CAISO’s internal Market Monitor on Tuesday provided more details about rising energy prices in the second quarter and extreme day-ahead price spikes occurring over a three-day period during a June heat wave in the West.
The frequency of price spikes In the 15-minute market increased In the second quarter | CAISO
Day-ahead energy prices increased each month in the quarter because of high temperatures that drove up electricity demand, the ISO’s Department of Monitoring said during a stakeholder call Tuesday. The Monitor announced the second-quarter results last week. (See Monitor: CAISO Q2 Prices Hit Record Despite Mitigation.)
“We generally saw them increasing in terms of just seasonal conditions. It wasn’t out of the ordinary,” DMM Market Analyst Kyle Westendorf said. “With the higher temperatures, we saw the higher prices.”
Westendorf did shine more light on events that occurred over several days leading up to June 21, when day-ahead prices hit $600/MWh. His presentation showed that each day over June 18-21 saw less generation bid into the market below $100/MWh, with June 21 wind energy supply coming in below average and down from the previous day. Traders also bid significantly fewer virtual supply offers below $100/MWh into the market between June 20 and 21.
The Day-Ahead market system marginal energy price reached more than $600/MWh on June 21 | CAISO
“One of the things that was happening here, was participants engaging in convergence bidding were shifting away from virtual supply and more towards virtual demand positions in anticipation of higher real-time prices,” Westendorf said.
Convergence bidding refers to financial positions taken in the day-ahead market and liquidated with an opposite transaction in real time. It includes “virtual supply” that looks like a dispatchable energy resource to the market and “virtual demand” that looks like load.
Virtual demand, which is charged the day-ahead LMP, is considered a long position in the market, while virtual supply is paid the day-ahead LMP and is considered a short position. There is no physical transfer of energy in virtual bidding, which is a financial instrument.
Imports into CAISO also significantly declined between June 18 and 19, Westendorf said, and again between June 20 and 21.
“You start to see a pattern now,” he said, adding that the lack of imports was because of extremely high temperatures across the West, creating tight supply conditions across the region, affecting intertie activity and driving some of CAISO’s market results. The stress on the system of heat and high demand pushed the market software solution to a higher day-ahead price, he said.
The ISO and DMM are also investigating why energy prices increased on June 21 after mitigation was applied through computer software. The Monitor has said that, generally, prices should not rise after mitigation.
FERC on Tuesday approved a joint MISO–PJM proposal to create a new category of small interregional transmission projects intended to address historical congestion along the RTOs’ seams.
But the commission’s decision, which clears a path for developing five proposed interregional projects, was conditioned on the RTOs providing their stakeholders with more details about the decisions behind selecting so-called target market efficiency projects (TMEPs) (ER17-718).
In a related order, the commission also approved MISO’s plan for allocating TMEP costs within its footprint (ER17-2246).
FERC staff, in absence of a commission quorum, tentatively approved the TMEP project type in late June. (See FERC Tentatively OKs New MISO-PJM Project Type.) While the commission on Tuesday found the RTOs’ joint operating agreement language creating TMEPs to be mostly consistent with transparency principles in FERC Order 890, their ruling pointed to one missing detail: It did not spell out that stakeholders would “receive a sufficient explanation” about why the RTOs would recommend — or not recommend — a proposed TMEP to their respective boards.
“We find that stakeholders must have this information in order to play a meaningful role in the TMEP planning process and to allow them to monitor and provide feedback on how MISO and PJM are planning transmission projects to alleviate the congestion that is the subject of a TMEP study,” the commission wrote. “Failure to present this information to stakeholders may lead to more frequent after-the-fact disputes regarding the TMEP planning process.”
The commission ordered both RTOs to revise the JOA to show they will provide their Interregional Planning Stakeholder Advisory Committee with supporting explanations behind decisions whether or not to: (1) evaluate a potential TMEP that could economically relieve congestion at a particular flowgate; and (2) recommend an evaluated TMEP to their respective boards. The revision also must include a promise to disclose to stakeholders “any additional criteria used to evaluate potential TMEP solutions.”
MISO TMEP Cost Allocation Approved
The commission on Tuesday also approved MISO’s plan to internally allocate its share of TMEP costs to transmission pricing zones based on their historical contribution to the market-to-market congestion relieved by the project. MISO’s cost allocation also establishes minimum benefit thresholds guaranteeing that no zone will be charged for benefits estimated to be either $5,000 or less, or less than 1% of MISO’s share of the project’s cost.
FERC also accepted a provision stating that, during the Entergy transition period of integrating into MISO, transmission pricing zones within MISO South will not be allocated costs for TMEPs that terminate in other MISO areas or wholly outside the RTO.
“We find that this proposed limitation is generally consistent with the proposal the commission accepted for allocating the costs of new transmission facilities within MISO during [MISO South’s] transition period,” the commission said. “Given the limited duration of the transition period, we conclude that [the] proposal will not prevent MISO’s share of the costs of TMEPs from being allocated in a manner that is at least roughly commensurate with the benefits.”
FERC has not yet ruled on PJM’s regional cost allocation plan submitted in April (ER17-1406).
TMEPs at the Ready
TMEPs are designed to address cost-effective and congestion-relieving seams projects that might otherwise be overlooked because of their low cost and small size. To qualify, projects must cost less than $20 million, be in-service within three years of approval and provide historical congestion relief that is equal to or greater than construction costs within the first four years of operation. Construction costs will be divided among MISO and PJM based on the percentage of congestion relief benefits.
Five such TMEPs have been sitting in the pipeline for the better part of a year, representing $17.25 million worth of upgrades. They expect the projects to deliver a 5.8:1 benefit-cost ratio and realize $100 million in benefits within four years of going into service. (See MISO-PJM TMEP Projects Drop to Five.) Both MISO and PJM plan to ask for respective board approval of TMEP candidates by the end of the year.
MISO-PJM Coordinated System Plan Produces One Project
Meanwhile, MISO and PJM will this month wrap up their two-year coordinated system plan, and they see potential for one interregional project under the more expensive traditional market efficiency project type.
Thayer Morrison transmission project | MISO and PJM
Using their regional benefit criteria, the RTOs point to a new 30-mile, 138-kV line between Northern Indiana Public Service Co.’s Thayer and Morrison substations near the northern Indiana-Illinois border as the only potential interregional project to emerge from the study. NIPSCO expects the line to cost $42.5 million and be in-service by December 2022. If approved, MISO and PJM will split interregional costs based on each RTO’s benefit share and determine a regional allocation.
MISO is eyeing a June 2018 board recommendation for its portion of the project, as it doesn’t yet have in place a cost allocation method for sub-345-kV interregional projects. The RTO said it is “open to additional cost allocation methodologies” and is close to completing a study on a preferred regional cost allocation approach for the projects. For now, MISO has suggested allocating 100% of regional project costs to benefiting local resource zones or transmission pricing zones. MISO hopes to make a regional cost allocation filing with FERC in March 2018.
The U.S. Department of Energy’s proposed rescue plan for at-risk coal and nuclear plants could cost ratepayers $800 million to $3.8 billion annually through 2030, ICF analysts said Wednesday.
The analysts said the wide range is the result of considerable uncertainty about how FERC might implement the Notice of Proposed Rulemaking issued by Energy Secretary Rick Perry last week. The NOPR directed FERC to ensure that nuclear and coal generation in deregulated states with 90-days on-site fuel supply receive “full recovery” of their costs.
But ICF senior vice president Judah Rose said during a webinar Wednesday that he sees “a significant possibility” that FERC will take some action to address the secretary’s “resilience” concerns, especially in the wake of Hurricanes Harvey, Maria and Irma.
“DOE has rarely, if ever, exercised its authority vis-a-vis FERC in this manner. It is even more rare to act with such very tight deadlines — i.e. 60 days, and with such broad regional coverage — it applies to any ISO or RTO with an energy market (day-ahead and real-time) and any plant not subject to state rate of return regulation,” Rose and ICF principal George Katsigiannakis wrote in a blog post. “In the past, most NOPRs originated from FERC directly. Thus, past experience is not necessarily a good guide regarding handicapping the likelihood of implementation. Also, the political environment is without obvious precedent.”
The “lower bound” annual cost of $800 million ($6.6 billion net present value (NPV) at a 7% discount rate) assumes high natural gas prices, normal energy demand, and that units’ fixed operations and maintenance costs are partially recovered in the market.
The “upper bound” cost of $3.8 billion ($31 billion NPV) is based on an expectation of low gas prices and low energy demand with a minimum offer price rule for all regulated units.
The “lower bound” assumes high natural gas prices, normal energy demand, and that units’ fixed operations and maintenance costs are partially recovered in the market. The “upper bound” is based on an expectation of low gas prices and low energy demand with a minimum offer price rule for all regulated units. | ICF
Among the uncertainties, Rose said, is whether FERC seeks to provide cost recovery through energy prices, as proposed in the NOPR, or through capacity prices “because the service is to some degree more akin to a capacity service.”
One particularly important question is whether the rules will include mitigation of buy-side or sell-side market power, an issue not mentioned in the NOPR. If a large share of the generation fleet is subject to rate of service regulation, the analysts said, it could delay retirements and lower supply bids, reducing energy and capacity revenues for remaining units.
If coal plants have bid below costs in the past, prices could increase, but if mitigation is not pursued vigorously, market prices could decrease.
Impact on Gas, Renewables
By reducing coal and nuclear retirements, said ICF Managing Director Michael Sloan, the rule would likely reduce the development of new natural gas-fired capacity by 20 to 40 GW, leading to a reduction of gas demand of as much as 5 Bcfd by 2030, causing gas prices to drop by 4 to 7%.
One uncertainty: whether gas plants with firm pipeline contracts or access to underground storage or local production could qualify for cost recovery.
Renewable generation would be less impacted by the capacity market but could be affected by other FERC actions on price formation, such as restrictions on negative pricing.
The analysts said the NOPR also raised these questions:
Will the rules permit expansions at existing units or reopening of mothballed units? If expansions are allowed, how many megawatts?
Who will set the rate of return and what will be the amortization period?
Why is the NOPR restricted to RTOs and merchant plants? Given FERC’s role in ensuring reliability, “What showing, if any, do rate-of-return states have to show that they have the correct procedures in place to achieve resilience? Will this ultimately apply to all jurisdictional transmission providers?”
“This NOPR could have a major impact on the industry and markets, and could be a huge game changer for baseload plants. Timing is unclear along with most of the details. The only certainty is the uncertainty that this will create in the marketplace as the rule is developed and the details debated,” said the analysts, who questioned whether upcoming capacity auctions in ISO-NE (January 2018) and PJM (May 2018) and monthly auctions in NYISO will be delayed.
Sempra Energy said Wednesday that it has reworked its proposed $9.45 billion acquisition of Oncor with a new financing structure that wipes out the debt of the utility’s parent company, Energy Future Holdings.
Sempra on Thursday submitted a change-in-control filing with the Public Utility Commission of Texas (Docket 47675) that adds the new financial provisions and offers 47 regulatory commitments, possibly clearing the way for a regulatory approval that eluded previous Oncor suitors.
The California-based company’s top executives told financial analysts Wednesday that the joint application with Oncor stems from discussions with key Texas stakeholder groups and guidance from Oncor CEO Bob Shapard and General Counsel Allen Nye.
Sempra CEO Debbie Reed | Sempra Energy
“We’ve learned a lot from meetings in Austin and working with Oncor’s senior leadership,” CEO Debra Reed said. “We believe the revised financial structure addresses concerns made by certain stakeholders … and substantially addresses many of their key issues.” (See Sempra Begins ‘Listening Tour’ of Key Stakeholders.)
Reed said stakeholder groups likely to participate in the case — PUC staff, Texas Industrial Energy Consumers, a coalition of cities served by Oncor and the Office of the Public Utility Counsel — have agreed to continue working on regulatory settlement discussions with Sempra and Oncor representatives.
“We do feel this improves our likelihood of being able to reach regulatory resolution,” she said. “We made a conscientious decision to make this change after we got a lot of stakeholder input. One of their greatest concerns was the holding company debt. We thought addressing those issues up front would help us get regulatory approval.”
The previous financing arrangement would have added $3 billion in new debt to Oncor, but Sempra’s revisions essentially match a previous deal intervenors agreed to with Berkshire Hathaway Energy. Sempra out-bid Berkshire in August. (See Sempra Outmuscles Berkshire for Oncor.)
Sempra expects to fund approximately 65% of the EFH purchase with equity and 35% with company-issued debt, eliminating the need to rely on third-party investors. CFO Jeff Martin said the “simpler and more conservative financing approach” will erase the EFH debt. Sempra’s original proposal would have given the company 60% of EFH, with the goal of acquiring 100% over a period of time.
“Our revised financing structure for the transaction is both clear and simple. This eliminates the need to take future additional steps to achieve full control of EFH,” said Martin, noting it will allow Sempra “to fund additional growth initiatives.”
Wall Street was cool to Sempra’s revised financing proposal. The company’s stock lost $2.63 off Wednesday’s close of $114.57/share, a 2.30% drop. It finished the week at $111.95/share.
Florida-based NextEra Energy has its own application for a share of Oncor before the PUC (Docket 47453), seeking the remaining 19.75% interest owned by a collection of private-equity funds operating under the name Texas Transmission Holdings Corp. (See Texas PUC Resistant to NextEra’s Minority Interest in Oncor.)
Sempra Energy’s headquarters | Sempra Energy
Asked about acquiring the minority interest, Reed reminded analysts, “We have said over time we would like to own the entirety” of Oncor.
Sempra’s regulatory commitments “are intended to preserve the independence of Oncor and help ensure that Oncor is protected for the customers it serves in Texas … and able to continue to perform in accordance with its financial plans for its customers and shareholders,” Reed said.
The regulatory commitments include:
Preserving Oncor’s board independence;
Maintaining the utility’s current management team, workforce and Dallas-based headquarters;
Not incurring any debt at EFH as part of the transaction or in the future;
Keeping strong ring-fence provisions to maintain both legal and financial separation among Oncor, Sempra and their affiliates;
Ensuring Oncor’s customers don’t bear any of the transaction costs; and
Supporting Oncor’s five-year, $7.5 billion capital investment plan.
NextEra’s inability to abide by similar ring-fencing measures imposed by the PUC sank its own bid to acquire Oncor earlier this year. The commission also rejected Dallas-based Hunt Consolidated’s attempted acquisition over concerns that taxing savings wouldn’t be shared with Texas ratepayers.
With the filing, the PUC now has 180 days to render a decision. The 2017 state legislature approved a bill that was recently signed into law giving the commissioners an extra 60 days if they find “good cause.”
Sempra and Oncor already cleared one regulatory hurdle after a U.S. Bankruptcy Court in Delaware approved the merger agreement in September. (See Bankruptcy Court Advances Sempra Bid for Oncor.)
The agreement remains subject to customary closing conditions, including further approvals by the PUC, Bankruptcy Court, FERC and the U.S. Department of Justice.
FOLSOM, Calif. — California agencies are finalizing a roadmap for commercializing microgrids in the state, aligning with a $45 million grant funding opportunity for the technology.
“We had a huge amount of questions and answers — in fact, the largest we have had for any solicitation,” Mike Gravely of the California Energy Commission said at an Oct. 2 workshop to discuss the funding initiative. He cautioned that the roadmap is still preliminary and that his agency is “very much interested in the consensus of the industry.”
Microgrids — independent, controllable energy systems with a single point of interconnection to the grid — are increasingly being studied as an option to help integrate renewables, not just in the U.S., but also in Europe and Asia, where solar development is on the rise.
The commission is taking comments through Oct. 28 on its draft roadmap for commercializing microgrids, issued late last month. The agency is offering grants for microgrid development in the state on military bases, ports and tribal lands; in low-income and rural areas; and at industrial complexes and local schools. (See California Awarding $45 Million for Microgrids.)
The funding opportunity is the second to be issued by the commission, and a third one is under review and due to be released by the end of the year. Earlier solicitations provided more than $70 million for 18 to 20 microgrids.
“We will be a big player in this market,” Gravely said, adding that a lot of the activities in the roadmap will be implemented through a CEC research process before going to the California Public Utilities Commission and CAISO, and some will be implemented through existing proceedings.
Some questions around microgrid implementation remain unanswered, including who carries the costs, who pays for interconnection and what fees will apply to microgrids. While there are no particular legislative or regulatory directives to develop microgrids, the issues around their implementation cross over other state proceedings on interconnection, energy storage and distributed energy. The PUC’s “Distributed Resources Plans” proceeding has authorized development of two microgrids: one in Borrego Springs, in San Diego Gas & Electric territory, and another in Mono County, in Southern California Edison’s area.
The services model for microgrids is still evolving, Adam Forni of Navigant Consulting said in a presentation on a recent global survey of the technology. Almost every microgrid in California uses solar in conjunction with energy storage, while overseas applications often utilize back-up diesel generation.
The projects examined in the Navigant study, which is meant to help the CEC shape the roadmap, had to be at least 50% privately funded and be already online or commencing operation within the next year. Navigant studied nine projects in California, 10 others on the North American continent and seven additional projects in China, Singapore, Hawaii, India, Japan and Mozambique. International and North American projects were built more for reliability, while California projects were designed mainly to meet environmental goals.
Facilities included commercial hosts, government entities, landfills, affordable housing, agriculture and food production, with most rated at 1 MW or above and three larger than 10 MW. Navigant recommended that the state focus research and development on technologies that enhance integration to reduce reliance on diesel generators, not to limit funding to just solar plus energy storage and to incorporate more diverse renewable sources. The consulting group also recommended considering the other benefits that microgrids can provide outside of electricity, including thermal energy, water and waste management solutions.
AUSTIN, Texas — A panel of CEOs from some of Texas’ largest energy companies on Tuesday panned U.S. Energy Secretary Rick Perry’s directive that FERC consider supporting struggling coal and nuclear plants.
Or, as former FERC Chairman Pat Wood III put it in setting up the discussion at the Gulf Coast Power Association’s Fall Conference: “This lovely little Christmas turd that showed up on our desks.”
Wood agreed with the consensus opinion that Perry was within his legal rights to issue his Sept. 29 Notice of Proposed Rulemaking to FERC, which suggests compensating baseload plants in deregulated states for preserving the grid’s reliability and resilience. (See FERC’s Independence to be Tested by DOE NOPR.)
Still, Wood, who also chaired the Texas Public Utility Commission during part of Perry’s tenure as the state’s governor, said he was caught off-guard by the NOPR.
“It was a pretty big deal for me. First thing, it was signed by the governor of this state, that made this room as big as it is,” he said, motioning to a large ballroom filled with conference attendees.
“It was his regulatory approach that allowed this state to benefit tremendously from competitive markets. It also ran counter to some of the key provisions of his staff’s grid study report, especially when talking about the unending cycle of subsidies,” Wood said.
Asked whether Perry’s letter was a “cannon” aimed at the RTOs or the natural gas industry, Dynegy CEO Bob Flexon said, “It’s going to really impact PJM, where coal and nuclear plants are surrounded by Marcellus and Utica natural gas [plays], and in Illinois.”
PJM stakeholders have questioned the RTO’s focus on being cost-based and resource-neutral, while Illinois joined New York in issuing zero-emission credits to keep Exelon nuclear plants running. (See PJM Stakeholders Offer Different Takes on Markets’ Viability.)
“I don’t view it as negative to anyone,” Southern Power CEO Buzz Miller said. “I think it really is just the best way they could find to really prop up coal and nuclear in the competitive markets.”
“Certainly, the [Department of Energy] proposal tries to define resiliency in the form of fuel certainty, said NRG Energy CEO Mauricio Gutierrez. “The narrow definition in this proposal is coal and nuclear, the people with fuel certainty on site.
“To us, resiliency is more than that. It’s the characteristics an asset brings to the grid; whether it can withstand that type of disaster or come back significantly quicker. That characteristic has to be fuel-neutral.
“We have to think about the power delivery,” Gutierrez continued. “Are we recognizing, and pricing correctly, the resiliency value some of our power plants provide the system? If you have a generation unit that is required for reliability and resilience, then let that unit set the marginal price. There are ways to tackle this issue in a fuel-neutral way.”
“We have a long history of disasters in the Southeast, and it’s the distribution and transmission that usually goes down. … The vulnerability is the wire,” Miller pointed out. “It looks like they tried to come up with a scenario that makes coal and nuclear stand out. The problem is, if an electromagnetic pulse happens, nuclear units have more digital parts. It’s hard to cherry pick your disaster scenario and plan around that. … Generation can recover quickly, but it’s the wires that take time.”
Flexon, who manages a fleet with a 60/40 gas-to-coal ratio, said Perry’s letter was a result of hard lobbying by two unnamed energy companies.
“The subsidy war is alive and well,” Flexon said. “For years, we turned a blind eye to wind getting subsidies. Now, nuclear is getting subsidies and it’s disrupting the markets. That letter is just a new subsidy entering the space. This is designed to counter the effectiveness of the marketplace and save assets that should be exiting the market.
“Even though we’re a fairly large coal generator, we’re not supportive of [Perry’s memo]. We believe policy should be fuel-neutral. But if someone is going to pay us a return for our plants with 90 days’ worth of fuel on site, we’ll find a way to store 90 days of fuel at every one of our coal plants.”
Flexon noted the DOE study this summer focused on price formation, but that the generation stack has changed in the last 20 years.
“Energy price formation needs to change too,” he said. “You just can’t ignore the fact the generation stack has changed dramatically. How you price energy has to keep up, so you have new investment coming in and you’re getting the most efficient megawatts to the customer.”
Gutierrez agreed, saying Perry’s memo may have been aimed at energy markets, such as ERCOT’s.
“We need to improve the markets, and this may be the catalyst that does it,” he said.
Energy Groups Seek Longer Response Deadline
In a related development, 14 energy trade groups asked FERC on Tuesday to extend the comment periods in the commission’s consideration of the directive (RM18-1).
Perry’s NOPR called for final action on the proposed rule within 60 days from its publication in the Federal Register. On Monday, the commission issued a notice setting an Oct. 23 deadline on comments on the proposal, with reply comments due Nov. 7. (See FERC’s Independence to be Tested by DOE NOPR.)
The trade groups’ filing requests that FERC set a 90-day initial comment period and a 45-day reply comment deadline.
“The proposed reforms laid out in the NOPR, if finalized, would result in one of the most significant changes in decades to the energy industry and would unquestionably have significant ramifications for wholesale markets under the commission’s jurisdiction,” the groups said. “When agencies consider a proposed rule that could affect electricity prices paid by hundreds of millions of consumers and hundreds of thousands of businesses, as well as entire industries and their tens of thousands of workers, such as the proposal in question, it is customary for an agency to allow time for meaningful comments to be filed in the record so that the agency can make a reasoned decision thereon. In fact, agencies are under an obligation to allow a comment period of not less than 60 days for typical rulemaking proceedings, unless exceptional circumstances exist.”
Signing the joint motion were: Advanced Energy Economy, American Biogas Council, American Council on Renewable Energy, American Petroleum Institute, American Public Power Association, American Wind Energy Association, Business Council for Sustainable Energy, Electric Power Supply Association, Electricity Consumers Resource Council, Energy Storage Association, Interstate Natural Gas Association of America, National Rural Electric Cooperative Association, Natural Gas Supply Association and the Solar Energy Industries Association.
FERC has approved SPP’s request to change the frequency of its regional cost allocation review (RCAR) from every three years to every six, overruling member objections. The change became effective Oct. 1.
Sunflower Electric Power and Mid-Kansas Electric protested the tariff change, saying problems with the RCAR’s study assumptions, analysis and results made it unreasonable to decrease its frequency. The commission ruled their concerns as being out of scope (ER17-2229).
In their Sept. 29 order, commissioners said that while Sunflower and Mid-Kansas “may be correct that a relatively small change in transmission investment could have a large effect, that does not persuade us that conducting a mandatory review of the entire cost allocation methodology every six years instead of every three years is unjust and unreasonable.”
SPP and the commission both noted that any member that believes it has an imbalanced cost allocation can request relief through the RTO’s Markets and Operations Policy Committee. The RTO has also said it is trying to improve the review process by using more accurate information.
Stakeholders approved the Regional Allocation Review Task Force’s revision request in April, based on its recommendation that the change would save SPP manpower and consulting costs. (See “RSC Approves Six-Year Cost Allocation Review,” SPP Regional State Committee Briefs.)
The most recent regional cost review (RCAR II) showed more positive benefit-to-cost ratios and only one deficient transmission zone, which already has a project in the 2017 Integrated Transmission Planning assessment.
SPP said it took about 2,100 employee hours and more than $417,000 in payments to outside consultants to complete that review. The two RCARs have cost more than $1.5 million in outside consulting just to conduct the analysis, and each study has taken at least six months to complete, according to the RTO.
BURLINGTON, Vt. — Vermont isn’t just moving in the right direction on renewable energy; it’s helping to lead the country despite — or because of — its modest size, the state’s top regulator told attendees at a recent conference.
“Unlike New York and California, which want to lead on energy, Vermont is not a battleship, we’re a PT boat, so we can turn on a dime,” Vermont Public Utility Commission Chair Anthony Roisman said Oct. 2 at the Renewable Energy Vermont (REV) Conference.
Gov. Phil Scott appointed the 79-year-old Roisman as chair in June.
Vermont is one of the top two states nationwide in terms of clean energy employment as a share of the workforce. The 13,000 jobs created in the state’s sector since 2000 represent 6% of the state’s workforce, REV Executive Director Olivia Campbell Andersen said at the conference.
When Roisman served on the siting board for New Hampshire’s Seabrook nuclear plant 40 years ago, the people interested in renewable energy wouldn’t have filled one table, he noted. In contrast, the REV2017 Conference drew hundreds of people who not only promote renewable energy, but also work in the field.
Kerrick Johnson with Vermont Electric Power Co. asked Roisman how long he expects to serve in his current role, given his age.
“I have a six-year term and I can’t predict who the governor will be in six years, but I don’t see any finite limit to how long I will serve,” Roisman said. He noted that Berkshire Hathaway CEO Warren Buffett is 87 and U.S. Supreme Court Justice Ruth Bader Ginsburg is 84. “I feel as though I’m a little young for the position, but I’m hoping to make up for that with my enthusiasm and energy.”
During the conference, state officials described how they see Vermont, like the U.S., as standing at a critical crossroads in terms of both climate change and politics.
“When we have a federal government that abdicates its responsibility to protect its people and our environment, the attorney general’s office will be the first line of defense and the last line of defense,” said state Attorney General T.J. Donovan.
“Now we’re realizing that democracy is not just on election day, but all the time,” Lt. Gov. David Zuckerman said.
The growing season is going to be longer and both wetter and drier at the same time, he said.
“You say, ‘How is that possible?’ But we’ve seen it this year,” said Zuckerman, who owns a farm in Hinesburg. “This summer was one of the worst growing seasons, at the beginning of the season, that any farmer I know has seen, with incredible rains for a long time. And now my pond is almost empty because for the last month and a half it’s been very, very dry.”
Project Siting and Policy
Conference panelists also discussed how a 2016 state law that calls for greater local government involvement in the generation siting process has exacerbated the NIMBY syndrome.
The law (Act 174) represents “a big change from the status quo,” according to Alex “Sash” Lewis, a lawyer with Dunkiel Saunders Elliott Raubvogel & Hand. In the past, state officials had to give “due consideration” to local and regional planning standards when siting resources, but now they must give “substantial deference” to those requirements.
“The PUC is now going to be considering specific municipal plans,” he said.
The law establishes a new set of energy planning standards that municipalities and regions can adopt on a voluntary basis, earning them the right of substantial deference in the siting process. Regions and municipalities that do not wish to update their plans will continue to receive due consideration in the process.
Jon Copans of the Vermont Council on Rural Development considers that holistic approach to energy planning to be a good thing: “You can’t just look at the electric sector without considering many others.”
Catherine Dimitruk of the Northwest Regional Planning Commission pointed to a correlation between prime wind areas and nature conservation areas. She said her commission has a goal of developing 19 MW of new wind generation in the northwestern part of the state, to be achieved only through small-scale wind, and is relying on evolving technology to make it possible.
Kimberly Hayden, a lawyer with Paul Frank + Collins, said that in the past five years “our CO2 footprint has gone up 2.5% because, while we are retiring nuclear, we’re replacing it with natural gas-fired generation.” The New England Power Pool’s Integrating Markets and Public Policy process “looks very promising … but it’s very political.”
New York and Illinois are doing interesting work, but New York’s Value of Distributed Energy Resources Phase II process “will be going on until the end of time, which scares me,” said Nathan Phelps of advocacy group Vote Solar. “The market is really hurting in New York right now because of uncertainty, which scared off a lot of developers.”
VALLEY FORGE, Pa. — Discussion at PJM’s Transmission Replacement Processes Senior Task Force has not advanced much in the four meetings the group has held since being reactivated in late July, but the rhetoric has softened.
The PJM Transmission Owners, their customers and RTO officials all took that as a positive sign at the task force’s most recent meeting Wednesday. Throughout the meeting, all sides thanked each other for the cooperative tone.
“We don’t think we’re that far apart,” American Municipal Power’s Ed Tatum said. AMP’s Lisa McAlister hoped it wasn’t overly optimistic to anticipate that the group might agree on a joint filing to FERC. Participants agreed to define “end-of-life” at the next meeting on Oct. 25 and determine what transmission equipment should be included in that definition.
Hiatus
The atmosphere was a far cry from the Markets and Reliability Committee meeting in July, where load interests blocked TOs’ attempt to continue the task force’s 10-month hiatus. (See Load Blocks TO Effort to Delay PJM Tx-Replacement Talks.)
The hiatus began last September, after FERC questioned whether the TOs’ procedures for planning supplemental projects provided stakeholders opportunity for “early and meaningful input and participation” as required by Order 890 (EL16-71).
Supplemental projects are proposed by TOs to meet local needs, but they are not required by PJM’s reliability, economic efficiency or operational performance criteria. Their costs are paid by the TO zone and are not regionally allocated, unlike baseline upgrades resulting from the RTO’s Regional Transmission Expansion Plan.
The commission’s show cause order directed the TOs to file rule revisions, or counter with evidence that they were already in compliance, within 60 days. The TOs responded Oct. 25, contending that the Operating Agreement already complies with Order 890 but also proposed a Tariff amendment, Attachment M-3, that they said would improve transparency. Attachment M-3 would institute an annual stakeholder review of TOs’ assumptions and methodology. It also would require TOs to present their view of local transmission needs and proposed solutions for stakeholder comment.
FERC, which was without a quorum between February and August, has not ruled on the filing despite promising it would act within about three months of the TOs’ response.
At last week’s task force meeting, Exelon’s Gloria Godson reviewed a timeline of the issue and a summary of the proposed amendments.
AMP followed with a presentation that compared the TO’s suggested changes through the M-3 proposal to changes AMP proposed to the PJM Operating Agreement, Schedule 6, Regional Transmission Expansion Planning Protocols. AMP’s position would apply the same PJM process used for baseline project planning to end-of-life project planning, which Tatum said would result in the PJM Members Committee retaining filing rights under Section 205 of the Federal Power Act as opposed to shifting filing rights to the TOs as the M-3 proposal would do.
The organization said it was focused on the processes to determine when infrastructure has reached the end of its serviceable life and how it gets replaced. (On Friday, AMP released an analysis showing that more than half the transmission spending in PJM since 2012 was on supplemental projects. See related story, Report Decries Rising Tx Costs; Seeks Transparency on TO Projects.)
RTEP Process ‘Working Well’
Mark Ringhausen of Old Dominion Electric Cooperative called for pulling the TOs’ local planning for certain Supplemental projects into the RTEP process and requiring designated entity agreements between PJM and the transmission developer to set expectations and remedies for nonperformance for better PJM planning models. He said it would “provide consistency and transparency across all the TOs and PJM if we use a process that’s been working well for the past 15 years.”
He and AMP also asked for one-line diagrams to be provided for some project presentations, which they said would speed up meetings and reduce their questions and information requests.
TOs hesitated to agree to the one-line requests in public meeting materials, citing Critical Energy/Electric Infrastructure Information (CEII) concerns and that they often lack comprehensive information when projects are presented. But they said that the information is available with appropriate CEII protection. PJM acknowledged the concerns. The TOs noted that they provide project maps during the planning process, which they said serve a similar purpose, but AMP and ODEC disagreed.
Frustration
The hesitation has frustrated customers, who said they’ve heard the same arguments before and that other PJM stakeholder groups “don’t seem to have a problem working” while awaiting the FERC decision.
“You’re working very hard to improve the process without asking us what we want or need,” McAlister said.
PPL’s Frank “Chip” Richardson said the TOs are not willing to discuss augmenting what they’ve already filed at FERC but will consider other items.
Godson stressed the gravity of the show cause order, noting it “is not something that happens often.”
“Unfortunately, FERC failed to issue an order within three months as indicated due to the lack of a quorum,” she added.
GT Power Group’s Dave Pratzon said he doesn’t have a direct interest in the dispute, but he suggested that the customers list their requests and that the TOs then indicate which of them they can talk about “rather than have everybody dance around the table.”
“Let’s get to the substantive work. We’re tired of having this same discussion. We understand the TOs’ litigation position and believe that what we’re proposing is within the bounds of the task force’s charter and not that far off — from a substantive perspective — from what the TOs proposed,” McAlister said.
“I would love nothing better than to engage in a productive discussion with the TOs on this. I can’t make them love me. … I can’t force them to do that. But we do have an MRC-approved taskforce and charter with things to work on,” Tatum said. “There’s lots of opportunities to do productive things here. There’s one group who won’t play.”
“It’s not that we won’t play. We’re here. We have considered things,” Richardson responded. “Just because we’re not willing to negotiate what is pending at the FERC in a stakeholder forum — and require the task force to work within its charter — doesn’t mean we’re not willing to play.”
FERC last week granted NYISO a waiver of its shortage pricing rules, giving the ISO time to align its Tariff with its market software (ER17-758).
NYISO requested the waiver after its Market Monitoring Unit discovered that the ISO’s software had not been calculating prices in accordance with the Tariff language since it implemented transmission shortage cost pricing in February 2016.
| NYISO
The MMU, Potomac Economics, reported the problem to the ISO at the end of August 2016. After further investigation, the ISO told stakeholders Nov. 3 that the inconsistencies constituted a “Market Problem” because they had materially impacted its markets.
The ISO asked FERC to waive the relevant Tariff provisions from Feb. 11, 2016, until the Services Tariff was revised — as occurred June 14, 2017, when the commission accepted the ISO’s proposed revisions, under delegated authority.
“NYISO now realizes that it inadequately explained the pre-existing logic for its software and the interaction of this logic with the graduated transmission shortage cost provisions,” FERC recounted.
Noting that no commenters opposed the waiver, the commission said that the ISO had “acted in good faith and worked diligently with MMU and its stakeholders to resolve the inconsistency.”
