American Electric Power has filed a complaint against MISO for failing to collect and distribute millions in transmission charges from three defunct load-serving entities more than a decade ago.
In an Oct. 10 filing with FERC, AEP claimed that MISO owes more than $4.8 million to its PJM transmission affiliates after MISO failed to bill seams-related surcharges to energy providers Nicor Energy, Engage Energy America and The New Power Co., all of which shuttered before December 2004, when MISO created the charges (EL18-7). Nicor folded in 2003 amid financial fraud allegations, while New Power was liquidated in bankruptcy that same year. Engage went out of business in 2004.
AEP is seeking the money through the Seams Elimination Charge/Cost Adjustments/Assignments (SECA), a non-bypassable surcharge in MISO’s Tariff intended to recover lost revenues for a 16-month transition period during the elimination of through-and-out rates in late 2004 in the MISO and PJM regions.
AEP said that when MISO was setting up the SECA invoice system, Nicor, Engage and New Power were already defunct and not invoiced, but the RTO nevertheless listed their ensuing charges and “allocated even more SECA charges to the Nicor Energy and Engage sub-zones (based on 2003 data).”
“The allocation of SECA charges to nonexistent LSEs thwarted recovery of the SECA charges, ran counter to fundamental cost allocation principles and resulted in cost subsidies by reducing the SECA responsibility of others,” AEP said. “MISO did not bill and collect SECA charges from the three nonexistent LSEs, nor did it adjust the SECA charges allocated to them (as the RTO did to others) and, therefore, did not remit to the PJM [transmission owners] the revenue from all allocated SECA charges.”
AEP said it asked for compensation from MISO in conference calls in November 2016 and the following August, but the RTO refused to pay. The company asked FERC to either order MISO to pay the charges with interest or set up settlement proceedings to resolve the dispute.
WASHINGTON — A court ruling requiring FERC to consider the impact of greenhouse gas emissions won’t have a “significant” impact on the agency’s licensing of natural gas pipelines, Chairman Neil Chatterjee said Friday.
On Aug. 23, the D.C. Circuit Court of Appeals ruled 2-1 that FERC’s environmental impact statement (EIS) for the Southeast Market Pipelines Project should have included “reasonable forecasting” of the project’s impact on GHG emissions.
FERC had contended that the impact of the pipelines on GHG emissions was unknowable, dependent on variables including the operating decisions of individual plants and regional power demand.
Ruling in a challenge by the Sierra Club, the court said FERC had failed to meet the requirements of the National Environmental Policy Act. FERC “should have either given a quantitative estimate of the downstream greenhouse emissions that will result from burning the natural gas that the pipelines will transport or explained more specifically why it could not have done so,” the court ruled. (See FERC Must Consider GHG Impact of Pipelines, DC Circuit Rules.)
In a press conference Friday, Chatterjee said he didn’t “believe that [the court’s ruling] was going to significantly alter the way that we evaluate these projects.”
Nexus Order
As an example, he pointed to the commission’s Aug. 25 order approving the Nexus Gas Transmission Project, a 255-mile pipeline from Ohio to Michigan (CP16-22) that is being built by DTE Energy and Enbridge’s Spectra Energy. The order contained a lengthy discussion of the environmental impacts of the project, arguing that its analysis complied with the National Environmental Policy Act.
The commission also noted that, in the final days of the Obama administration, EPA had requested the removal of a statement from the project’s EIS that said that there is no accepted methodology for correlating specific GHG amounts to changes in a region’s environment. The agency also asserted that comparing a project’s emissions to statewide emissions did not contribute to an analysis on global climate change.
“The EPA provides no compelling reason to change or supplement the final EIS,” FERC wrote. “The final EIS specifically notes that comparing project-related GHG emissions to statewide GHG inventories provides a frame of reference for understanding the magnitude of GHG emissions in general, but that it does not indicate significance. … The final EIS appropriately discusses climate change, quantifies project-related GHG emissions, identifies emission reduction and mitigation measures and programs, and notes the projects’ consistency with climate goals in the Midwest region.”
“In many ways, that approval anticipated the court’s argument in the Southeast case and addressed a lot of it,” Chatterjee said. He declined to comment on any other projects.
The Sierra Club requested rehearing in the Nexus case, saying the commission’s GHG evaluation failed to meet the D.C. Circuit’s requirement. “Regardless of what methodology FERC ultimately uses, it cannot ignore the issue by claiming, without support, that there is no way fulfill its duty committed to it by NEPA,” Benjamin A. Luckett, senior attorney for Appalachian Mountain Advocates, wrote on the Sierra Club’s behalf.
Southeast Markets’ Supplemental EIS
On Sept. 27, the commission responded to the court’s remand on the Southeast Markets project with a supplemental EIS that included estimated GHG emissions but maintained that the project would have no significant effect on the environment (CP15-16, et al.).
| Duke Energy
The 685-mile project by Duke Energy, NextEra Energy, Spectra Energy Partners and the Williams Companies, is composed of three interconnected pipelines in Alabama, Georgia and Florida: the Hillabee Expansion Project, Sabal Trail and the Florida Southeast Connection.
FERC’s supplemental EIS concluded that three Florida natural gas generators that would be supplied by the pipelines — Florida Power & Light’s new Okeechobee Clean Energy Center; Duke Energy’s new Citrus County combined cycle plant and FPL’s existing Martin County Power Plant — would emit as much as 12.5 million metric tons of CO2e annually while retirements of coal, oil and natural gas plants replaced by the new units would eliminate 6.14 million metric tons — a net increase of 6.36 million.
Burning of the pipeline’s uncommitted capacity could add an additional 2 million metric tons, FERC said. The net total of 8.36 million metric tons equals 3.7% of Florida’s GHG emissions in 2015, the commission said.
The commission said, however, that it was unable to find a method to “attribute discrete environmental effects” to the emissions. “The atmospheric modeling used by the Intergovernmental Panel on Climate Change, Environmental Protection Agency, National Aeronautics and Space Administration and others is not reasonable for project-level analysis,” the commission said.
FERC also said the social cost of carbon tool is not useful for project-level NEPA review because it does not measure the incremental impacts of a project on the environment. The commission also cited a lack of consensus on the appropriate discount rate and “the monetized values that are to be considered significant for NEPA reviews.”
| Duke Energy
A group of Albany, Ga., residents responded to FERC’s supplemental filing with a protest, saying “it assumes that coal-burning power plants will be shut down in the future but does not consider the methane output from the many compressor stations that are also planned for these pipelines.”
Other Approvals
On Friday, FERC issued certificates approving two other pipeline projects: the Atlantic Coast Pipeline (CP15-554, et al.), which will deliver up to 1.5 million Dth/d over 604 miles of new pipelines between Harrison County, W.Va., and eastern Virginia and North Carolina; and the Mountain Valley Pipeline (CP16-10, et al.), which will transport up to 2 million Dth/d from Wetzel County, W.Va., to Pittsylvania County, Va.
My last couple columns have explored the Department of Energy’s “Cash for Clunkers” proposal. The first column discussed how it will cost tens of billions of dollars and subsidize less reliable generating resources to suppress more reliable resources.[1] The second column showed that the proposal is the direct result of meetings between President Trump and Robert Murray, coal mine owner and major fundraiser for the president’s campaign,[2] not some deliberative process involving well-informed, well-intentioned people.
Robert Murray’s Confirmation
A shout-out to Murray for providing a smoking gun one day after my last column ran, confirming that the DOE proposal is all about selling more of his coal to FirstEnergy power plants, one way or another.[3]
1 in 5,000, and Then Some
Some folks may still think that the situation can’t possibly be that outrageous. The DOE proposal can’t be that devoid of merit.
Wrong.
The smoking gun below is from ReliabilityFirst, the regional reliability organization responsible for reliability in the Mid-Atlantic and Midwest states (the states that are the focus of the DOE proposal).[4]
| ReliabilityFirst
Please bear with me in explaining this graphic. It’s displaying the winter. The leftmost column is showing generating resources. The next column is showing possible reduction in those resources due to resource outages, based on the last five winters (including the polar vortex). The percentages on the left are the chance of cumulative outages exceeding the associated outage quantity.[5]
The biggest cumulative reduction in resources has a 0.2% chance of occurring. That is one in 500.
OK, now skip the 50/50 Demand column and look at the 90/10 Demand column. That reflects a one-in-10 chance of the coldest weather.
Please note that resources at a one-in-500 worst case (the second column) are still much more than the peak demand in the one-in-10 worst case (the last column).
In other words, combined there is much less than a one-in-5,000 (500 x 10) chance of peak demand exceeding resources in the winter.
And there’s more!
What if that less-than-one-in-5,000 situation were to occur? Fuel supply interruption is unlikely to be a major factor.[6] And RTOs like PJM have tools to avoid customer impact, such as public appeals for conservation and voltage reductions.[7] And any resource-demand shortage would last only hours, not weeks or of course months.[8]
The DOE proposal is much ado about nothing.
The Worm Will Turn
Here’s the third smoking gun. If FERC goes forward with subsidizing certain resources for an insignificant quality like fuel supply on site, it should recognize really important qualities like environmental/public health damage.[9] In the case of coal, the National Research Council of the National Academies estimates that coal generation causes pollution damage averaging $32/MWh.[10]
This means coal resources should pay $32/MWh for their generation, to be subtracted from whatever revenues they otherwise would receive. The payments should be distributed to those hurt by coal generation.
This administration won’t do that, but no administration is forever. Once the precedent is set for FERC to put its thumbs on the scales, coal better hope that the worm never turns.
Murray said he had pressed Trump and Energy Secretary Rick Perry to have the secretary order financial support for at-risk coal plants using DOE emergency authority, but department and White House lawyers ruled that out. “They didn’t want to declare the emergency,” he said. “It was a low point because we worked hard at it and knew it was needed.“They’re doing it in a different way,” Murray said. “Now we have another approach that’s in use to get to the same point.” https://www.eenews.net/energywire/2017/10/11/stories/1060063287↑
ReliabilityFirst says, “To the left side of the range of random outages are probability percentages related to the amount of random outages that equal or exceed the amount of outages shown above that line on the outage bar.” ↑
“Between 2012 and 2016, there were roughly 3.4 billion customer-hours impacted by major electricity disruptions. Of that, 2,382 hours, or 0.00007% of the total, was due to fuel supply problems.” http://rhg.com/notes/the-real-electricity-reliability-crisis. ↑
ALBANY, N.Y. — Now that New York has done most of the hard policymaking, it’s time to focus on building individual renewable energy projects, speakers said Thursday at the Alliance for Clean Energy New York’s 11th Fall Conference.
“It is a great time to be a New Yorker advocating for clean energy policies in New York, but all these great, strong leading policies have not put us on an easy glide path to 50%” renewable energy, ACE NY Director Anne Reynolds said.
With a tradition of home rule and spirited opposition to large-scale projects, New York is a tough place for building, she said. Thus, ACE NY needs to focus on getting projects built, Reynolds said.
“Without this new focus, and without individual projects succeeding, our collective progress will be on paper only,” she said.
She also spoke of the Trump administration’s efforts to reverse its predecessor’s responses to climate change.
“It’s been a year in which I’ve been glad to focus on advocacy in Albany rather than in Washington, D.C.,” Reynolds said. “It’s also been a year when I’ve been happy to be living in Upstate New York, as we watched with hopes and prayers as Americans in Houston and Florida and Puerto Rico and in the Virgin Islands had a front row seat to a changed and changing climate — a dangerous and deadly front row seat.”
“New York really has set forth an extraordinarily ambitious agenda for climate policy and clean energy in the state,” said Alicia Barton, CEO of the New York State Energy and Research Development Authority, who spoke of the state’s “extraordinarily ambitious” clean energy goals: 50% renewable energy by 2030, while reducing buildings’ energy and electricity consumption by 23% from 2012 levels. It also has committed to build 2,400 MW of offshore wind in the same time frame. (See New York Seeks to Lead US in Offshore Wind.)
Meeting its goals will require scaling energy efficiency to deliver outcomes at a lower cost, she said. That’s why NYSERDA is making new investments in energy efficiency that are premised on different models than used before under the $10 billion, five-year Clean Energy Fund.
“For example, we’re working to launch later this fall a program that we’re very excited about called Retrofit New York, which is a $40 million initiative to enable new models to deliver deep energy retrofits in the multifamily housing space, which is an incredibly important segment of the building stock for New York,” Barton said. “Retrofit New York is based on a model that’s been deployed successfully in a number of European markets, and it’s totally new to the U.S. So again, we are asking for partnership from industry, from players in the design of energy-efficiency delivery and project finance.”
NYSERDA is also looking at a pilot around pay-for-performance in energy efficiency, but that’s in the “fairly early stages of conception,” Barton said.
Largest Procurement in the U.S.?
Government procurement is creating the demand that will allow renewable projects to get financed and built, said Joe Martens, director of the New York Offshore Wind Alliance and former commissioner of the state Department of Environmental Conservation.
“In New York, a developer’s current opportunities for long-term contracts arise from NYSERDA and the New York Power Authority and, to a lesser extent, the Long Island Power Authority,” Martens said. “As you know, there are many open solicitations from both NYPA and NYSERDA for an unprecedented 2.5 million MWh. This procurement, the very first under the Clean Energy Standard policy, is the largest single procurement that New York has ever conducted and, as far as I know, the largest in the United States.” (See NY Clean Energy Commitment Spurs Procurement.)
Rich Allen, NYPA’s vice president for project and business development, said he was excited to tell the conference about the agency’s procurement until he realized that — with a request for proposals open and client confidentially applying — he was not free to discuss many of the details. The authority was pleased to receive more than 100 proposals offering all the technologies sought, Allen said.
“Our procurement goal when we pulled together this RFP was to hit three bullet areas: The Clean Energy Standard; we also wanted to meet our customers’ renewable goals; and we’re also seeking lower-cost renewable energy,” Allen said. “The CES will require about 29 TWh of renewable energy statewide by 2030. NYPA’s share is about 4 TWh, 1 TWh of which it is seeking in the current RFP.”
All NYPA projects — either wind, solar, hydro or biomass — will be required to be in service by 2022, with a minimum size of 10 to 20 MW, depending on the technology.
The most innovative aspect of the RFP is NYPA’s use of a prepaid power purchase agreement, in which the agency would serve as matchmakers between generators and loads. NYPA can only procure as much renewable energy as its customers express an interest in.
Retirement Issues
Doreen Harris, NYSERDA director for large-scale renewables, said that one new aspect of the CES procurement is the setting of minimum quantity requirements. “So for this year, our minimum procurement target is about 1.3 TWh, and should in November we not obtain that quantity, we would issue a second solicitation in 2017,” Harris said. “And this will continue … and will set the stage for what will be a really significant pipeline of projects both under development and in construction in the state.”
New York Offshore Wind Map with Cables | NYSERDA
On Oct. 2, NYSERDA requested that the federal Bureau of Ocean Energy Management consider areas the state felt were best suited for offshore wind development. The selection process “really is the balance of all the uses of the ocean, including fishing, environmental questions and concerns, as well as cables and pipelines,” she said.
Asa Hopkins of Synapse Energy Economics addressed the fact that some older renewable generators won’t qualify for long-term contracts under Tier II rules. To be eligible, run-of-river hydroelectric facilities of 5 MW or less, wind turbines and direct combustion biomass facilities must have entered commercial operation and had their output included in the state’s baseline of renewable resources by Jan. 1, 2003. Under CES guidelines, they also must demonstrate that the renewable energy attributes of these resources are at financial risk.
“The existing independent New York resources are about 20% of the baseline or about 13% of the resources needed to get to the 2030 goal,” Hopkins said.
If these resources were lost, either by shutting down or by selling their environmental attributes and their energy to other jurisdictions, that could be a significant challenge for New York, he said.
“Opportunities for these resources to export their attributes are increasing,” Hopkins said. “Low market prices increase the risk of retirement. Just to reiterate, New York can only claim those resources for its goals if those attributes actually stay in New York. … Our estimate is that replacing these resources, if they are lost, with Tier I resources would cost New York ratepayers $1.1 billion, and our analysis indicates that there are other policy options that would retain some or all of these resources in New York for less than that.”
On an energy basis, these resources “are 47% hydro, 39% wind and the rest landfill gas, biomass and a little bit of solar,” Hopkins said. He added that in 2014, New York resources used for renewable portfolio standard compliance in Massachusetts were about 1 TWh, with about one-tenth of that amount used in Connecticut.
“These are fungible resources and they could be attracted back to New York depending on New York’s policy,” Hopkins said.
New York’s position as a leader in energy efficiency is falling, said Karl Rábago, director of the Pace Energy and Climate Center. Lime Energy CEO Adam Procell said the reason is that “30% of those electrons, or kilowatt-hours, are wasted in our buildings.”
Procell recommended New York regulators avoid being like Florida. “In Florida they love to trumpet their 10-cent energy rate,” he said. “They’ve kept the rates very low; that’s what regulators do in Florida. But when you’re paying 10 cents/kWh to run electricity through 20-year-old equipment and fluorescent lighting fixtures that we took out in Mass. 15 years ago, that’s a very expensive energy bill. Customers care about their bills, not their rates.”
It’s not a good idea to force yourself into playing catch-up on ambitious clean energy goals, said Steve Wemple, director of Consolidated Edison’s Utility of the Future Team.
Con Ed has four different incentives or earnings adjustment mechanisms under the state’s Reforming the Energy Vision. Some are tied specifically to megawatt-hour reductions, as well as peak megawatts, the traditional programmatic incentives for utilities. The company has two new outcome-based incentives that measure the energy intensity of customers and the adoption of distributed energy resources. Con Ed is also developing a carbon intensity metric that it hopes to use as an incentive mechanism in 2019.
| ConEd
To elicit behavioral change, the company is changing its approach to the market. “We used to have rebate forms, but now it’s point-of-sale,” Wemple said. “We’re trying to work upstream to make sure vendors are stocking the more efficient appliances and making it easier for customers to realize those incentives.”
Con Ed is also trying to work through the school system. “Getting school kids to guilt their parents is a very effective tool, and it will pay off down the road,” Wemple said. “Hopefully those students will stay in New York state, and we won’t have the leakage into Massachusetts.”
Procell had the last word: “If New York backslides from 2018 to 2020, we won’t make it to our 2030 goals.”
FERC on Friday rejected SPP’s request to remove its day-ahead must-offer requirement, saying the RTO had not provided “sufficient support” for its proposed Tariff revisions (ER17-2312).
“SPP’s proposal removes the only direct penalty, beyond referrals to the commission’s Office of Enforcement, for physical withholding and associated manipulative behavior in SPP’s day-ahead market,” the commission said. It also pointed out the RTO didn’t suggest additional protections going forward.
| SPP
“Removing the limited day-ahead must-offer requirement in its entirety would make monitoring and capturing potential physical withholding in the day-ahead market even more important,” FERC said.
MMU, Golden Spread Raise Concerns
SPP’s Market Monitoring Unit and member Golden Spread Electric Cooperative both supported the proposal, though not without reservations.
The MMU raised concerns about the potential for physical withholding without the requirement and requested the removal on an interim basis for 18 months — allowing the Monitor and SPP to determine whether it does result in increased withholding.
The MMU recommended in its 2014 State of the Market report that SPP remove the limited day-ahead must-offer requirement, establish a phased penalty structure for physical withholding, update the defined thresholds for physical withholding and revise the generator capability thresholds. However, those proposals failed to pass the stakeholder process.
Golden Spread’s issues were with the day-ahead market’s competitive operation without a must-offer requirement. The co-op said it is “unsound” to rely only on the expectation that the withholding rules will catch improper behavior. The co-op also argued the Tariff should be clear on what constitutes physical withholding, so market participants aren’t subject to an “information gap.”
Without access to the shift factors and other information SPP collects, market participants have no warning on the impact of their offers, forcing them to make guesses regarding resource demand and market clearing prices, Golden Spread said.
It also said that without the must-offer requirement, market participants may offer into the day-ahead market to avoid failing ambiguous physical withholding tests, rather than basing their decisions on economics.
‘Anectodal’ Evidence
FERC said SPP referred to “anecdotal” evidence that there is little reason to fear physical withholding but did not “provide further support for this assertion.”
The commission said that while SPP assured it that there is ample resource participation in its day-ahead market, “sufficient resource participation is not a safeguard against physical withholding and associated market manipulation.” FERC said a generating resource could hold local market power because of a transmission constraint, despite a large market-wide surplus.
“The must-offer requirement is the physical withholding analog to the market power mitigation rules to address economic withholding,” the commission said.
| SPP
SPP filed the request in August, saying the must-offer requirement was no longer needed and that its reliability needs are met “at all times” by the full must-offer requirements for its reliability unit commitment processes and real-time market. The RTO said the MMU’s eye on physical withholding in the day-ahead market has a “more significant impact on market participant behavior” and, based on three years of observational data, “robust” participation in the day-ahead market resulted in capacity offered in the day-ahead market “consistently exceeding” reported load by about 50%.
SPP’s request was the result of a directive from FERC when it conditionally accepted the RTO’s Integrated Marketplace in 2012. The commission asked SPP to revise its Tariff to create a process in which it or the MMU would:
Verify that market participants had not exceeded a predetermined acceptable load forecasting error; and
Establish noncompliance penalties if market participants’ estimations exceeded the acceptable range of load forecasting error.
SAN DIEGO — The electricity sector continues to identify possible applications for energy storage while costs for the technology steadily decline, but the lack of cohesive federal, state and local policy remains the chief obstacle to integration, a panel of experts said Wednesday.
“The technology piece has caught up. What we cannot afford to do is let the policy drag it down,” Kiran Kumaraswamy of AES Energy Storage said during a panel discussion at the Infocast Transmission Summit West. Industry and policymakers can develop a framework for adopting storage once they determine the magnitude and type of need for the technology, he said.
Storage has not traditionally been seen as a workable solution to solving locational reliability needs on the transmission grid, and there are questions as to whether it should be regulated as a generation or transmission/distribution asset. The U.S., especially CAISO, is in a leadership position as far as deploying storage, “but the rest of the world is catching up,” Kumaraswamy said.
Storage can also defer transmission investment, and “the ISO has been very progressive in considering non-wires alternatives,” he said.
CAISO recently launched a yearslong effort to develop a load-shifting product for energy storage, the third phase of its Energy Storage and Distributed Energy Resources (ESDER) initiative. (See CAISO Load-Shifting Product to Target Energy Storage.)
Even in situations in which conventional generation would be much cheaper, California regulatory policy and public opinion are driving storage applications. After CAISO recently performed a study finding that the $299 million proposed Puente Power Project is the cheapest alternative to energy storage and distributed energy solutions costing up to $1.2 billion, the California Energy Commission still indicated that it might not approve the plant. (See CEC Members Recommend No-Go for Puente Plant.)
There is “a very good working relationship between renewables and energy storage,” according to Tom Dagenais of Duke-American Transmission Co., a joint venture between Duke Energy and American Transmission Co. created to develop new transmission projects — such as the Zephyr line to carry wind energy from Wyoming to California, and the San Luis transmission project in California’s Central Valley.
Dagenais cautioned that integrating energy storage is a challenge, and that the decisions being made today as the technology enters the market will set the tone for how it is perceived in the future.
“If we screw this up, there is going to be a lot of fingers pointed and a lot of questions,” he said.
FERC last November issued a Notice of Proposed Rulemaking that would require each RTO and ISO to recognize the physical and operational characteristics of storage, and accommodate storage and aggregated distributed resources in organized markets. (See FERC Rule Would Boost Energy Storage, DER.)
Harding Street Energy Storage | AES
But the agency lost its quorum shortly after the proposed rule was issued, and it is unclear whether the new commission will act on it. It is also unknown how FERC will view storage as the commission becomes embroiled in controversy over Energy Secretary Rick Perry’s new proposed rule designed to bolster coal-fired generation.
Idaho Public Commissioner Kristine Raper asked the panel how a state like hers, which is long on capacity and has an abundance of hydroelectric generation, could take advantage of energy storage.
Jin Noh of the California Energy Storage Alliance noted that California has sufficient capacity but is still pursuing energy storage. “It is a question of what type of capacity,” Noh said. “There is a major need for flexibility capacity and opportunities to save ratepayer money.”
Dagenais said: “Idaho is in a pretty unique situation,” adding that many other states have a rapidly changing resource mix. He said that storage is still something worth looking into to cut costs and reduce use of lower-efficiency generation units at peak times.
FERC on Wednesday granted MISO a six-month reprieve from a Tariff provision requiring it to include minimum zonal reserve requirements in its modeling of broader system reserve requirements.
The RTO currently calculates minimum reserve requirements using offline studies conducted three days in advance of a day-ahead market run, but it has said that study results aren’t always accurate because actual operating conditions, including transmission constraints, can deviate from original study assumptions.
A case in point: In early April, scarcity pricing was triggered in MISO because an offline study predicted an 84-MW minimum contingency reserve for Zone 6 covering Indiana and a slice of Kentucky, but it failed to account for actual transmission and generation outages modeled in the day-ahead process. Generation and transmission outages in MISO caused an outflow of energy from Zone 6, creating scarcity conditions for reserves and sending prices as high as $1,100/MWh.
In mid-July, MISO said it was evaluating changing the algorithm behind its minimum reserve requirement to reflect energy flow constraints. (See MISO Ponders Reserve Scheduling Fix.)
In its filing, the RTO told FERC it needed a waiver of “inflexible” offline studies while it holds stakeholder meetings exploring an additional modeling step to account for constraints and prepares a Tariff filing. It also noted that it could decide to permanently remove offline studies from the process.
MISO filed for the waiver last month, and the commission acted quickly given that the RTO has entered its shoulder season typified by planned outages (ER17-2466).
“MISO requests expeditious action on this waiver request because the conditions that could potentially lead offline studies to set minimum reserve requirements have previously occurred in the months of October and November,” FERC said.
The waiver remains in effect until April 12, 2018.
FERC allowed the waiver on the grounds that it will remedy current reserve price distortions through “ineffective constraint relief when minimum reserve requirements do not properly reflect real-time non-deliverability of reserves” and “protect the markets from price signals that do not properly reflect or resolve real-time reserve deliverability issues.”
WASHINGTON — Energy Secretary Rick Perry on Thursday defended his call for price supports for struggling coal and nuclear plants, telling the House Energy Subcommittee “these resources must be revived, not reviled.”
Perry also pushed back on criticism that his Notice of Proposed Rulemaking, which called for “full recovery” of the plants’ costs, would undermine competitive markets.
Republicans largely expressed support for the rule. But Perry did little to counter allegations that his action was motivated by President Trump’s campaign promises to help the coal industry — repeatedly sidestepping Democrats’ questions about the costs of his proposal and the evidence supporting the need for 90 days of on-site fuel. He also contradicted himself on whether the NOPR was a command to FERC or an invitation to “start a conversation.”
“The base reason that we asked for this … is that, for years, this has been kicked down the road,” Perry said of the NOPR, published in the Federal Register on Tuesday.
The proposal would require FERC-jurisdictional RTOs and ISOs with capacity markets and day-ahead and real-time energy markets to ensure full cost recovery for any generation that is capable of providing “essential energy and ancillary services” and has a 90-day fuel supply on site “enabling it to operate during an emergency, extreme weather conditions, or a natural or man-made disaster.” Units subject to cost-of-service rate regulation would be excluded.
Essential services include voltage support, frequency services, operating reserves and reactive power. Just and reasonable rates for such generators would cover “its fully allocated costs and a fair return on equity,” including operating and fuel expenses and the costs of capital and debt, the NOPR said.
Rep. Bobby Rush (D-Ill.), ranking member of the subcommittee, asked how Perry reached the conclusions in the NOPR, given that FERC and NERC have said that the grid is reliable. In an apparent reference to the NOPR, FERC Commissioner Robert Powelson promised in an Oct. 4 speech “not to destroy” the markets, leading Commissioner Cheryl LaFleur to tweet, “Great message!”
“I respect the FERC members’ views,” Perry said. “I think their picture is one that is a snapshot in time. … What I think one of my roles is is to think outside of the box.”
The grid is normally resilient during “blue sky” days, he said, and his support for an “all of the above” generation mix was proven during his time overseeing wind growth as governor of Texas. “But the wind does not always blow. The sun doesn’t always shine. The gas pipelines — they can’t guarantee every day that that supply is going to be there.”
“It seems to me what you’re saying is, ‘Well my gut feeling has more of a priority … rather than what these experts have said,’” Rush responded.
While no Republican on the subcommittee criticized the proposal — and many offered their support and praise for Perry — party leadership did not tip its hand.
“While I reserve judgment on the policy solutions, the fact that the secretary stepped in to this complicated debate reflects the current need to have a broader conversation about the functioning of the nation’s electricity markets,” subcommittee Chair Fred Upton (R-Mich.) said in his opening statement.
Rep. Greg Walden (R-Ore.), chair of the full Energy and Commerce Committee, made no mention of the NOPR in his opening remarks, instead focusing on the Department of Energy’s budget.
Countering Subsidies
Perry said he was attempting to counter subsidies that have benefited renewables at the expense of coal and nuclear. “There is no such thing as a free market in the energy industry,” he said multiple times. “Government’s picking winners and losers every day by regulations … and I’m at least honest enough to say it.” He pointed to state utility commissions, policies such as renewable portfolio standards, and Texas’ own Competitive Retail Energy Zones as evidence.
Rep. Gene Green (D-Texas) pushed back on this, pointing to the retail choice offered in his state and the uncoupling of generators from utilities.
“Gene, you know me, I’m all about that competition,” Perry said. “That’s what we did … we deregulated that market and that competition came. But the idea is, we had an administration before that had their thumb on the scale. I think you’ll agree, [former President Barack Obama] liked green energy, and that’s where the subsidization came.”
Rep. Paul Tonko (D-N.Y.) pointed out that the production and investment tax credits for solar and wind resources, respectively, were passed by a Republican-controlled Congress.
Not Supported by DOE Study
Rep. Frank Pallone (D-N.J.), ranking member of the full committee, said the NOPR was not supported by the grid study the department released in August. He asked Perry what analyses the department or its national labs had done to support the proposal.
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Perry did not respond to the question, instead challenging Pallone’s premise. The grid study, he said, didn’t address “with specificity the events I’m concerned about,” he said, citing the 2014 polar vortex. In fact, the report had about 17 references to “extreme weather” or the polar vortex. (See Perry Grid Study Seeks to Aid Coal, Nuclear Generation.)
Perry also sparred with Rep. Michael Doyle (D-Pa.), who said the committee had held eight hearings on markets and reliability. “We’ve actually been having the conversation you claimed to be starting,” he said.
“This has been discussed for a long time, as you rightfully said,” Perry conceded. But he said it was now time for action.
“Our RTO made that adjustment” after the polar vortex, Doyle said, referring to PJM’s Capacity Performance rules, which increased the penalties and bonuses for capacity resources during grid emergencies. “We feel pretty confident with our capacity in Pennsylvania.”
“‘Pretty confident’ is not going to get it [done],” Perry shot back.
Tonko asked if Perry considered consumer costs in developing the NOPR.
“What’s the cost of freedom?” Perry responded. “What does it cost to build a system that keeps America free? I’m not sure I want to put that straight out onto the free market.”
Directive or Conversation?
Perry said the NOPR was intended to “kick-start a national discussion about resiliency and about the reliability of the grid.” Noting the vociferous opposition his proposal provoked, he chuckled, “And best I can tell, we were pretty successful in doing that. … We’re having this conversation now that we really haven’t had in this country.” (See Consumer Advocates Slam Perry NOPR, RTOs, FERC.)
Indeed, at least 50 companies, regulatory agencies and trade groups have intervened or made comments in the docket FERC opened to respond to the NOPR (RM18-1).
Doyle pressed Perry on discrepancies between the NOPR, which repeatedly says FERC “must” act, and the secretary’s repeated references to starting a “conversation.”
“Is it a directive to FERC to do this or a conversation?” Doyle asked.
“Both,” Perry said.
“So, it’s a directive then?” Doyle asked.
“My words are what my words are. I don’t back off from them,” Perry said.
“It can’t be both,” Doyle protested. “So, which one is it?”
“Well actually it is both. It can be both. We can have a conversation and I think [FERC] must move. I think they must act. We’ve kicked this can down the road as long as we need to.”
Perry seemed to acknowledge multiple times that FERC would not be obligated to follow such a directive. Legal experts have said that Perry has no power to make FERC, an independent agency, provide the relief he is seeking. (See FERC’s Independence to be Tested by DOE NOPR.)
Rep. David McKinley (R-W.Va.), who said he was “100% behind” the NOPR, asked if “FERC were to follow through with your missive, don’t you think we’d have a better outcome” than what happened during the polar vortex?
“Well I do, but I mean, that’s why we’re having this conversation here,” Perry answered, saying he wanted to hear from both sides of the issue.
Rep. Kathy Castor (D-Fla.) also said the NOPR conflicted with the findings of the grid study and said it would cost consumers and businesses billions. “There is just no rational basis for this new FERC rule that you’re trying to move through as quickly as possible,” she said.
“If the request … the NOPR to FERC is what you say it is, [FERC] won’t go forward with it,” Perry responded.
When asked by Doyle if he had considered any better alternatives to the NOPR, Perry answered, “I don’t have any idea whether there are any better options. That’s one of the reasons we wanted to have this conversation is to bring those up and discuss them.
“I’m not saying that my letter to FERC is the be-all-end-all, but it’s obviously been very successful in getting the conversation going.”
CARMEL, Ind. — MISO will make two points in its comments to FERC in response to Energy Secretary Rick Perry’s proposal to allow “resilient” resources with a 90-day on-site supply of fuel to fully recover their costs. (See Perry Orders FERC Rescue of Nukes, Coal.)
The first point, according to Executive Director of Strategy Shawn McFarlane: The commission’s response to the Department of Energy’s Notice of Proposed Rulemaking should respect MISO’s existing reliability process that incorporates state rules.
The second: Any monetary value placed on resiliency must be supported by research.
“MISO and MISO states have a well-established process to address reliability and resource needs … and any approach needs to respect those regional processes, and even those regional differences,” McFarlane said at an Oct. 11 Resource Adequacy Subcommittee meeting.
He also noted that “MISO supports a thorough and complete process” for detailing reliability and resiliency attributes, and will urge a well-researched approach.
McFarlane said the 21-day public comment period didn’t provide enough time to collect stakeholder comments and summarize them in MISO’s comments, and he urged stakeholders to make individual filings.
MISO Executive Director of System Operations Renuka Chatterjee echoed McFarlane’s comments a day later at an Oct. 12 Market Subcommittee meeting.
“MISO and the states have well-established processes and initiatives in place to protect reliability,” she said.
MISO will seek a thorough FERC process and sufficient time for the RTO to review any final rule “so we can judge the applicability while respecting regional differences,” Chatterjee said.
“How about the 15-day implementation period?” joked Kevin Murray, attorney for the Coalition of Midwest Transmission Customers, referring to the NOPR provision requiring RTOs to make a compliance filing within 15 days of a proposed rule becoming final (RM18-1).
“I don’t know that 15 days would be sufficient, but all jokes aside, MISO will probably ask for more time to review and assess. Stakeholders that think the 15 days is too short should comment,” Chatterjee said.
MISO Independent Market Monitor David Patton confirmed that he would file comments.
“We’re going to file comments that stress the importance of being careful and reasonable when picking policies,” Patton said. “I don’t know that we understand what [resiliency] is unless it’s related to reliability.”
Patton said he could see the need for resiliency in planning for future contingencies but didn’t know if the concept should be monetized.
“Treating it as a separate idea and pursing it outside the market process is very harmful,” Patton said.
The Public Utility of Commission on Wednesday approved a settlement in Oncor’s proposed swap of more than $400 million in assets with Sharyland Utilities, paving the way for the two parties to complete the transaction (Docket 47469).
The exchange will result in Oncor acquiring 54,000 retail distribution customers and assets from Sharyland, in exchange for 258 miles of Oncor transmission lines in West and Central Texas. The PUC’s approval would also dismiss Sharyland’s current rate case, providing “significant rate relief to our customers,” according to the utility’s CEO, David Campbell.
In 2015 the commission opened an inquiry into Sharyland’s rates, which spiked following the utility’s 2010 acquisition of a bundled package of financially troubled electric cooperatives. Sharyland is owned by the Hunt family of Dallas, which failed in a 2016 bid to buy Oncor.
“The Hunt organization and Sharyland took a lot of arrows from customers and others, for problems that really weren’t of their making,” Commissioner Ken Anderson said. “They were faced with an intractable problem. … This will solve that problem. Oncor didn’t have to do this. It couldn’t have happened but for the agreement of everybody.”
The agreement also avoids an expected rate increase for Sharyland’s retail customers in South Texas.
“Ultimately, the proposed transaction seeks to resolve the rate disparity that currently exists between Sharyland’s high retail electric delivery rates and those of Oncor” and other ERCOT transmission and distribution utilities, the order said.
The commission approved Sharyland’s request to recover up to $17 million in transition costs for the proposed transaction, although it directed the utility to use its “best efforts” to sell any assets not being exchanged and to minimize employee-related transition costs.
The PUC also approved the incorporation of Sharyland’s energy efficiency cost recovery factor (EECRF) and transmission cost recovery factor (TCRF) regulatory assets or liabilities into Oncor’s EECRF and TCRF.
Oncor plans to make its 2018 EECRF effective March 1, 2018, and will include a refund of $6,097,744 for its over-recovered 2016 energy efficiency costs. The transaction, expected to close before March 1, will result in a credit of $243,199 for Sharyland’s over-recovered 2016 energy efficiency costs. That total will be combined with Oncor’s EECRF and be refunded to the appropriate Oncor rate classes.
Oncor is already the largest utility in Texas, with 3.4 million wholesale and retail customers.
The commission’s approval led to a round of back-patting among the parties and commission staff.
“It’s been a long process, with a lot of tricky issues we didn’t anticipate,” said Vinson & Elkins’ Matt Henry, Oncor’s legal counsel. “Staff worked hard to help us fight through the things. Working with Sharyland and their team, there was never a point we didn’t find an obstacle we couldn’t work through.”
“Matt is probably just happy he finally has a change-in-control agreement,” said PUC Executive Director Brian Lloyd.
Schedules Set in LP&L, Sempra-Oncor Cases
The commissioners set tentative hearing dates in a pair of upcoming high-profile cases that will keep them busy well into 2018.
During an Oct. 9 prehearing conference, parties in Lubbock Power & Light’s plan to migrate part of its load from SPP into ERCOT agreed to Jan. 17-18, 2018, hearing dates (Docket 47576).
Lubbock on Sept. 1 filed its formal application to integrate 470 MW of its load with ERCOT by June 2021. That load is currently served through a wholesale contract with SPP member Southwestern Public Service; the contract expires May 31, 2021.
Another prehearing conference is scheduled Monday for Sempra Energy’s attempted acquisition of Oncor (Docket 47675). The PUC has blocked off Feb. 21-23 for a hearing on the merits.
