capital cost of installing reactive power equipment — effectively creating a capacity payment for providing reactive power service.
CAISO contends that generators can recover those costs through their power purchase agreements, given the West’s continued reliance on bilateral contracts for the provision of capacity. Any additional market mechanism would run the risk of creating double payments for the service, Johnson said.
“Providing reactive power is a service essential to the operation of the grid,” said Brian Theaker, director of market affairs at NRG Energy. “Today’s disappointing decision doesn’t advance that.”
Theaker said that the current compensation structure does not provide “reliable signals” for generating units that require longer-term guarantees to remain financially viable.
“We feel like there’s been an opportunity missed here,” said Carrie Bentley, a consultant representing the Western Power Trading Forum. “The ability to provide reactive power is not free,” she continued, adding that five other organized markets offer compensation for the service.
“It’s not a secret that renewable power is disrupting the [capacity] and energy market — a lot of thermal generation will not be able to remain in the market,” Bentley continued. “How do you provide a market signal strong enough to keep the thermal generation we need.”
“The ISO did talk about compensation and looked at some of the other ISOs and RTOs across the country,” Johnson responded. “When PJM or MISO was formed, there were legacy arrangements for capacity payments for reactive power. We have no such system of capacity payments — we have bilateral contracts.”
Keith Casey, CAISO vice president for market and infrastructure development, said Bentley’s concerns about the ISO’s thermal fleet were “spot on.” He pointed out that the ISO’s new flexible ramping product — which compensates generators for the ability to rapidly respond to intermittent output from renewables — is one effort to reward “needed” generators.
“We just view the reactive power capability as a fundamental requirement,” Casey said. “The capital cost for that capability should be addressed through bilateral contracts.”
The Omaha Public Power District has notified the Nuclear Regulatory Commission that it will permanently shut down its Fort Calhoun reactor on Oct. 24. The OPPD board unanimously approved a recommended shutdown in June, but officials had not provided a date for when the plant would stop operating, only saying it would by the end of the year.
Southwest Research Institute has received a $3.28 million grant from the Energy Department to develop a project that could eliminate smokestacks and reduce emissions from coal-fired power plants.
Energy Department representatives said that retrofitting the Colstrip coal-fired power plant in Montana to reduce greenhouse gas emissions would cost at least $1.2 billion, but that price tag could be partially offset by selling captured carbon dioxide for use in oil fields. Colstrip emitted about 16.5 million tons of CO2 in 2014, two-thirds of the state’s total, according to EPA.
FERC has approved an expansion of one of Dominion Transmission’s natural gas pipelines necessary to serve new generating stations in Maryland and in Virginia. Dominion filed to expand the Leidy South Project in May 2015.
The Nuclear Regulatory Commission cited FirstEnergy for failing to provide accurate medical information after a nuclear operator at the company’s Davis-Besse plant lied about taking his prescribed medication.
A main transformer fault at the Tennessee Valley Authority’s new Watts Bar 2 nuclear station caused a transformer oil fire and tripped the reactor last week. The incident occurred during testing of the unit before it goes into commercial operation.
