MISO has developed a revised approach for providing owners of financially struggling generators more flexibility, saying it will treat Attachment Y filings as suspension notices while allowing owners 18 months to make a final retirement decision.
MISO adviser Joe Reddoch said staff has drafted near-final Tariff language to align the RTO’s retirement and suspension process with the annual capacity auction.
In April, MISO said it would eliminate the temporary suspension provisions from its Attachment Y change of status rules in favor of a catch-all “economic shutdown” period. But some stakeholders said the move to a binary status for generators — on or off — might nudge some owners into prematurely retiring units. (See “Removal of Temporary Suspensions will Provide Generators Flexibility, RTO says,” MISO Planning Advisory Committee Briefs.)
With the revised language bringing the suspension concept back, retirement terminology would only come into play when generation owners waive their rescission rights or when the rescission period ends, giving asset owners time to decide, Reddoch said.
Under the proposal, all Attachment Y notices will be submitted as open-ended suspension requests without the estimated return date currently required by MISO. The temporary shutdowns would be limited to 18 months, with the RTO open to extending a suspension status to 30 months, aligned with the beginning of the planning year. MISO said that will allow an asset owner time to evaluate repairs in the case of a forced outage.
“By reorienting this process around suspensions, the process is a little more intuitive,” Reddoch said, adding that asset owners would no longer be forced to decide when submitting an Attachment Y notice if their units will suspend or retire.
Reddoch asked for stakeholder feedback by Sept. 1 and said he would return to review final Tariff language at the September PAC meeting. MISO plans a FERC filing in October or November, he said.
Clean Line Energy Partners said Thursday it is considering legal appeals and other options following the Missouri Public Service Commission’s third rejection of its proposed Grain Belt Express.
The PSC on Wednesday rejected Clean Line’s request for a certificate of convenience and necessity (EA-2016-0358). The commission previously denied the $2.3 billion project last year on a procedural error, and in 2015 for not proving the project’s necessity and worth.
Mike Skelly, Clean Line’s founder and president, said the company will review the PSC’s order to determine its next course of action.
“We are currently assessing all existing authorities available to move the Grain Belt Express project forward, including, but not limited, to legal appeals,” Skelly said in a statement. “The PSC’s decision … sends a clear message that investors contemplating new infrastructure projects should not come to Missouri.”
Clean Line’s other options, said spokesperson Sarah Bray, include asking the PSC for a rehearing, working with the state’s legislature to revise pertinent laws or seeking U.S. Energy Department approval under Section 1222 of the 2005 Energy Policy Act. The latter would authorize the department to take part in “designing, developing, constructing, operating, maintaining or owning” new transmission.
“The project is certainly not dead,” Bray said.
Following the PSC’s 2015 rejection of the Grain Belt Express — when the commission determined there weren’t enough benefits for Missouri consumers and cited landowner opposition — Clean Line signed up more than three dozen cities to purchase about 100 MW of power from the project. The Houston-based company projects ratepayers in those cities will see annual savings of $10 million.
| Clean Line Energy Partners
Four of the commission’s five members said in a concurring opinion Wednesday the project is needed, economically feasible and beneficial to the public.
However, they referenced a March state appeals court ruling on an unrelated case involving Ameren Transmission Company of Illinois, which found that infrastructure projects must first secure approvals from each county it crosses.
In 2012, Clean Line won permission from the commissions of eight counties to construct the line along and across their public roads. But the company was tripped up in Caldwell County, after a court ruled in 2015 that county officials had violated the state Sunshine Law when they approved the line.
“It was in the public interest to approve the line,” PSC Chairman Daniel Hall said. “Unfortunately, because of the structure of this commission and because of the legal system in this state, we were unable to act in the public interest.”
Commissioner Steve Stoll did not sign the order, saying “the court has spoken.”
Bray told RTO Insider that Clean Line was “encouraged by the PSC’s determination that the project is in the public interest and will benefit the State of Missouri.”
The “ruling is inconsistent with good government and sound public policy, and it is our hope that moving forward, Missouri will work to remove barriers to building new critical infrastructure projects,” Skelly said.
James Owen, executive director of Renew Missouri, which supports renewable energy and energy efficiency, said the PSC ruling is based on a misreading of state law and undermines Gov. Eric Greitens’ promise to eliminate “job-killing regulations.”
“The [appellate] opinion now says that a few county commissioners have absolute veto power over the regulatory decisions of the federal and state government,” Owen said in a statement. “This multibillion-dollar project spanning four states is now stalled due to a baseless objection from a single Missouri county. … In the face of this absurd result, Gov. Greitens’ silence is deafening.”
The Grain Belt Express would deliver approximately 4,000 MW of wind power from western Kansas through Missouri and Illinois to the Indiana border over 780 miles of DC lines. Kansas and Illinois regulators approved the project within their states in 2013 and 2015, respectively.
Clean Line said the decision would be “devastating” for Missouri ratepayers and workers “who will be deprived of good paying local jobs.”
The company had support from a number of the state’s companies and organizations, including the Missouri Joint Municipal Electric Utility Commission, the Missouri Department of Economic Development, the International Brotherhood of Electrical Workers, the Missouri AFL-CIO, The Wind Coalition and Wind on the Wires.
CAISO on Tuesday unveiled its latest revisions to a program meant to compensate uneconomic generation units needed to maintain reliability.
After consulting with stakeholders since June, CAISO unveiled 20 changes to the Capacity Procurement Model Risk-of-Retirement Initiative (CPM ROR). The ISO is taking comments through Aug. 28 on the revised straw proposal, which is due to be reviewed by the Board of Governors on Nov. 1.
Stakeholders were skeptical of the program when it was proposed earlier this year, saying it does not address the fact that CAISO’s energy market can no longer adequately compensate generation resources that are unprofitable but are still needed to manage the integration of large amounts of renewables (See CAISO Stakeholders Question Risk-of-Retirement Initiative.)
On a call Tuesday, Pacific Gas and Electric representative Peter Griffiths asked how the CPM ROR process relates to a separate reliability-must-run process, as one of CAISO’s stated objectives is to see if ROR could be used rather than RMR. “I just want to make sure that is a touchstone to some degree that we continue to look back at,” Griffiths said.
CAISO Manager of Infrastructure Policy and Contracts Keith Johnson replied that “one of the objectives here is to see if CPM is a viable option.” He said the changes are intended to increase the possibility of using the program, which has never been deployed since its creation in March 2011.
“We want to see if there is a way that we can at least make the existing provisions work better so there is a higher probability that they will be used and useful,” Johnson said. There are still circumstances in which RMR will be needed, he said.
Earlier this year, CAISO awarded RMR designations to Calpine’s Yuba City and Feather River peaking plants after the company said it would be forced to retire the facilities if required to await a decision on CPM next year. (See CAISO RMRs Win Board OK, Stakeholders Critical.) Calpine said the RMR award was the only viable option, but CAISO wants the CPM ROR to be the primary backstop to generation shortages through retirement.
CAISO is tweaking its backstop procurement for resources like Calpine’s Yuba City Plant that are needed for reliability | Calpine
Most stakeholders support allowing any resource to apply for a ROR designation, including resources that are under a resource adequacy (RA) contract. Currently, generation resources that have an RA contract for the upcoming (January-December) RA year cannot apply for ROR designation. Capacity under a RA or RMR contract or another kind of CPM procurement may not receive ROR payments at same time.
Resource owners say that one current problem is that CAISO cannot initiate its study to determine the need for an individual unit until November of each year, just after all load-serving entities publish their RA requirements for the following calendar year. Generation owners have expressed concern that they don’t know if their resources will have RA contracts until Oct. 31. One of CAISO’s objectives is to provide for its ROR analysis to take place prior to the end of the RA contracting period.
| CAISO
Under the new proposal, windows would open in April and November each year for three types of ROR designations:
Type 1 refers to non-RA resources for designation within the current RA compliance year (April window).
Type 2 is for RA resources or non-RA resources for designation during the calendar year following the current RA compliance year (April window).
Type 3 is for non-RA resources for designation during the upcoming RA compliance year (November window).
The straw proposal also clarified the criteria for an ROR designation: that the “grid cannot be reliability operated without that specific resource in service.” CAISO plans to post reports within 30 days of such findings to allow stakeholders to comment.
CAISO’s draft final proposal is due to be posted on Sept. 11, and another stakeholder call is set for Sept. 18.
MISO is yanking support on the last possible project resulting from a coordinated study with SPP, nixing the RTOs’ chances this year to collaborate on a first-ever interregional project.
The RTO now says an analysis of the $5.2 million Split Rock-Lawrence project in South Dakota shows that congestion on the line can be managed for now and that another alternative project could provide the RTO with at least the same benefit at a lower cost.
The project was halted before it could clear the Joint RTO Planning Committee — composed of staff with ultimate say over interregional issues — and before it would have been recommended for inclusion in MISO’s 2017 Transmission Expansion Plan. The coordinated study was meant to focus on needs along the border of SPP’s Integrated System in North Dakota, South Dakota and Iowa. Some MISO stakeholders expressed doubt at the beginning of the study that any projects would materialize.
The RTO said the congested line in South Dakota is now operating as an open circuit under an operations guide proposed by Xcel Energy in May, which shifts some congestion to the nearby Sioux Falls–Split Rock 230-kV line. Had the project — which would have looped Xcel’s existing Split Rock-Lawrence 115-kV circuit into the Western Area Power Administration’s Sioux Falls station, crossing SPP territory — proceeded, Xcel would have been at risk of incurring SPP penalties for unreserved use of non-firm point-to-point transmission service, MISO said.
The RTO recommends the maintaining status quo and operating the Lawrence–Sioux Falls line in an open state to relieve the congestion for now, Davey Lopez, the RTO’s adviser of planning coordination and strategy, said during an Aug. 16 Planning Advisory Committee meeting. He added that the open state operation “provides MISO nearly the same adjusted production cost savings” as the interregional project at little to no cost.
However, MISO said it would continue to pursue upgrades to terminal equipment on the Lawrence–Sioux Falls line through joint efforts between MISO, Xcel, SPP and WAPA. The terminal upgrades would still represent a savings over the originally proposed loop project, the RTO said.
Adam McKinnie, utility economist for the Missouri Public Service Commission, said he had “severe concerns” that MISO was allowing a temporary operations plan to become a long-term solution for congestion.
“We couldn’t justify subjecting our customers to a $5 million project when there’s a no-cost solution available,” Lopez explained.
McKinnie also questioned if the SPP-MISO seam is receiving the same level of interregional coordination as the MISO-PJM seam. “I’m kind of tired of refereeing fights between MISO and SPP because my ratepayers pay for those fights,” he said, adding that SPP officials seem more receptive to interregional planning than those at MISO.
MISO staff countered that the RTO is looking for the most economic and efficient solution to the congestion.
The RTO’s interregional project cost and voltage thresholds with SPP remain unchanged at $5 million and 345 kV, respectively. FERC ruled at the beginning of the year that both RTOs were not bound by its directive to PJM and MISO to remove identical thresholds. SPP had asked FERC last year to apply the same directive to the MISO-SPP seam.
Had the 115-kV Split Rock-Lawrence project won approval, MISO would have had to designate its portion of the project as miscellaneous, unable to qualify for cost allocation, because it does not meet the 345-kV voltage threshold required of its market efficiency projects.
| MISO & SPP
It’s unclear how soon the RTOs will embark on another joint study. Last spring, MISO staff originally decided against a coordinated study, explaining that it was hoping to improve the process behind coordinated studies before taking up another one. Staff later reversed course and agreed to the 2016 coordinated study. A 2014-15 MISO-SPP coordinated study ran over deadline by three months and left both RTO staffs frustrated and empty-handed. (See SPP, MISO Try to Bridge Joint Study Scope Differences.)
MISO will pursue changes to its Transmission Expansion Plan futures weighting process in the 2019 cycle of projects, delaying the initiative by one year.
Starting with MTEP 19, equal weighting will be assigned to all four future grid and generation scenarios, effectively eliminating weighting of the 15-year futures. Staff initially said it would drop weighting beginning with MTEP 18. (See MISO Rethinks Weighting of MTEP 18 Futures.)
The RTO began reviewing its weighting process early this year after MISO South transmission owners and regulators of southern states asked for less emphasis in one MTEP 17 study on futures containing policy regulations and increased penetration of alternative technologies. The RTO granted the request. (See MISO Changes MTEP Futures Weighting for South.)
MISO policy studies engineer Matt Ellis said the RTO is delaying the change because MTEP 18 futures were developed with the understanding that stakeholders would be involved in deciding their importance.
“It doesn’t make sense to change something when it was implicitly understood at the beginning,” Ellis said during an Aug. 16 Planning Advisory Committee meeting. He asked for stakeholder input on the unfinished MTEP 18 weighting process and said MISO still reserves the right to “put its thumb on the scale” if it thinks the stakeholder rationale for weighting is weak. Not surprisingly, MISO is recommending a 25% weighting for all four MTEP futures: a “limited,” “continued” and “accelerated” fleet change and an emerging technologies scenario.
MISO is also considering using benefit-cost criteria in all four futures in MTEP 18 to determine which transmission projects are sent for Board of Directors approval. Projects may have to have an average 1.25:1 benefit-cost ratio across the four MTEP futures and earn at least a 1:1 cost-benefit ratio in at least two. Projects may also be rejected if a project earns a negative benefit of 0.8 greater in any one future.
Ellis said MISO will take a backward look at previously approved MTEP projects to further refine benefit-cost criteria and asked for stakeholder input on establishing benefit-cost floors.
The new equal-footing weighting process in 2019 will make MTEP futures more predictable year to year and shift the focus from stakeholders’ perceived likelihood of a certain future to how effectively a project can perform under varying scenarios, Ellis said.
“What we can all agree on is the old process wasn’t very predictable. The MISO process should be very predictable, very cut and dried,” he said.
Bill Booth of the Mississippi Public Service Commission asked if MISO was firm in its decision that all futures will have equal importance. “Seems to me that by eliminating weighting, you’re eliminating stakeholder feedback,” Booth said.
“We are firm on that. We are firm on even and equal weighting,” Ellis said.
The PSC’s David Carr asked if MISO viewed the Trump administration’s rollback of environmental regulations — which sparked the requests for reweighting of MTEP 17 futures — as an “anomaly” that is not likely to occur again.
| MISO
“We can tell you in the previous three [MTEP] cycles, we’ve gotten requests to reweight. So this is an issue that’s been building for quite some time,” Ellis said.
Going forward, Ellis said, MISO would only consider revising weights when all stakeholder sectors ask it to rethink the likelihood of a certain future. He also said that development of futures themselves will remain unchanged.
“As we go through the futures development process, we gather extensive stakeholder feedback. … We can tell you that all of our futures are very reasonable,” Ellis said.
“Sectors aren’t providing weights based on their expectations of the future, but on their advocacy of a particular business model,” said Wisconsin Public Service’s Chris Plante.
“That’s a great point,” replied Ellis.
Customized Energy Solutions’ David Sapper said it was important to have MISO’s “independent, unbiased” voice in the futures weighting process.
MISO will conduct a study to identify the challenges of integrating growing volumes of renewable generation in its footprint.
The open-ended, multiyear study will be used to “facilitate a broader conversation about renewable energy-driven impacts on the reliability of the electric system,” MISO said.
“We trying to look at the impacts over a much broader period of renewable penetration and quantify the impacts,” said Jordan Bakke, of the RTO’s policy studies group, at an Aug. 16 Planning Advisory Committee meeting. “If we look over the last decade of MISO, we started at very minimal [renewable] penetration … and we’ve grown quite steadily over that time frame.”
Different types of renewables are growing at different rates throughout the MISO regions, Bakke said, and the RTO wants to identify “inflection points” at which the growth of renewables and the retirement of baseload units will require changes in the structure or operation of the system. With more projects moving through the interconnection queue, Bakke said MISO may soon have to begin forecasting for solar output.
The study aims to predict how and when reliability will be impacted under heavy renewable output; if there are limits to the amount of wind and solar generation MISO can support; how long before energy storage becomes a requirement; what parts of the grid will be stressed first; and how much renewable energy can be deployed before significant system changes are needed.
“We don’t have a great idea of when certain things will have to take place to integrate renewable generation. We don’t know at what mix that will have to take place,” Bakke said.
MISO’s current registered wind capacity is about 16.8 GW and current registered solar capacity is about 180 MW, but those figures could pale in comparison if all the prospective projects in its generation interconnection queue are realized. The RTO currently has about 31 GW of wind capacity and 15.7 GW of solar capacity advancing through various stages of the queue.
After some stakeholders cautioned MISO not to inhibit state jurisdiction over resource adequacy or renewable portfolio standards, staff stressed that the study will be limited to an impact assessment, and nothing will be built or changed as a direct result of the study.
“We’re looking purely at the technical impacts of the system, and how those can change,” Bakke said, adding that if something significant is discovered, study results will be passed to other departments.
Some stakeholders demanded to know if the study results would eventually inform modeling in MISO’s annual Transmission Expansion Plan.
“It really depends. It’s an exploratory study, and that’s the nature of research,” Bakke said.
Wind on the Wires’ Natalie McIntire asked how this study would differ from other renewable studies the U.S. Energy Department has already conducted.
Bakke said that while national studies seek ways to incorporate targeted amounts of renewables, MISO’s study will lack “a solution-oriented focus.”
Indianapolis Power and Light’s Lin Franks offered to share the company’s data on its solar assets and Harding Street storage facility. “We’ve been trying to get MISO’s attention now for a while to provide real PV data,” Franks said. “We need to bring real data to the table before engaging in a worthless academic exercise.”
Bakke agreed that renewable data for the footprint is hard to come by and said MISO may use IPL’s data.
The RTO will return to the PAC in September with a study scope for stakeholders to review, he said.
Massachusetts regulators have issued new, stricter limits on greenhouse gas emissions from the state’s fossil fuel power plants and ordered utilities to buy at least 16% of their electricity from clean energy sources in 2018.
The regulations, announced Aug. 11 in response to a 2016 court order, include a Clean Energy Standard (CES) that requires utilities and competitive suppliers in the state to procure increasing amounts of electricity from clean energy sources every year, with the minimum percentage increasing 2 points annually to reach 80% in 2050.
The new rules also set annually declining limits on aggregate CO2 emissions from 21 large fossil fuel-fired power plants in the state, from 8.96 million metric tons in 2018 to 1.8 million metric tons in 2050. The regulations establish an allowance trading program for CO2 emissions from generators, with allowance auctions beginning in 2019 and direct allocations for 2018. The rules offer flexibility in the form of limited allowance banking and a “deferred compliance” option to address electricity grid reliability.
allowance prices assumed in the main scenarios, (RGGI price) and alternative sensitivity price | Mass. DOER
The regulations also reduce allowable methane emissions from natural gas pipelines and distribution systems. They also tap the transportation sector by requiring state, city and regional transportation planning agencies to evaluate and report the aggregate GHG emissions of their facilities, fleets and programs.
The new procurement rules are like those of the Massachusetts Renewable Portfolio Standard, while the emissions targets are stricter than CO2limits under the Regional Greenhouse Gas Initiative, the cap-and-trade system agreed on by nine Northeastern states.
Pushed to Act
The state acted in response to a 2014 lawsuit by the Conservation Law Foundation that accused Massachusetts officials of failing to enact regulations needed to meet the targets set by the 2008 Global Warming Solutions Act. The state’s top court ruled in favor of CLF in May 2016.
CLF helped win passage of the climate change law, which requires Massachusetts to issue regulations to incrementally reduce greenhouse gas emissions each year.
“These rules re-establish the commonwealth as a national leader in developing sensible, enforceable standards to transition our economy to a low-carbon future,” CLF President Bradley Campbell said in a statement. “Much more needs to be done, and Gov. [Charlie] Baker’s leadership will be essential to getting neighboring states to take meaningful action to prepare New England for the energy future being shaped by the Paris Climate Agreement.”
20-year levelized cost of renewable energy resources | Mass. DOER
Last September, Baker issued an executive order that set a deadline of Aug. 11 for the secretary of energy and environmental Affairs and the Department of Environmental Protection to have “designed such regulations to ensure that the commonwealth meets the 2020 statewide emissions limit mandated by the GWSA.”
That limit — a 25% reduction in emissions below 1990 levels — was established seven years ago by the state to meet the GWSA requirement of a minimum 80% reduction by 2050. Officials estimate that by 2014, Massachusetts had already cut carbon emissions by 21% from 1990 levels.
“These regulations will help ensure the commonwealth meets the rigorous emission reductions limits established in the Global Warming Solutions Act in order to protect our residents, communities and natural resources from the effects of climate change,” Baker said.
Limited Effect on Consumers
The DEP concluded that the emissions targets and clean procurement rules would likely increase customer electricity bills by 1 to 2% per year.
The Bay State has been busy this year ramping up its environmental regulations. Officials earlier this summer announced that the state’s electric distribution utilities must procure a combined 200 MWh of energy storage by Jan. 1, 2020. (See Massachusetts Underwhelms with 200-MWh Storage Target.)
In late July, the state received more than half a dozen proposals to meet its call for 9.45 TWh a year of renewable generation. Projects will be selected next January, with contracts to be submitted in late April. (See Hydro-Québec Dominates Mass. Clean Energy Bids.)
In response to public comment, the final CES included limited grandfathering to accommodate electricity sold in 2018 and 2019 under existing contracts. For the next three years, the alternative compliance payment rate is being increased to 75% of the RPS amount, but it will drop to 50% of the RPS amount in 2021. The use of banked clean energy credits is not allowed until 2021.
allowance prices assumed in the main scenarios, (RGGI price) and alternative sensitivity price | Mass. DOER
The RGGI emissions cap represents a regional budget for CO2 emissions from the power sector, with each CO2 allowance representing an authorization to emit 1 short ton from a regulated source. The nine RGGI states agreed on a 2014 cap of 91 million short tons. The CO2 cap declines by 2.5 percentage points each year from 2015 to 2020.
Next week’s total solar eclipse will not disrupt SPP operations despite 100% obscuration levels in parts of its 14-state footprint, according to a report by RTO staff.
The eclipse will pass over North America on Monday, with parts of Nebraska, Kansas and Missouri experiencing totality — complete obscuration of the sun — for almost three minutes. Kansas City and Lincoln, Neb., are among the municipalities in the totality path. Other states in the SPP region will experience solar obscuration levels of 80% or more.
| GreatAmericanEclipse.com via SPP
“The eclipse is expected to have some impact on resources and loads in our region,” said Lanny Nickell, SPP’s vice president of engineering.
The RTO expects to lose about 200 MW of solar PV generation during the height of the eclipse, assuming clear skies. The system currently has 215 MW of registered utility solar resources; SPP has identified another 111 MW of distributed PV on its system, including residential rooftop solar and commercial solar farms.
The eclipse will pass over the SPP footprint for about three hours, beginning at the western edge around 11:30 a.m. CT and ending at the eastern edge around 2:45 p.m.
| SPP
Although solar generation will be reduced, the eclipse also will reduce air conditioning loads because of falling temperatures. But the temperature drop also will cut wind speeds, reducing wind generation, according to the report, which was prepared by a summer engineering intern. A drop in solar generation connected to the distribution system will appear as an increase in load from the transmission system’s perspective.
The report expects demand for lighting will increase during the eclipse, which would require additional generation.
“The eclipse is worthy of study in light of the increasing numbers of distributed generators in the SPP footprint,” the report said.
That study could come in handy in 2024, when another solar eclipse will cover Texas and Arkansas on its way to the Northeast. The National Renewable Energy Laboratory (NREL) projects the SPP region may have up to 1.1 GW of distributed PV in at that time.
Utility-scale solar is also likely to increase, given more than 7 GW of solar generation is being studied in the generator interconnection queue.
Ohio regulators on Wednesday rejected challenges to their order awarding FirstEnergy a subsidy worth more than $600 million, assistance the company said it needed to avoid having its credit rating reduced below investment grade.
The Public Utilities Commission of Ohio also rejected some rehearing requests by FirstEnergy while also granting others (14-1297-EL-SSO).
Opponents of the rider immediately vowed to appeal to the state Supreme Court.
In October, the commission unanimously rejected FirstEnergy’s request for an eight-year retail rate stability (RRS) rider totaling $4.46 billion, which the company said it needed to ensure its financial health at a time in which its coal- and nuclear-fueled generation is challenged by low natural gas prices.
Instead, the commission approved a three-year distribution modernization rider (DMR) totaling about $612 million for subsidiaries Ohio Edison, Cleveland Electric Illuminating and Toledo Edison. The commission said the additional money would allow the company to make investments in grid modernization. (See PUCO Rejects FirstEnergy’s $558M Rider, OKs $132.5M.)
Ohio Edison workers in a switchyard | FirstEnergy
In December, the commission agreed to consider FirstEnergy’s rehearing request, along with challenges by environmentalists, independent power producers, large customers and the Ohio Consumers Counsel (OCC).
In its unanimous ruling Wednesday, the commission said that it had already “thoroughly addressed” issues raised by OCC, the Northwest Ohio Aggregation Coalition, Cleveland Municipal School District and the Sierra Club. Commissioner Lawrence K. Friedeman recused himself.
It said the risk of FirstEnergy’s and its subsidiaries’ credit ratings dropping to below investment grade was “sufficient to constitute an emergency that threatens the utility’s financial integrity,” rejecting opponents’ claim that it should rely on the current credit ratings of the companies.
The commission also approved FirstEnergy’s request to strike portions of filings by the Ohio Manufacturers’ Association Energy Group, saying “new information should not be introduced after the closure of the record.” It also struck news articles included in filings by the Northeast Ohio Public Energy Council, which it said were hearsay.
In response to a request from FirstEnergy, it clarified its earlier ruling, saying that if Electric Security Plan (ESP) IV is terminated, the Rider Delivery Capital Recovery (DCR) revenue cap increases currently in place will continue until the commission establishes a new standard service offer (SSO). “If FirstEnergy exercises its right to terminate ESP IV at some point in the future following rehearing or an appeal, the Rider DCR revenue cap increases yet to be implemented at the time of termination will also be terminated along with the remaining provisions of ESP IV. However, FirstEnergy will be permitted to continue to recover costs already incurred under Rider DCR,” it said.
PUCO said it was “not persuaded by FirstEnergy’s assertion that DMR revenue could be recovered through a base distribution rate case. We do agree that certain costs of grid modernization, specifically the costs of any acquisition and deployment of advanced metering, including the costs of any meters prematurely retired as a result of the advanced metering implementation, may be recovered outside of an ESP [electric security plan]. Moreover, we also agree that the $568 million annual economic impact of the retention of the FirstEnergy Corp. headquarters is an economic benefit under the ESP and should be included as a consideration in the ESP versus MRO [market rate offer] test.”
Opponents of the rider reacted sharply, saying they will take their arguments to the Ohio Supreme Court.
“There is simply no basis in Ohio law to force utility customers to pay for a slush fund for FirstEnergy Corp. and its shareholders,” said Shannon Fisk, managing attorney at Earthjustice.
“We are very disappointed in the commission’s continued unwillingness to shield customers from FirstEnergy’s poor business decisions,” said Dan Sawmiller, senior representative for Sierra Club’s Beyond Coal Campaign. “The PUCO has missed yet another opportunity to focus the company on real efforts to modernize our electric grid and invest in new, clean energy technologies and instead has forced customers to pay up for unwise investments in outdated coal and nuclear plants.”
The Environmental Defense Fund said it was “confident the Ohio Supreme Court will … reject the regulators’ latest giveaway to dirty energy.”
FirstEnergy spokesman Doug Colafella said the ruling “affirmed the commission’s previous order that will help support future investments to modernize our electric system.”
“Grid modernization will benefit our customers and competitive suppliers by enhancing service reliability and enabling new products and services,” he said.
NEW YORK — While timelines for completing large power projects can be especially long in New York, developers are finding it easier to invest here now that the state is providing more predictability around clean energy procurement and market fundamentals.
That was the consensus of panelists discussing the impact of the state’s Clean Energy Standard (CES) on procurement at the Infocast New York Energy REVolution Summit held earlier this month at Times Square.
Gov. Andrew Cuomo’s Reforming the Energy Vision (REV) and its associated CES aim to meet two goals by 2030: a reduction in New York’s greenhouse gas emissions to 40% below 1990 levels and that renewables generate 50% of the state’s electricity.
To support those objectives, the governor in June announced the largest-ever state-mandated clean energy procurement, authorizing the New York State Energy Research and Development Authority (NYSERDA) and the New York Power Authority to oversee up to $1.5 billion of investment in major renewable energy projects, including offshore wind and solar.
“We’re encouraged by the number of projects, both in the interconnection queue at the ISO, and also in the pipeline of projects that are moving through Article 10,” said Doreen Harris, director of large scale renewables at NYSERDA. Article 10 is New York’s primary permitting process for authorizing the construction and operation of all utility-scale power projects 25 MW and above.
“It’s a good signal to us of the interest in New York and the supply that’s to come.”
Steady Wind
Harris said NYSERDA is focusing on three main areas around renewables: solicitation of long-term contracts; behind-the-scenes work running tracking systems and working with 152 load-serving entities; and aggressive pursuit of offshore wind.
Cuomo in January called for the development of 2,400 MW of offshore wind projects by 2030, starting with the 90-MW South Fork Project off Montauk, Long Island. (See New York Seeks to Lead US in Offshore Wind.)
“The way we are evaluating proposals is more complex than it used to be under the [renewable portfolio standard] in the sense that, first of all, we are looking to signal through some new threshold criteria the desire to really move projects through the pipeline in New York state,” Harris said.
Having the state replace goals with actual standards to achieve over five to 10 years “enhances the ability of developers to focus specifically on development of the best possible assets, with appropriate timelines,” said Jack Godshall, vice president of origination at Invenergy, the largest renewable energy provider in North America.
Firm procurement targets allow companies to spend time and capital developing assets for which they know there will be a market in coming years, Godshall said. “And that’s great for the state and also for the developers.”
Beneficial Load
Corporate clients deciding to “go solar” have shifted toward more and more larger procurements and off-site developments, according to Dennis Phayre, director of business development for EnterSolar, the top solar developer in New York.
“New York state now is limited to 2 MW on the distributed generation level, soon going up to 5 MW, but in our world, with the clientele we deal with, we certainly have to be looking at what comes beyond that,” Phayre said. “Having appropriate maturity barriers, so that we don’t have churn in awards, is super important to ensure that NYSERDA isn’t rebidding the same 100,000 MWh over and over again.”
NYSERDA Director of Policy and Regulatory Affairs John Williams said people tend to think of the DG outcomes of REV, but the program “always envisioned the supply side needing to undergo some pretty dramatic changes as well, and the Clean Energy Standard is the primary mechanism. When planning for a dynamic grid, we always imagined that there’s going to be a lot of dynamic activity on the supply side.”
Why all the focus on the power generation sector when it only represents about 20% of GHG in New York? Over the past decade, New York has nearly halved the sector’s GHG emissions, with an accompanying shift in load, according to Williams.
“The CES actually needs to take account of the shift of load,” Williams said. “We like to call it beneficial load, but clean energy-powered load only becomes beneficial to the degree that we can get consistent and continuous emissions reductions and a shift in that emissions profile in that electric generation sector. The value in an aggressive, continuous focus on power generation sector emissions is necessary because it winds up being the solution to emissions reductions that we need to see in other sectors.”
