Amid unusual silence from energy storage advocates who previously complained about slow action on the issue by the grid operator, the Federal Energy Regulatory Commission has approved tariff changes by the Midcontinent Independent System Operator to fully open its markets to storage operators, but granted MISO’s request to delay implementation until June 2022.
MISO’s request to push back implementation of the new storage rules for 31 months went unopposed by the Energy Storage Association (ESA), battery owner Indianapolis Power & Light (IPL) and other storage advocates who for years have slammed the grid operator for dragging its feet on tariff changes to help storage participate in its energy, ancillary services and capacity markets.
ESA and IPL did not respond Tuesday to requests for comment on their apparent acquiescence to the long delay sought by MISO to implement the new rules.
IPL was among the first to formally demand changes to MISO’s market rules to better accommodate storage, saying it had spent years in fruitless discussions with the grid operator. The AES subsidiary filed an October 2016 complaint at FERC seeking an order directing MISO to make tariff fixes to enable a new 20 megawatt battery storage facility built by the utility to provide primary frequency response and other support services to the grid operator’s 15-state system.
That complaint eventually led FERC to issue its landmark Order 841 in early 2018, which directed regional grid operators to promptly craft new storage-friendly market rules, a move that the fledgling storage industry said was vital to increasing revenues.
It is unclear why storage advocates did not protest the long delay granted to MISO for implementation of its new rules, although it could indicate that battery developers do not expect the MISO changes to help them much until their systems become more cost-competitive.
For its part, FERC accepted MISO’s contention that the deferred implementation of its energy storage resources participation model “is expected to have limited impacts on the ability of storage-type resources to participate in MISO’s markets” because the storage facilities already can do so under existing rules.
FERC approved the MISO tariff changes November 21 along with Order 841 compliance filings made by the California Independent System Operator (CAISO) and ISO-New England. The commission ordered all three of the grid operators to rework a few elements of their tariff changes, but none of the issues involved appeared major.
Similarly, FERC in October accepted most of the rule changes proposed by PJM Interconnection and the Southwest Power Pool, although the PJM changes were more controversial.
Order 841 directed FERC-regulated regional transmission organizations and independent system operators (RTO/ISO) to rewrite their market rules to allow storage resources to participate in all energy, capacity and ancillary services markets in which they are capable of providing service, regardless of whether they are located on transmission or distribution systems or behind-the-meter.
The order recognized that many market rules were written decades ago with traditional generation resources in mind and did not take into account the unique physical and operational characteristics of storage resources that can act as both load—such as when batteries draw power from the grid to recharge—and generation, when they are tapped by grid operators to inject energy into bulk power systems.
The RTO/ISOs filed their tariff changes in response to Order 841 earlier this year, and since then storage developers have been eagerly awaiting FERC action, including orders that were expected to direct implementation of the new rules by the end of 2019.
FERC Chairman Neil Chatterjee has said repeatedly that implementation of the new storage rules are one of his top priorities, while the ESA has said the new rules under Order 841 would be a “game-changer” that will clear hurdles to wider deployment of batteries and other storage technologies seen as a key to supporting rising amounts of intermittent wind and solar resources on the grid.
However, the years-long delay in MISO’s implementation of its new rules—and the lack of complaints from energy storage advocates—may reflect widespread acknowledgment of tepid market interest in new storage resources in MISO at present.
Other than IPL’s battery facility, which is designed to control frequency at a specific location, there currently is no battery storage capacity deployed in MISO markets, although the grid operator has 52 proposals for storage in its interconnection queue that together would total 2,600 MW of storage.
The impact of the new rules also may be fairly muted in ISO-New England and CAISO, which indicated in their compliance filings that they already had rewritten most of their rules to allow for full participation of storage facilities to meet the standards laid out in Order 841.
More broadly, some market observers have questioned whether new storage systems can be commercially viable in many markets regardless of the FERC rule changes. PJM Interconnection’s independent market monitor has said the high capital costs make them generally uneconomic in that market outside of limited frequency regulation applications, while CAISO last month noted continuing economic challenges of utility-scale storage systems.
“Many storage technologies, including lithium-ion batteries, still largely remain capital-intensive—and difficult to realize as utility-scale projects on volatile spot prices alone,” CAISO wrote in a joint report with European grid operators on the prospects for storage.
Given those market realities, MISO said its proposed changes under Order 841 were unlikely to have much impact on storage deployment relative to the rules it already has in place.
“The requested deferred implementation of the energy storage resources participation model is expected to have limited impacts on the ability of storage-type resources to participate in MISO’s markets,” the grid operator wrote in its request for delayed implementation.
“While MISO recognizes there are storage-type resources in MISO’s current generation interconnection queue, it maintains that any storage-type resources that emerge from the interconnection queue and actually enter into service before June 2022 can participate in MISO’s [current] markets as Stored Energy Resources—Type II.”
MISO said it needed the long delay because it is making other significant changes to its market operations, and that the complex software and other changes necessary to implement the new storage rules would have to wait until those other projects are completed.
Along with approval of the delay, FERC accepted almost all of MISO’s proposed changes to comply with Order 841.
FERC did order MISO to rework provisions about metering and accounting practices for storage systems connected to distribution systems or behind-the-meter. It also rejected MISO’s proposal to limit the number of very small storage resources that may interconnect to its grid, and it ordered MISO to better explain why storage resources should not be considered “fast start” resources, according to the order.
Ruling on perhaps the most controversial issue, FERC rejected a request by Michigan’s two biggest power distribution utilities, DTE Energy and Consumers Energy, that states be allowed to decide whether storage resources located behind-the-meter or on the distribution system are permitted to participate in the RTO/ISO wholesale markets. Distribution utilities and states have enough visibility into operations to ensure reliability, FERC wrote.
FERC Commissioner Bernard McNamee concurred in the approval of the storage changes, but reiterated his view that states should have the ability to opt out of allowing storage resources connected to distribution systems to participate in the FERC-regulated markets—a position that storage advocates argue would gut the intent of Order 841.
In its orders on ISO-New England’s and CAISO’s filings, FERC accepted nearly all of the provisions but ordered the grid operators to better address metering and accounting for storage facilities connected to distribution networks. The commission also ordered changes to some of CAISO’s and ISO-New England’s bidding parameters, among other technical changes.
© 2019 IHS Markit®. All rights reserved.
A North Dakota rural electric cooperative is quietly advancing an ambitious $1 billion carbon capture and storage project at a coal-fired power plant that promises to be an early test of whether increased federal tax credits recently approved by Congress for carbon sequestration can overcome the financial obstacles that generally have blocked such costly clean coal efforts to date.
Minnkota Power Cooperative, which serves 135,000 customers in eastern North Dakota and northwestern Minnesota, recently received a $9.8 million grant from the Energy Department and $15 million from North Dakota to help fund the final engineering study for Project Tundra, which would deploy conventional post-combustion technology to capture carbon dioxide (CO2) from the stack of the co-op’s Milton R. Young Generating Station, a decades-old 705 megawatt coal-fired plant near Hensler, N.D.
The carbon capture, storage and utilization (CCUS) project has been planned since 2014 and, if built, would become only the second utility-scale CCUS project at a U.S. coal plant, after NRG Energy’s operating CCUS system at its Petra Nova power plant in Texas.
However, while the Petra Nova project achieved financial viability by selling its captured CO2 to nearby drillers for enhanced oil recovery (EOR), the prospects for Project Tundra hang on the effectiveness of the new federal CCUS tax credits in attracting investors to back the initiative.
The Internal Revenue Service is currently finalizing guidance for the so-called 45Q tax credits, which provide $50 per metric ton of CO2 sequestered in underground geological formation at power plants that capture at least 500,000 tons of CO2 per year.
However, the question is whether that tax credit will be sufficiently enticing for investors to take the plunge on a power plant CCUS project using traditional amine-based capture technology, which generally has proven too expensive to be commercially viable.
Interestingly, carbon experts note that the 45Q tax credit, if successful, will effectively blaze the trail for carbon pricing in the United States by setting a “shadow” price for CCUS at coal plants—potentially opening the economic door for the coal industry’s long-sought goal of making carbon-heavy coal plants greenhouse-friendly.
As with the Petra Nova project, Project Tundra will use an amine-based liquid solvent to capture the CO2 in the Young plant’s flue gas so it can be converted into a liquid that can be injected underground—a process that is not only costly but takes a slice of a generating plant’s electricity output to run.
Minnkota and its business partner BNI Energy, a coal company owned by Minnesota-based Allete that supplies the Young plant, say they have optimized the amine process and Project Tundra’s design through collaboration with Fluor, the engineering firm of Burns & McDonnell and consultants such as David Greeson, who helped lead the Petra Nova project.
If everything “aligns perfectly,” construction would begin at the Young plant’s 455 MW Unit 2 at the end of 2021, with operations to sequester and inject carbon 1 mile underground starting in late 2025, said Stacy Dahl, Project Tundra’s senior manager of external affairs.
She said the project is expected to sequester 3 million tons of carbon per year, the maximum amount eligible for the $50 per ton tax credit at any single power plant CCUS project. At that sequestration rate, Project Tundra would generate $1.8 billion in federal tax credits over 12 years for investors willing to bet on the project, Dahl estimated.
She suggested the tax credits would bring enough investment to offset the cost of Project Tundra—and that Minnkota is seeing some investor interest.
“What we’re hearing from the investment community is that there’s certainly an interest in 45Q,” she said while declining to provide any specifics. “It’s somewhat of an unknown quantity, but there’s definitely interest.”
Project Tundra has been strongly backed by North Dakota officials as a way to maintain the vitality of the state’s mining industry for carbon-heavy lignite coal and to revitalize legacy oil fields through creation of a new CO2 EOR industry.
The strategy to preserve the state’s lignite coal industry is of interest to BNI Energy, which has seen revenues drop from its long-term coal contract with Minnkota’s Young plant, which runs through 2037.
Minnkota also remains in talks with Eagle Energy Partners, a nearby oil company, to explore EOR opportunities in western North Dakota. The new 45Q tax credits offer $35 for every ton of CO2 that is sequestered through EOR.
However, with Congress’ adoption of the $50 per ton credit for CO2 sequestered underground by coal plants, Minnkota has focused on sequestration as the most financially viable strategy for Project Tundra.
Carbon market experts generally agree with Minnkota that the $50 per ton credit could go a long way toward making Project Tundra viable, especially if it applies lessons learned from the Petra Nova project to show that CO2 capture costs can come down.
And some analysts suggest that the successful use of the 45Q credit at Project Tundra could bolster the case for carbon pricing, which Republicans now uniformly oppose.
With effective application of the 45Q, “we now have the equivalent of a shadow price on carbon—which in this context would be up to $50/ton for geologic sequestration and up to $35/ton for carbon captured for EOR,” said Ponciano Manalo, a principal research analyst who follows CCUS developments for IHS Markit, the global analytics firm that owns The Energy Daily.
He noted that before lawmakers boosted the 45Q tax credit last year, investors would get credits of $20/ton for carbon that was stored geologically and $10/ton for carbon sequestered through EOR. However, those price points were too low to incent wider interest in the deployment of carbon capture domestically, which helps to explain why only two major projects outside the oil and gas industry have so far moved to the operational stage, Manalo said.
Improving carbon capture is critical from a climate perspective because emerging economies such as India and China are still building coal plants to bring millions out of poverty and will need to find a way to keep emissions in check. With the 45Q tax credit program, the United States is uniquely positioned to take a leadership role, said Manalo.
However, he added that tax credits are not a permanent fix for CCUS’ financial problems, and that only a carbon pricing system will provide the lasting support that is needed to make carbon capture at coal plants commercially viable.
Further, some analysts suggest the richer 45Q tax credit still may not be enough to win investor favor for CCUS at coal plants. Because the concentration of carbon in emissions from coal plants is relatively low compared to the emissions from some other industrial sources like ethanol, hydrogen and fertilizer facilities, it costs more to capture emissions from coal-burning power plants, noted Ryan Edwards, a policy advisor for Occidental Petroleum Corp.’s Oxy Low Carbon Ventures in Houston who specializes in carbon capture.
Coal plants “seem to be around the edge of what’s possible with the value of the new 45Q credits,” he said.
Edwards expects to see more CCUS projects at the industrial sources with more concentrated carbon discharges, but he says some coal plants in certain regions and circumstances may still be financially viable.
Minnkota thinks it belongs to that category due to the strong political and policy support it has received from the state for Project Tundra. The co-op enlisted its congressional delegation to help push for the DOE grant and the state passed a series of laws and regulations clarifying liability and land use to make Project Tundra more palatable to risk-averse investors. Among other things, the state will assume liability for the sequestered carbon 10 years after the project ends, which Dahl called “huge.”
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Solar advocates and industry groups have come out against a first-of-its-kind proposal by the Sacramento municipal utility to allow homebuilders in its service territory to opt out of California’s precedent-setting home solar mandate if they agree to participate in a community shared solar program planned by the utility.
The proposal, submitted by the Sacramento Municipal Utility District (SMUD) to the California Energy Commission (CEC) September 26, has drawn attention because it is the first effort to exercise alternative compliance mechanisms provided by the CEC when it approved highly publicized building efficiency rules last year requiring all new homes and low-rise residential buildings in the state to have rooftop solar starting next year—the first such mandate in the country.
But while the CEC rules specifically allow for alternative compliance measures to meet the rules’ fundamental requirement that builders provide net-zero energy homes and buildings, solar advocates and rooftop solar installers are crying foul over SMUD’s plan to let builders achieve compliance through its proposed Neighborhood SolarShares program.
In general, the critics complain that SMUD wants to build utility-scale solar facilities to meet the CEC rules, undermining state policies that encourage distributed solar and the general thrust of the CEC rules supporting more home solar arrays.
However, CEC staff are backing the SMUD plan, and SMUD officials say they are surprised by the critical comments filed by Vote Solar and multiple solar industry groups at the CEC because those groups did not previously voice any opposition to the utility’s community solar effort at workshops held by the commission on SMUD’s plan.
While it is unusual for green groups to object to any program that encourages more solar, Vote Solar and other opponents of SMUD’s plan say the utility is improperly seeking to meet both its clean energy deployment requirements under California’s renewable portfolio standards (RPS) and the CEC’s Title 24 building efficiency standards. They say that while SMUD is building utility-scale solar to meet the state’s rising RPS standards, the community solar plan it has submitted to the CEC will greatly reduce any additional rooftop solar that otherwise might be installed in its service territory to meet the building efficiency rules.
The critics also say that some of the utility-scale solar plants planned by SMUD will not directly serve the new homes and buildings that otherwise would be required to install rooftop solar under the CEC rules. Instead, they say some of the SMUD solar generation will be located hundreds of miles away from homes that would be allocated output from those projects under the utility’s alternative compliance scheme for sidestepping the home solar mandate.
While most of the solar projects SMUD lists for supplying its proposed community solar program are 5 megawatts or less, the Great Valley Solar project is 60 MW, and two others under development—Rancho Seco II and Wildflower Solar—total 173 MW.
However, SMUD officials point out that the CEC in its Title 24 rooftop solar requirements for new buildings included a specific compliance alternative under which shares of a CEC-approved community solar system can be substituted for the otherwise required onsite solar.
Vote Solar acknowledges that compliance alternative, but says the CEC effectively undermined its own home solar requirement by not precisely defining what community solar programs qualified as an acceptable substitute for home solar, with the apparent goal of allowing flexibility for alternative compliance mechanisms involving community solar.
Notably, CEC staff recommended approval of the SMUD proposal October 8 in a brief review that effectively ticked off a checklist of administrative requirements for an alternative compliance application.
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In a surprising rebuke to the state’s utilities and the agency’s own staff, the Florida Public Service Commission Tuesday rejected utility proposals to dramatically reduce or eliminate peak demand and energy conservation goals required by state law, saying it would instead keep current standards set in 2015 and seek to increase them.
The commission—long criticized by ratepayer and green groups as well as some state lawmakers as too subservient to the desires of the state’s politically powerful incumbent utilities—also went out of its way to slap its own staff for backing utility contentions that state efficiency goals no longer were needed or cost-effective in light of recent improvements in appliance efficiency and federal conservation standards.
To the contrary, the commission said in a press release that the current utility efficiency goals set under the 1980 Florida Energy Efficiency and Conservation Act (FEECA) were not strong enough, and that it would “actively pursue the modernization of FEECA to generate higher efficiency goals with next generation programs.”
Of the utility proposals, the PSC said: “Commissioners determined the 2020 proposed goals were not robust enough and expressed concern that some investor-owned utilities had goals of zero for the first time. They agreed that energy efficiency is an effective conservation resource in Florida and should be a key factor in meeting Florida’s future electric energy needs.”
The commission said the utility conservation goals set under FEECA had effectively reduced the need for new power plants in the state by cutting Florida’s total electricity consumption by an estimated 10,694 gigawatt-hours (GWh) per year.
Under FEECA, the commission must set 10-year conservation goals at least once every five years for the state’s biggest distribution utilities, including investor-owned Florida Power & Light (FP&L), Duke Energy Florida, Tampa Electric and Gulf Power and three large public power utilities, Florida Public Utilities Co., Orlando Utilities Commission and JEA, the utility for Jacksonville.
The commission’s decision also was surprising because in 2014 it acceded to utility requests to sharply cut back the efficiency goals. Over vehement protests from environmentalists and the opposition of two of its members, the PSC voted 3-2 to endorse proposals by FP&L, Duke and Tampa Electric to eliminate 10-year targets set in 2009 that established a goal of a 90 percent improvement in energy efficiency by 2020. In their place, the commission approved far less ambitious targets that took effect in 2015.
Those 2015 standards will now remain in place through 2025 and the commission ordered the utilities to come in with new efficiency proposals.
And while it did not lay out specific plans for modernizing FEECA, it appears likely the commission will consider changes to a cost-effectiveness screening tool—the Ratepayer Impact Measurement (RIM) test—long used by the PSC to estimate benefits from ratepayer-funded utility programs to encourage conservation, such as rebates to consumers for more efficient appliances or building weatherization.
Energy efficiency advocates and the Florida Office of Public Counsel, the state ratepayer advocate, say the RIM test is outdated and misguided because it categorizes reductions in power consumption from improved efficiency as a cost to utilities due to resulting reductions in their revenues. The RIM critics say that metric enables utilities to portray efficiency improvements as money-losers for ratepayers, and that virtually all other states have abandoned the test in measuring the effectiveness of their utility efficiency programs.
In fact, it has long been an article of faith in the utility industry that increasing efficiency is the most cost-effective way to chop power costs to consumers, especially by cutting peak demand, thus reducing utilities’ need to dispatch expensive “peaker” plants.
However, efficiency standards have come under attack in several states in recent years from utilities that already are struggling with stagnant demand growth.
That is not the case in economically robust Florida, where demand growth continues to rise, but the state’s regulated and vertically integrated utilities have a vested interest in building more power plants to increase rate base, their main engine for increasing revenues and earnings.
The only utility seeking to boost its efficiency goals this year was Tampa Electric, which proposed to increase its overall energy savings goal by 14 percent to 165 GWh over the 10-year period.
FP&L and Duke, the state’s largest utilities, proposed reductions in their efficiency goals, saying ratepayer-funded utility rebates designed to encourage conservation by consumers were no longer needed.
“Changes in building codes and standards and economic conditions have increased the amount of efficiency that customers are undertaking on their own, without incentive from the utility,” said Duke in testimony to the commission.
FP&L said its customers already benefit from steps the state and federal government have taken to boost efficiency, and that those initiatives have diminished the impact of utility programs.
However, the Southern Alliance for Clean Energy (SACE), a pro-efficiency group, said FP&L’s proposed efficiency target was is 99.8 percent lower than the goal set by the PSC for the utility in 2014. SACE said the utility’s goal for residential power savings, 116 megawatt-hours, was equivalent to the energy one Florida home uses over 10 years.
FP&L countered by saying the energy savings goal advocated by SACE for the utility—1.5 percent of its retail sales and a measure supporting low-income families—would cost its ratepayers $4.1 billion over the next decade.
Not surprisingly, SACE and other efficiency advocates welcomed the PSC’s decision to reject the utility plans to cut or kill their efficiency goals, but they suggested the commission faced a steep hill to bolster conservation in the state.
“Although Florida’s current energy savings goals still lag behind national goals and must be strengthened, the commission's decision to reject the near-zero goals proposed by utilities is a better outcome for consumers than giving utilities a free pass to do nothing,” the efficiency advocates said in a joint statement Tuesday.
However, they added: “The current efficiency goals that the Public Service Commission voted to extend have earned Florida a ranking of 45th among states for energy efficiency.”
The American Council for an Energy-Efficient Economy currently ranks Florida among the bottom six states when it comes to actual electricity savings. It says the state achieved just 0.09 percent in net incremental electricity savings in 2017.
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Amid charges by green groups that utilities are costing customers billions of dollars by self-scheduling dispatch of uneconomic coal plants, the Midcontinent Independent System Operator indicated Tuesday it is rolling out a new multi-day market outlook designed to help generators make informed decisions on whether to run the coal plants based on forecasted prices for the days ahead.
In November the Midwest grid operator will launch what it’s calling the “Multi-day Operating Margin” forecast, which will “provide high-level information on the supply/demand balance in MISO for the upcoming 7-day period.”
MISO, which runs the grid and a regional wholesale power market for all or parts of 14 Midwest and Gulf Coast states, also says it is “in the process of pulling together information to frame and evaluate a more advanced forward market mechanism with stakeholders in early 2020.” Such a market would allow price transparency beyond MISO’s current day-ahead market.
The longer forecasts and possible advanced forward market mechanism are meant to provide greater visibility into prices over a longer timeframe to help plant operators—particularly coal-fired generators—decide when it is more economic not to run.
MISO officials said this week that they ran simulations in 2017 indicating an advanced forward market mechanism may benefit customers across its service area by potentially reducing the time that coal plants operate outside of economic merit.
The enhanced forecasting is especially important for coal plants because they cannot ramp up and down quickly and face huge costs when they have to turn on and off frequently. Coal plant operators say they sometimes run outside of economic merit to avoid the costs of shutting down and coming back on.
The moves come as MISO, the Southwest Power Pool and other regional grid operators—as well as state regulators—are coming under increasing pressure from renewable energy advocates and green groups to provide greater oversight of “self-scheduling,” the practice by which owners of coal plants and other resources schedule their plants to run outside of economic merit in wholesale markets. Several studies have indicated 30 percent or more of generation dispatched in some markets—including SPP and MISO—is through self-scheduling.
A series of recent reports from the Sierra Club, Union of Concerned Scientists and the Wind Solar Alliance (WSA)—which includes the American Wind Energy Association and Solar Energy Industry Association—claim that regulated, vertically integrated utilities are much more likely to self-schedule their coal plants to run when wholesale energy prices do not cover their costs because they know they can recover costs from their ratepayers.
WSA in a November 2018 study said regulated utilities have “a perverse incentive” to self-schedule their coal plants because they can pass through operating costs of an otherwise uneconomic plant to ratepayers. And by ensuring a coal plant regularly runs, a utility can demonstrate to regulators that a plant remains “used and useful,” thus helping the plant remain in the utility’s rate base, where it earns a rate of return for the utility.
The latest report on self-scheduling, released last week by the Sierra Club, claims that the practice of running coal plants outside of economic merit is seldom seen among merchant generators that cannot fall back on recovery of costs from ratepayers because they would lose money by incurring plant operation costs exceeding revenues from market prices.
Specifically, the report estimates that coal plants self-scheduled to run in wholesale markets operated by MISO, SPP, PJM Interconnection and the Electric Reliability Council of Texas (ERCOT) saw combined losses of $3.8 billion relative to wholesale market prices between 2015 and 2017. Between 79 percent and 87 percent of those losses were incurred at coal plants owned by regulated utilities as opposed to merchant generators, the study indicated.
MISO accounted for the highest number of non-economically dispatched coal-burning power plants, with plants losing nearly $750 million in MISO’s energy market alone, according to the study. A greater number of coal plants in MISO are owned by vertically integrated utilities than in other regional grids such as PJM, where most are merchant generators, the study noted. A “large cohort” of coal plants in MISO that currently operate at capacity factors of between 40 and 80 percent would fall to 20 percent or lower under ideal economic dispatch, the study stated.
MISO and plant operators have noted that there are many valid reasons why a coal plant may be operated outside of economic merit. Utility owners must consider reliability factors and account for the full cost of plant ownership, which may include contracts for fuel supplies, additional wear-and-tear on the plants, long start-up times and other costs that may not be fully accounted for in wholesale prices.
The new Sierra Club study acknowledged it did not account for all factors, but said it took into account reliability and other issues that extended beyond wholesale prices.
Overall, the study concluded that while economic dispatch of MISO’s coal units in 2017 was feasible, it would have resulted in “less coal generation, lower system costs and higher market revenues.” Specifically, it said that if coal units in MISO had dispatched economically rather than through self-scheduling in 2017, generation from coal units would have fallen about 10 percent, from about 324 terawatt-hours (TWh) to 293 TWh.
The new Sierra Club study largely meshes with the findings of previous reports from green groups and the WSA. However, the latest study compares in greater detail the self-scheduling practices of coal plants owned by regulated utilities with ones owned by merchant generators.
“In periods when energy market prices are low, coal plants owned by regulated, vertically integrated utilities are systematically operating coal plants out of merit, to an extent not seen in merchant-owned coal plants,” the study says. “These non-economic decisions have unnecessarily driven up costs to captive ratepayers of non-economic coal plants, increased emissions from non-economic coal plants, and driven down revenues to independent generators, renewable energy producers and more economically efficient regulated generators.
“One of the most substantial findings here is that the non-economic dispatch of coal units in market regions is likely depressing regional wholesale market prices,” the study adds.
Specifically, the study says median hourly market prices would have increased by about $7.70 per megawatt-hour—about a 30 percent increase—across nine modeled MISO regions if coal units had been dispatched economically in 2017.
“This practice disadvantages independent power producers, qualified facilities under the federal Public Utility Regulatory Policies Act, new renewable energy entrants, energy efficiency programs, net metering customers and the customers of regulated units that are economically dispatching,” the study asserts.
In the face of similar findings from previous studies on self-scheduling of coal plants, the Missouri Public Service Commission (MPSC) earlier this month expanded an investigation into self-scheduling practices by the state’s large investor-owned utilities, directing them to provide additional information about the inputs that go into their scheduling decisions.
Notably, MPSC staff to date says it has not found evidence that the self-scheduling practices have hurt the state’s ratepayers. However, the staff says it needs more information that they will later use in rate cases and proceedings to determine if scheduling is affecting utilities’ recovery of fuel costs from ratepayers.
The SPP independent market monitor also has been pushing for that grid operator to assess self-scheduling practices more closely, saying they can undermine the efficient dispatch of lowest-cost resources across SPP’s grid in 14 Great Plains and south-central states.
MISO officials say their 2017 simulations of an advanced forward market show significant benefits to customers, but not at the scale indicated by the recent Sierra Club study.
“Based upon that limited work in 2017, MISO expects the benefits of a forward market mechanism to be material, but much less than the Sierra Club estimate,” MISO spokeswoman Allison Bermudez told The Energy Daily.
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