FOLSOM, Calif. — CAISO’s Board of Governors on Thursday approved new generator contingency modeling, rules extending time for generator interconnections and enhancements to the Western Energy Imbalance Market (EIM).
The board made several unanimous votes and also approved CAISO’s 2018 budget of $197.2 million, which funds ISO operations and salaries based on fees collected from system users. The budget grew by 1% from last year. (See CAISO Seeks Bump in Spending, Revenue Requirement.)
CME Initiative Approved
The board approved a new tool that will allow dispatch of generation to return energy flows to normal levels within a required time frame following the loss of major infrastructure. The contingency modeling enhancements (CME) proposal took years to develop, said Keith Casey, CAISO vice president of infrastructure and market development.
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“This was some four years in the making to bring this to you today,” Casey told the board, which unanimously approved the measure with little discussion.
CAISO developed the CME initiative to address a Western Electricity Coordinating Council reliability provision requiring grid operators to return a critical transmission path to its system operating limit within 30 minutes of a destabilizing event, such as the loss of a generator or transmission line.
The ISO currently dispatches generation to ensure that output does not exceed system limits, but its market model does not consider how to dispatch in a way that returns a line to normal operating limits within the required time. CAISO has been relying on “minimum online commitment constraints” that dispatch generation to meet constraint requirements, but generators are not compensated for the capacity made available to meet contingencies, and exceptional — or out-of-market — dispatch is used to return the transmission system to normal.
The new modeling creates “corrective capacity” in the day-ahead and real-time markets, and resources would be paid for the locational corrective capacity they provide.
Southern California Edison and the Six Cities group of Southern California municipal utilities opposed the change, saying it has limited benefit. SCE said the measure also introduces complexity and makes market prices less transparent. Powerex supported the changes but said it should not be implemented until CAISO overhauls its congestion revenue rights policy. (See CAISO Finalizes Constraint Tool Proposal.)
During the stakeholder process, CAISO removed a provision that would have applied the methodology to lines not subject to the 30-minute restoration time frame, saying it would develop an additional policy in that regard if needed. The ISO also declined a stakeholder suggestion to allow bidding for “corrective capacity” intended to reduce flows across a line within 30 minutes of a contingency, saying the measure would be complex and difficult to mitigate for market power.
New Interconnection Rules
The board also approved a change to CAISO’s generator interconnection policies that will extend the time projects can remain in the queue. The revision is designed to help renewable projects stay financially viable as utility-scale procurement of renewables declines.
“This change will provide additional time to validate and correct interconnection request submittals, which should further streamline the efficiency of the overall interconnection study process,” Casey said in a memo to the board. The change requires approval by FERC.
Many load-serving entities require that generators complete the second phase of the ISO’s interconnection process to qualify for procurement. There is typically about a four-month window between Phase II reports and a transmission deliverability allocation. While projects can currently sit in the queue for a year, there has been a sharp increase in the number of projects unable to secure power purchase agreements before being dropped from the queue.
The new rules extend by a year the “parking” period in the queue, and the ISO also intends to examine its transmission planning deliverability qualification criteria in 2018. (See CAISO Launches Generator Interconnection Effort.)
Governor David Olsen said the proposal is “a good faith effort by the ISO to accommodate the slowdown of project development, especially renewable resources, that we are facing.” But he added “we are under no illusions that taking this step is going to do anything effectively to address the underlying problems behind the effective suspension of procurement.”
That issue, according to Olsen, is rooted in the development of distributed resources and the loss of utility load, “which could very materially affect the ability to develop [utility-scale] renewable resources in the near future. Those are issues that are going to have to be addressed by others.” Olsen said that all parties involved in California policies should ensure that clean energy development can proceed.
The board also approved a set of EIM enhancements that represent a pared-down version of a package proposed earlier this year. The EIM Governing Body in late November approved the package, which automates some manual processes, facilitates bilateral settlements and improves the market’s modeling accuracy. (See EIM Governing Body Approves ‘Consolidated’ Initiatives.)
In executive session, the board also promoted Jodi Ziemathis, the ISO’s executive director of human resources, to vice president of human resources. Chief Financial Officer and Treasurer Ryan Seghesio was also named vice president, while retaining his current titles.
CARMEL, Ind. — MISO last week said it will defer any initiative to account for planned and maintenance outages in capacity planning until it kicks off a broader discussion on overall resource availability sometime next year.
The RTO floated the idea of the initiative last month after observing an increasing number of intentional outages that occurred during periods of peak demand. (See MISO Seeks to Gauge Risk of Peak Season Planned Outages.)
But stakeholders are mixed in their support for accounting for the outages in forecasts for peak periods, MISO Resource Adequacy Coordinator Ryan Westphal said during a Dec. 13 Resource Adequacy Subcommittee meeting.
Instead of accounting for the outages in its mid-2018 capacity planning, MISO now hopes to implement the changes for the 2019/20 planning year. The RTO plans to roll the outage consideration into discussion about its seasonal capacity procurement proposal, which has been rebranded as “resource availability and need,” as planners have increasingly begun to think the answer to capacity issues may not lie in seasonal procurements but in something more granular.
RASC liaison Shawn McFarlane said MISO is now assessing the “hour-by-hour” availability of capacity resources instead of relying on a season-by-season basis of availability. The RTO plans later this month to release a white paper on resource availability trends throughout the year.
“We want to make sure we understand when resources are available, especially in light of the increasing maximum generation events since the 2016/17 planning year,” said MISO analyst Dustin Grethen.
Indianapolis Power and Light’s Ted Leffler noted that MISO once had a Real-Time Sufficiency Task Force that worked on outage-related forecasting issues but ultimately did not come up with a new forecasting process that included planned outages.
“We worked on this for about a year and a half before we gave up,” Leffler said. He urged MISO officials to review the old task force’s documents, if any of them survived.
MISO stakeholders have likewise cooled on defining seasonal capacity procurement requirements.
At an October RASC meeting, some stakeholders questioned the need for seasonal limits, noting that MISO’s emergency conditions in April and September were outside of the summer months, the result of poorly coordinated transmission outages.
NRG Energy’s Tia Elliott suggested that MISO might not need a seasonal definition of capacity at all if it decided to pursue its own transmission project to link its Midwest and South regions. Elliott also expressed exasperation at “being down this dirt road before and ending up in a puddle,” referring to MISO’s two-season capacity market proposal in late 2015 that eventually devolved into the proposal being scrapped to allow the RTO to conduct more research. (See “Seasonal Aspect Back in Conceptual Stage,” MISO Postpones External Zones Until 2019 Auction.)
CARMEL, Ind. — MISO’s market planners last week outlined a potential 30-minute reserve product to reduce uplift and multiday generator commitments to cut production costs. Both concepts are in early planning stages, officials told the Dec. 14 Market Subcommittee meeting.
Engineer Oluwaseyi Akinbode said MISO currently addresses short-term capacity needs using offline resources with quick start-up times and economic generation already online. However, Akinbode said, the approach results in expensive uplift payments.
Akinbode said a short-term capacity reserve would be especially helpful in MISO South, which has less than 500 MW of offline capacity available within 30 minutes. Two southern load pockets — Amite South and the West of the Atchafalaya Basin (WOTAB) — have none and less than 100 MW, respectively.
“We are on track in 2017 to incur about $20 million [in uplift]. Last year, we incurred about $20 million … in day-ahead revenue sufficiency guarantee to manage load pockets,” Akinbode said.
Making the price of the reliability service transparent may cause some generation owners to defer plant retirements and others to develop new fast-start resources, said Jeff Bladen, MISO executive director of market design.
“What we want to make sure is that generators have the best economic signal, and they judge for themselves,” Bladen said.
Northern Indiana Public Service Co.’s Bill SeDoris said that with only some localized parts of the footprint needing the capacity product, he saw a possibility that only generation with access to certain load pockets would be able to benefit financially. “That may raise concerns,” he said.
Bladen said that while MISO doesn’t yet have systemwide need for the short-term product, conditions will change with the increased adoption of intermittent resources. He pointed out that MISO doesn’t expect to have a short-term product ready for use until 2020, when the footprint’s resource mix will have further shifted toward renewables.
“We expect this to be needed systemwide … and by the time we’re fully utilizing it, we expect the need for a 30-minute product to be much more prevalent systemwide. We do see this as a need systemwide even though the short-term value proposition is localized,” Bladen said.
MidAmerican Energy’s Greg Schaefer asked under what conditions a 30-minute dispatch would be valuable.
Akinbode said the option would help eliminate out-of-market commitments that cause MISO to incur uplift payments.
Bladen said the product was needed because MISO’s forecasting of anticipated wind supply is less accurate beyond 30 minutes from dispatch.
“It’s a far less costly way to manage operations until we get to that 30-mintue window where we get a clearer picture of what to expect out of resources like wind,” Bladen said.
SeDoris asked if MISO designers were thinking about creating penalties for units that commit to offer the short-term capacity but don’t deliver.
“There are a lot of details we’re going to have to work through,” Akinbode agreed.
Werner Roth, an economist with the Public Utility Commission of Texas, thanked MISO for its work. “This is something we’ve been asking for a long time,” he said.
Multiday Market
MISO also is considering the use of a screening tool to make recommendations for turning generators with long lead times on and off seven days in advance. The RTO estimates implementation sometime in 2019. (See MISO Exploring Multiday Market.)
“The savings of a multiday optimization window are substantial,” Senior Market Engineer Chuck Hansen said.
Hansen said MISO identified the best candidates for multiday commitments using three criteria: long lead times, high start-up costs and the ability to respond. The RTO then developed a screening tool that estimates potential cost reductions by examining units individually.
“Some units have high emissions upon start-up and sometimes they can only start once or twice per month to avoid going over their emissions” limits, Hansen said.
He said MISO began researching with a multiday candidate list of 85 generators and later increased the number to 113 of the 1,200 units in the footprint after staff spoke with members and the Independent Market Monitor.
Using the 113 candidate generators, Hansen said MISO estimated that the multiday screening tool could reduce production costs by $157.3 million and output by 2,658 MW annually. Hansen said some of the savings were attributable to passing commitments to more nimble and economic units. But he cautioned that costs avoided using a multiday market won’t likely be as dramatic as the study suggests because it couldn’t account for unanticipated weather, unforeseen outages and increased renewable penetration. MISO estimates an achievable savings of between $29 million and $44 million per year, Hansen said.
“Some of this relies on [long-term] forecasts we don’t yet have,” he added.
Some stakeholders said that MISO estimating even a 10 to 15% share of the study’s savings would overstate the benefits.
Customized Energy Solutions’ Ted Kuhn said the multiday commitments could actually increase costs should MISO produce a wildly inaccurate seven-day forecast.
“With this, I just see more make-whole payments,” added Kuhn’s colleague David Sapper.
Bladen added that the screening tool merely suggests commitments to operators, and it’s up to operators to decide whether to act on those. MISO and stakeholders have yet to decide if the tool’s recommended commitment changes will come attached with make-whole payments and other market rules should operators decide to take its advice.
“What the tool is doing is simulating what the participant might change when they self-commit. The screening tool is not dispatch instructions. This is not a new kind of dispatch tool that we’re trying out,” Bladen said.
For financially binding commitments, MISO would have to create a multiday pricing forecast that the RTO would have confidence in, Hansen said.
When a generator decides to decommit, Hansen said, the lost generation will be replaced with new generation with the LMP at the hour, with the idea being to turn off more expensive generation and replace it with the system LMP.
In September, MISO Director Thomas Rainwater said that should MISO move to multiday financial commitments, “we have to make sure natural gas generation is in lockstep with pipeline commitments.”
AUSTIN, Texas — The ERCOT Board of Directors last week unanimously approved a $246.7 million transmission project to address growing energy needs along the Texas Gulf Coast.
Freeport is a highly industrialized region with several large chemical facilities and a major seaport. ERCOT projects that by 2019, the Freeport area’s load will increase 92% to 1,979 MW, with much of that growth coming from a large chemical plant. An additional 300 MW is expected by the end of 2022.
“We continue to see growing demand for electricity in the ERCOT region, especially in areas affected by industrial growth and oil and gas activity,” said ERCOT Senior Manager of Transmission Planning Jeff Billo.
The ISO’s independent review of the project confirmed its necessity. Staff analyzed five options and proposed the most cost-effective to support future electric needs in the area.
CenterPoint Energy, which services the area, suggested a two-phase approach to solve reliability criteria violations caused by the increased load. A $32.3 million first phase, or “bridge-the-gap upgrades,” focuses on near-term reliability needs with a 345-kV loop and a series of reactors, autotransformers and capacitor banks at a key substation.
The $214.4 million second phase comprises a new 48-mile, 345-kV double-circuit line and circuit upgrades to another 345-kV line.
Any projects approved by ERCOT that cost $50 million or more are classified as Tier 1 initiatives and require board approval.
The project must also be approved by the Public Utility Commission of Texas. Work is expected to be completed by 2022.
The board approved two nodal protocol revision requests (NPRRs) recently taken off the table by the TAC, but with varying degrees of opposition.
Brazos Electric Power Cooperative’s Clifton Karnei, representing the cooperative segment, cast the lone dissenting vote against NPRR815. The change increases from 50% to 60% the limit on load resources providing responsive reserve service (RRS), with at least 1,150 MW coming from resources that can provide primary frequency response.
The Protocol Revisions Subcommittee said changing the constraint will allow additional resources to provide RRS at lower costs. However, the Lower Colorado River Authority’s John Dumas, who opposed the measure when it passed the TAC last month, told the board that NPRR815 could harm reliability because of the reduction in generation resources that provide inertia and voltage support. (See “TAC ‘Un-Tables,’ Endorses NPRRs,” ERCOT Technical Advisory Committee Briefs.)
“Our opposition has to do with concerns over reliability risk and commercial risk,” Dumas said. “When you increase the amount of load in responsive reserves, you’re decreasing the amount of potential generation on the grid to manage things like voltage, inertia and ramping capabilities. When you take generation off the grid, you’re reducing reliability, you’re not improving reliability.”
Dumas said the commercial risk comes from a possible increase in RRS price spikes during high-wind, low-load situations.
“You can commit enough capacity to cover your energy position, but you cannot … when you suddenly have a wind variation or a unit trip,” he said. “When you reduce the amount of supply from generation, you’re reducing the offer curve.”
Woody Rickerson, ERCOT’s vice president of grid planning and operations, pushed back on the reliability concerns.
“[NPRR]815 in no way changes what we need for responsive reserves, only how we procure it,” he said. “We’ve gone through probably six months of questions on it. We’ve studied it, and it in no way endangers reliability.”
Rickerson pointed out ERCOT monitors inertia separately from responsive reserves, and that the ISO can always procure more services beyond the minimum amount.
NPRR825 also cleared the board, but with four votes in opposition from cooperative and consumer interests. The revision requires ERCOT to issue a DC tie curtailment notice before curtailing the tie’s load, addressing the ISO’s concerns about declaring an emergency condition before curtailing DC tie load for any reason, staff said.
Several directors were concerned about the NPRR’s price tag — $200,000 to $300,000 in development costs as part of a larger software tool — but staff said the change would result in automated processes and system reports. Rickerson told directors that the day before, staff had to issue a watch to curtail 27 MW.
“It’s increasing transparency in the marketplace,” said unaffiliated director Karl Pfirrmann, speaking in favor of the NPRR. “That should make things more efficient and helps prepare us for emergency situations.”
ERCOT CEO Bill Magness said the ISO is projecting to end the year nearly $8 million under budget following a warmer-than-normal October.
“Revenues go up, but so does congestion,” he told the board.
A positive variance in October for ERCOT’s system administration fee helped reduce an unfavorable year-end projection to about $100,000. Much of the overall positive variance stems from $4.1 million savings in interest expense because of project funding and minimal revolver usage, and interest income because of higher rates.
Magness said staff has completed their reliability-must-run studies of planned generator retirements and determined none of the units needs to be kept on for reliability needs. He also said the Texas grid is seeing higher-than-expected congestion in the day-ahead market, but that congestion revenue rights funding is not a concern.
IMM: Ancillary Services Market Growing in Importance
Beth Garza, director of the Independent Market Monitor, focused her board report on ancillary services, which have declined with the advent of the nodal market in 2011.
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Garza said the services cost $1.03/MWh in 2016 and averaged 87 cents/MWh through Oct. 7, but that is likely to change with the pending retirement of more than 2 GW of aging generation (though those units only have provided 2.5% of regulation up and 6.4% of regulation down in 2017 through October). Regulation up and down have seen the biggest decrease since the zonal market was replaced, with dispatch now occurring every five minutes instead of 15.
“It’s that efficiency of procuring on smaller time frames, and not over-procuring, that has brought the overall average down,” Garza said. “These things we call ancillary will become more important in a future market that has more load to zero-cost variable resources. As the [ancillary services market] becomes more important and [resources] scarcer, as less units are around to provide those services, those prices are likely to become higher and more important going forward.”
Asked if she was comfortable with ERCOT’s ancillary market performance, Garza said the interaction between regulation and security-constrained economic dispatch “continues to be refined,” but she noted total regulation has seen about a two-thirds reduction from the 1,800 MW in the zonal market.
“That balance seems pretty good,” she said.
The Monitor is projecting ERCOT’s real-time prices will be above last year’s record low average of $24.62/MWh. Through the first 10 months of 2017, prices are up 17% to $28.97/MWh compared to the same period last year. Real-time prices settled at $24.
| Potomac Economics
Gas prices averaged $2.44/MMBtu last year but were $3/MMBtu for the first 10 months of 2017.
Membership Approves 5 New Directors
ERCOT’s corporate members approved the election of Terry J. Bulger and the re-election of Peter Cramton to three-year terms during their annual membership meeting. Cramton’s current term will expire on Aug. 1.
Bulger is a 35-year banking professional with ABN AMRO and Bank of Montreal, and has more than 25 years of experience in risk management. Cramton is an economics professor at the University of Maryland and the University of Cologne.
Members also approved four new segment directors, who were previously segment alternates, and their alternates, to serve in 2018. The directors are:
Industrial consumers — Sam Harper, Chaparral Steel Midlothian
Independent generators — Kevin Gresham, E.ON Climate & Renewables North America
Independent retail electric providers — Rick Bluntzer, Just Energy Texas
Investor-owned utilities — Kenneth Mercado, CenterPoint Energy
The new segment alternates are:
Industrial consumers — Mark Schwirtz, Golden Spread Electric Cooperative
Independent generators — Amanda Frazier, Luminant
Independent retail electric providers — Mohsin Hassan, VEH
Investor-owned utilities — Mark Carpenter, Oncor
TAC Gets 6 New Members
The membership also approved six new members to the TAC, which makes recommendations to the board and is aided by five subcommittees:
Independent generators — Ian Haley, Luminant
Independent power marketers — Kevin Bunch, EDF Energy Services, and former ERCOT staffer Resmi Surendran, Shell Energy North America
Independent retail electric providers — Sandra Morris, Direct Energy
Investor-owned utilities — Walter Bartel, CenterPoint
Municipals — John Bonnin, CPS Energy
Board Clears 4 NPRRs, Other Measures
The board unanimously approved revisions to the methodology for computing responsive reserves as a result of NPRR815’s implementation, and two changes to determining non-spinning reserves in 2018; associated with NPRR815 and two changes to determining non-spinning reserves in 2018; accepted a clean system and organization control audit; and approved new key performance indicators.
The directors also unanimously approved NPRR846 by itself, and three other NPRRs on the consent agenda.
NPRR846: Allows previously committed emergency response service (ERS) resources to participate in must-run alternative agreements and modifies the methodology for evaluating the impact of ERS load performance during the first partial interval on calculating the alternate baseline. The change also defines acceptable parameters for an ERS generator’s self-serve capacity, and sets the ERS test performance factor to significantly lower values, in some instances to zero for resources with three consecutive test failures within a 365-day period. The NPRR includes additional administrative changes and clarifications to existing ERS protocol language.
NPRR834: Clarifies processes associated with ERCOT’s repossession of congestion revenue rights following a payment breach or other default by a market participant. The change specifies data transparency requirements; documents the disposition of auction revenue funds above amounts owed to ERCOT; clarifies that the one-time auction bids must be positive; and allows the immediate transfer of CRR ownership to the winning bidder should an auction be necessary.
NPRR839: Updates the protocols to clarify that, upon receiving meter data transactions from transmission or distribution service providers, ERCOT will forward the transactions to the designated competitive retailer.
NPRR843: Addresses four reporting items in Section 3 of the Nodal Protocols (Management Activities) by:
Changing the logic of short-term system adequacy reports for more consistent treatment of resource status; adding language to provide clarity to the reports’ end users;
Creating a new report that will show the portion of ancillary service offers at or above 50 times the fuel index price (FIP) when the market-clearing price for capacity of the service exceeds 50 times FIP;
Adding elements to the “48-hour highest price [ancillary service] offer selected” report, including the highest-priced offer selected in a supplemental ancillary service market (SASM); and
Creating a SASM disclosure report to provide transparency into ancillary service offers and awards for any SASMs executed within an operating day.
The costs of maintaining DC ties to allow SPP’s merger with the Mountain West Transmission Group should be allocated based on benefits, Texas Public Utility Commission Chair DeAnn Walker said last week.
Walker | PUC of Texas
In brief comments during the PUC’s Dec. 14 open meeting, Walker, who serves on SPP’s Regional State Committee, updated Commissioners Brandy Marty Marquez and Arthur D’Andrea on the “very interesting debate” taking place as Mountain West pursues SPP membership. (See SPP, Mountain West Integration Work Goes Public.)
The benefits touted by the two entities come in part from using the four DC interties that separate them to schedule power as a part of the SPP market. The four ties have a combined transfer capability of 720 MW.
“I [told SPP] yesterday that Texas believes that whatever [maintenance] costs are related to those DC ties or future ones … be done on a cost-benefit ratio,” Walker said.
Mountain West has proposed those and any future costs be allocated on a load-ratio share, as part of its recommendation for a Westside Transmission Owners Committee.
Hartburg-Sabine Delay
Walker also briefed the commissioners on the MISO Board of Directors’ recent decision to postpone approval of the $130 million Hartburg-Sabine 500-kV market efficiency project in eastern Texas for two months because of a late cost-allocation change. (See “Texas Project Delay,” MISO Board Approves $2.6B Transmission Spending Package.)
The Texas regulators last month asked MISO to create separate zones for it and Louisiana to allow more granular cost allocation. The Louisiana Public Service Commission filed a similar request with the RTO. (See “PUC to Ask MISO to Create Texas Local Resource Zone,” PUCT Open Meeting Briefs: Nov. 17, 2017.)
Packed House at the PUCT on December 14th | PUC of Texas
“We have assurances [MISO] will come back after FERC rules on the cost issues,” Walker said. “They’ve made statements they fully support the project.”
With the delay, Walker will hand off her MISO liaison duties to D’Andrea. She had temporarily inherited the responsibilities when Ken Anderson stepped down from the commission in November.
Fending off FERC
Walker said she is continuing to work with the Texas governor’s office and ERCOT on a “potential solution” addressing her concerns that transmission projects along the U.S. border with Mexico may threaten the ISO’s electrical separation from the rest of the country and the PUC’s exclusive jurisdiction over the Texas grid operator. (See Regulators Fear Cross-Border Tx Risks ERCOT’s FERC Exemption.)
PUCT Commissioners left to right: Brandy Marty Marquez, Chair DeAnn Walker, Arthur D’Andrea | PUC of Texas
“I don’t want to talk publicly at this point, because it is a litigation strategy,” she said.
Walker did say ERCOT staff has told her they could develop protocol language that makes it clear the ISO has authority to deny an e-Tag “or go so far as disconnect [its] system” from HVDC connections. The protocol change could be ready in time for ERCOT’s February Board of Directors meeting.
“Hopefully it’s a protocol that won’t have to be used,” Walker said.
ERCOT has several synchronous (AC) and asynchronous (DC) ties with the Mexican grid. Texas regulators are concerned comingled electricity flows from border projects in California and Arizona could lead FERC to claim jurisdiction through the U.S. Constitution’s Commerce Clause.
“These are drastic measures we’re talking about,” Marquez told Walker. “These are huge market disruptors, but they are a last line of defense, so I think it’s important we do it. We’ll continue to seek other solutions as well.”
Three solar advocates last week filed a joint challenge to the Montana Public Service Commission’s decision to alter the contract terms available to small generators under the Public Utility Regulatory Policies Act.
Solar farm | Cypress Creek Renewables
In a state district court complaint filed Dec. 13, Vote Solar, the Montana Environmental Information Center and solar developer Cypress Creek Renewables argue that Montana regulators “drastically and unreasonably” reduced the standard contract length and energy rate available to small renewable energy projects under PURPA. The commission last month reduced the contract length from 25 years to 15 years and cut the rates utilities must pay renewable projects up to 3 MW from $66/MWh to $31/MWh.
The PSC defended the decision as protecting ratepayers from overpaying for electricity produced by independent generators. NorthWestern Energy initially asked the commission for PURPA rate relief in May 2016.
The complaint characterizes the PSC’s decision as a “death knell for small solar development in Montana at a time when demand for renewable energy is growing, the cost of producing renewable energy is at an all-time low and NorthWestern has claimed a significant need for electric capacity that solar and wind developers are well-positioned to supply.”
The solar advocates say the decision resulted in dozens of solar projects across the state being put on hold. They argue it’s doubtful Montana will see solar expansion “in the foreseeable future” if the commission’s order stands. Cypress said it has delayed four prospective solar projects in Cascade County, where the challenge was filed.
“As a result, the state will lose hundreds of millions of dollars of economic investment, hundreds of construction jobs, affordable clean electricity and significant tax revenues for local governments,” the three organizations said in a statement. They asked the court to find the PSC’s order unreasonable and unlawful.
In June, Montana Commissioner Bob Lake was heard on a microphone appearing to confirm that state regulators put the rules in place knowing that they would stifle development of small solar projects. (See ‘Hot Mic’ Reveals Montana Move Against Solar QFs.) FERC earlier this year declined to enforce PURPA action against the Montana PSC.
PURPA requires utilities to pay qualifying facilities the cost a utility would incur for supplying the power itself or by obtaining supplies from another source. The law leaves it to each state’s utility commission to formulate those rates and set contract terms, depending on project size.
Adam Browning, executive director of Vote Solar, said competitive rates and longer contract lengths are needed to avoid utility monopolies.
“Now that solar is cost-competitive, fossil fuel interests in Montana and across the country are attempting to change the rules of the game. Fair treatment for solar opportunity will benefit Montana’s families, economy and environment,” Browning said.
Cypress Director of Market Development Casey May said the complaint is an attempt for a fair chance at competition for independent power producers. “Plainly put, we want to do business in Montana,” May said. “We want to increase Montanans’ access to clean energy, create jobs and increase the tax base of state and local governments, but this decision prevents that. … It’s a bad deal for Montanans and economic development across the state.”
TransAlta Scraps Wind Farm After PSC Ruling
In a related development, TransAlta said it won’t build the New Colony Wind Project because of a Dec. 12 PSC ruling that said NorthWestern should pay the wind farm $23.20/MWh over 15 years on a PURPA contract.
TransAlta had asked to be paid $43.63/MWh over 25 years. Northwestern had proposed paying $13.96/MWh.
The U.S. Supreme Court last week denied DTE Energy’s petition to review an environmental penalty against one of its Michigan coal plants over increased emissions, but the new tone set by the head of EPA will likely diminish the court’s action.
The court on Tuesday declined to hear the Michigan-based utility’s defense of upgrades it performed on its coal-fired Monroe power plant, clearing the way for EPA enforcement action. (See DTE Initiates Last-Ditch Effort in Clean Air Act Case.)
DTE Energy’s Monroe Power Plant | Port of Monroe
However, the agency has performed an about-face under in the intervening months since DTE filed a writ of certiorari with the court. Administrator Scott Pruitt earlier this month released a policy memo specifically citing DTE’s case and adopting some of its arguments against having to pay penalties for excessive air pollution, making it unlikely the agency will pursue penalties.
EPA and the Sierra Club have pursued enforcement against DTE since 2010, when the company started a $65 million upgrade to Unit 2 of the 46-year-old Monroe coal plant without installing additional pollution controls. They contended the upgrade violated the Clean Air Act’s New Source Review (NSR) program because DTE ignored its own projections that the renovation would cause emissions to increase by thousands of tons per year. EPA called the project a major overhaul that should have included new pollution controls and sought civil penalties of up to $37,500 per day.
DTE maintained that the higher emissions from the Monroe plant were a product of demand growth and not caused by the improvements. By 2014, DTE had installed four selective catalytic reduction units and four flue gas desulfurization units at the plant at a cost of about $2 billion.
“It is pretty simple. DTE chose to overhaul their dirty coal plant and not install modern pollution control technology at that time even though their own projection showed that pollution would increase after the overhaul,” said Regina Strong, director of the Sierra Club’s Beyond Coal Campaign in Michigan.
DTE contended that enforcement action could not proceed until after an actual pollution increase occurred, an argument that the 6th U.S. Circuit Court of Appeals twice rejected (14-2274, 14-2275).
However, Pruitt’s memo aligns with DTE’s arguments, saying that EPA will no longer bring NSR enforcement against generators until they’ve had the chance to increase pollution, contradicting the preventative nature of the NSR that the 6th Circuit recognized.
Pruitt wrote that EPA does not “presently intend to initiate enforcement … unless post-project actual emissions data indicate that a significant emissions increase … did in fact occur.”
According to the Sierra Club, EPA will now “no longer seek to challenge even obviously faulty or fraudulent projections by a utility that a proposed modification to a coal plant will purportedly not lead to a New Source Review-triggering emissions increase so long as such projection was procedurally done properly.”
“The new Pruitt approach appears to be little more than an attempt to give coal utilities a sense of empowerment to ignore the critical public health protections of the Clean Air Act New Source Review program,” Shannon Fisk, managing attorney with environmental law firm Earthjustice, said in a statement. “Such [an] approach should not stand as it is contrary to law, public health and common sense.”
CARMEL, Ind. — MISO is moving ahead with developing an automatic generation control (AGC) program designed to rapidly deploy 400 MW of fast-ramping resources by regulating either up or down in response to fluctuations in load.
Speaking during a Dec. 14 Market Subcommittee meeting, Pavan Addepalle of MISO’s market engineering group said the RTO is moving from a conceptual design phase to detailed design with a vendor. MISO hopes to implement AGC by late 2019.
Addepalle said MISO will add new real-time market hourly offer parameters to accommodate the faster units but use the RTO’s existing market and settlement rules to clear regulation. Resources must have a minimum 80-MW/minute ramp rate and a regulation limit of 1 MW or more to be eligible to participate in the program.
In response to a question from Northern Indiana Public Service Co.’s Bill SeDoris, MISO staff said resources under AGC will be cleared in the same market as other resources, but that fast- and slow-responding resources will be divided into pools waiting on separate dispatch signals.
“We’re going to have a single energy market but realize that resources have different parameters and constraints … and design a market that is capable of using separate resources differently,” said MISO Executive Director of Market Design Jeff Bladen, adding that the RTO will not follow in PJM’s footsteps in creating a separate regulation market.
ITC Holdings’ Ray Kershaw said the new designation, while amenable for pumped energy storage, is not an ideal use for batteries.
Addepalle said MISO did not approach the proposal with a specific type of generation in mind.
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability Committee on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:40)
Members will be asked to endorse the following proposed manual changes:
A. Manual 1: Control Center and Data Exchange Requirements. Revisions developed to update NERC references and procedures related to outages and system-restoration planning. PJM members will be required to send the RTO data on transmission megawatt and MVAR flows and bus voltages at greater than or equal to 100 kV, down from 345 kV.
B. Manual 10: Pre-Scheduling Operations. Revisions developed to comply with NERC standards as part of a periodic review of the manual. Generators will be required to notify PJM of operating conditions that could result in a single contingency causing an outage of multiple generators.
C. Manual 14D: Generator Operational Requirements. Revisions developed as part of a periodic review. Generators will need to be modeled in eDART consistent with the PJM energy management system model.
3. Manuals 3 and 13 Revisions and Gas Pipeline Contingencies (9:40-10:10)
A. Members will be asked to endorse proposed changes to Manual 3: Transmission Operations and Manual 13: Emergency Operations, which include processes for addressing gas pipeline disruptions that affect generator reliability.
B. Members will also be asked to endorse manual revisions proposed by gas-fired generators to document compensation mechanisms for generators directed by PJM to take action related to a pipeline contingency. (See related story, “Gas Generators Block PJM Pipeline Plan,” PJM OC briefs: Dec. 12, 2017.)
Members will be asked to endorse revisions to the Tariff, Manual 28: Operating Agreement Accounting and Manual 6: Financial Transmission Rights resulting from special sessions on FTR issues. The revisions will address changes to long-term FTR modeling for future transmission expansion, streamlining management of overlapping FTR auctions and allocating any surplus funds from day-ahead congestion and FTR auction revenue. (See related story, “FTR Discussions,” PJM MIC briefs: Dec. 13, 2017.)
5. New Service Request Study Methods (10:40-11:00)
Members will be asked to endorse changes to the procedures for the study of transmission service requests and upgrade requests in the new services queue process. (See “Interconnection Study Process to be Rearranged,” PJM Planning/TEAC Briefs Oct. 12, 2017.)
6. Energy Market Price Formation Problem Statement & Issue Charge (11:00-12:00)
Members will be asked to endorse PJM’s proposed problem statement and issue charge to changes price formation in the energy market. The RTO has proposed revisions that would allow inflexible units to set LMPs. The Independent Market Monitor has proposed an alternative problem statement and issue charge that would take up to two years to examine all components of energy market price formation and determine if changes are needed. (See “Questions Remain as PJM Continues Push for Price Formation Revisions,” PJM Markets and Reliability/Members Committees Briefs: Dec. 7, 2017.)
7. Capacity Construct/Public Policy Senior Task Force (CCPPSTF) (12:45-1:45)
Members will be asked to endorse Tariff revisions associated with the Monitor’s “MOPR-Ex” proposal to change the minimum offer price rule. The Monitor is proposing to amend the version endorsed by the Capacity Construct/Public Policy Senior Task Force to revise exemptions for state renewable portfolio standards. (See related story, IMM Battles Exelon on MOPR-Ex Proposal.)
8. Incremental Auction Senior Task Force (IASTF) (1:45-2:00)
Members will be asked to endorse a proposal developed by the Incremental Auction Senior Task Force to address concerns of excess capacity and low clearing prices. Although Proposal A” did not receive enough support at the IASTF to be automatically considered at the MRC, stakeholders moved for an endorsement vote. (See “Stakeholders Move Incremental Auction Proposal,” PJM Markets and Reliability/Members Committees Briefs: Dec. 7, 2017.)
FERC last week set hearing and settlement proceedings for a new Ohio merchant plant, saying it had not provided sufficient backing for its reactive power revenue requirement (ER18-92, EL18-32).
The 747-MW Carroll County Energy combined cycle plant, expected to go in service this month, is seeking compensation for its generator, associated exciter equipment, step-up transformers and other equipment under allocation factors representing their contribution to both reactive service and real power.
Carroll County Energy Plant Schematic | Power Technology
The commission said the plant’s owners had not demonstrated that its proposed revenue requirement was just and reasonable. “CCE’s filing has no underlying support for the costs claimed for this new generation facility, and the balance of plant investment allocator and the accessory electrical equipment allocator may be excessive. We further note that the components of the accessory electrical equipment are not provided,” the commission wrote.
FERC said that, if no settlement is reached, it expects to issue a decision within eight months of the filing of briefs opposing exceptions to the initial decision by an administrative law judge. “If the presiding judge were to issue an initial decision by July 31, 2018, we expect that, if the proceeding does not settle, we would be able to render a decision by May 31, 2019.”
The plant’s owners include TIAA, Chubu Electric Power, Ullico, Prudential Financial and Advanced Power, a Boston-based development company that oversaw construction and will manage the start of commercial operations. Chairman Kevin McIntyre did not participate in the decision.
