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.”
Stakeholder sectors have eschewed MISO’s suggestion that they apply equal importance to each of the RTO’s four 15-year future scenarios used for next year’s transmission planning, instead giving more weight to the potential for a slow-and-steady evolution of the generation fleet.
As a result, MISO’s 2018 Transmission Expansion Plan will include a 30% weighting for a continued fleet future, 25% each for limited fleet change and distributed and emerging technologies futures, and 20% for an accelerated fleet change future. The RTO used sector averages and rounded figures to the nearest 5% increment.
Some stakeholders asked why MISO decided to round the averages.
“A percentage here and a percentage there — that doesn’t make a big impact when it comes to project recommendation,” MISO policy studies engineer Matt Ellis said during a Sept. 27 Planning Advisory Committee meeting.
MISO had recommended an equal 25% weighting for all four MTEP 18 futures. Beginning with MTEP 19, equal importance will be assigned to all four grid and generation scenarios, effectively eliminating differential weighting. Staff initially said MISO would abolish weighting beginning with MTEP 18 but changed course in August, explaining that MTEP 18 futures were developed with the understanding that stakeholders would be involved in deciding their importance. (See MISO Delays Removing MTEP Futures Weighting to 2019.)
Minnesota Public Utilities Commission staff member Hwikwon Ham said he supported MISO’s August plan to apply an even 25% likelihood across the board for 2018.
“I share MISO’s concern that we are spending too much time slicing and dicing percentages,” Ham commented, saying that stakeholders were devoting too much time to debating issues that wouldn’t alter project recommendations.
Resource Additions Estimates in MTEP 18
MISO has meanwhile completed a draft projection of future resource additions to inform MTEP 18. The RTO is not projecting much change in resource siting between the MTEP 17 and MTEP 18 futures. However, it created an additional future scenario for the 2018 cycle — the distributed and emerging technologies future — that it predicts will show more than 20 GW of distributed solar in the next 15 years.
Additionally, MISO found that the MTEP 18 futures overall indicate that demand-side and distributed technologies would be spread across more buses in the footprint than in previous cycles.
The futures set out the following scenarios:
In a limited fleet change future, MISO predicts about 32 GW of generation additions and almost 30 GW of retirements, resulting in coal inching forward to take a 51% share of the resource mix by 2032, compared with today’s 48%. Natural gas generation remains unchanged at 24%, while renewables crawl forward to take a 10% share of generation, up from today’s 8% share.
In the continued fleet change scenario, the RTO projects more than 54 GW of additions and just about 38 GW of retirements, with a resource mix consisting of 43% coal, 27% natural gas and 15% renewables.
The accelerated fleet change future yields the most additions at roughly 82 GW, offset by 38 GW of retirements, resulting in 35% coal, 21% natural gas and 30% renewables fleet mix.
In a distributed and emerging technologies future, generation additions hit 70 GW, while retirements slightly exceed 40 GW, producing a mix of 40% coal, 27% natural gas and 21% renewables.
“There are 45 GW of renewables in the definitive planning phase of the interconnection queue set to come online in the next three years,” Ellis reminded stakeholders. “Now, it’s safe to say that not all of that will come online. I’ll leave that to you to determine. But, if you look at historic trends, roughly 60% of projects make it through the queue.”
After a second full review of the 2011 slate of multi-value transmission projects, MISO has concluded that although project costs are rising, benefits still far outpace them.
MISO said its multi-value project (MVP) portfolio creates anywhere from $12 billion to $52 billion in net benefits. Total portfolio costs have increased from an estimated $5.6 billion during MISO’s 2011 Transmission Expansion Plan to $6.5 billion today.
The findings were part of a mandated, three-year review of the MVP portfolio, included in MTEP 17.
MISO’s MVP portfolio was approved by the RTO’s Board of Directors in 2011 and contains 17 transmission projects designed to cut costs, support regional reliability and broaden access to renewable resources. The RTO said its MVPs currently show benefit-to-cost ratios ranging from 2.2:1 to 3.4:1. MISO only measures benefits for its Midwest region, as MISO South was not yet part of the RTO at the time of project approval. In 2014, the RTO put the benefit-cost measure at 1.8:1 to 3:1.
The results also “reconfirm the MVPs are essential to meeting renewable portfolio standards goals,” said MISO engineer Ben Stearney during a Sept. 27 Planning Advisory Committee meeting. MVPs will allow the delivery of 52.8 million MWh of renewable energy through 2031, supporting states’ renewable energy mandates and goals, he said. Had the project portfolio not been approved six years ago, an estimated 11.3 GW in dispatched wind generation would have to be curtailed in 2026. Wind curtailments in MISO are currently rare, due in large part to the RTO increasing dispatch frequency from one hour to five minutes and introducing its Dispatchable Intermittent Resource type, which allows wind operators to respond economically to dispatch instructions.
Stearney said projected natural gas prices represent the largest difference between the MTEP 14 and MTEP 17 reviews, the latter of which shows much lower prices.
MISO will file the MVP report with FERC in spring.
More than half of the $24.3 billion in transmission projects in PJM since 2012 were unneeded to comply with RTO or federal reliability requirements and were not subject to rigorous review, according to a report commissioned by American Municipal Power.
At a teleconference Friday, AMP used the findings to call for more transparency into transmission owner-proposed supplemental projects, which represented $12.7 billion of the total spending since 2012.
Supplemental projects are proposed by a TO and fully paid for by its customers. They are not required to fulfill any reliability obligations from NERC, FERC or PJM, which reviews the projects only to make sure they do not negatively impact the grid. This is in contrast to network upgrades and regionally funded baseline projects proposed by PJM to address violations of RTO, NERC, ReliabilityFirst or TO planning criteria. Supplemental projects also are exempt from the competitive transmission requirements of Order 1000.
Of the $28.1 billion in planned or in-service transmission projects from 2005 to 2012, only 24% ($6.8 billion) were supplemental, according to the report by Ken Rose, an independent consultant and senior fellow at Michigan State University’s Institute of Public Utilities. After 2012, supplemental projects made up 52% of total spending, compared to 48% ($11.6 billion) in baseline projects and network upgrades.
| AMP
“There is a shift from baseline projects to supplemental projects as revenue requirements and transmission rates have gone up, a lot — way beyond the levels of inflation,” Rose said. “Basically, if you continue to have a process where it is fairly easy for the regulated entity to pass project costs through, there is going to be an incentive to continue pursuing supplemental projects.”
PSEG, AEP, PPL Cited
Three TOs — the “overachievers,” as Rose called them — were particularly aggressive in such spending. Between May 9, 2005, and September 2017, supplemental projects represented more than 44% of the transmission spending within the PSEG zone, 40% of spending in the AEP zone and almost 59% of that in the PPL zone.
| AMP
The three TOs also saw their transmission revenue requirements and rates more than double since 2009, with PSEG’s requirements jumping 420% and its rates increasing 465% since 2009, far more than any other TO.
“Those transmission costs that we’ve seen increasing are being passed along to our members,” said Jolene Thompson, executive vice president of member relations for AMP, which provides generation, transmission and distribution to 135 members in Delaware, Indiana, Kentucky, Maryland, Michigan, Ohio, Pennsylvania, Virginia and West Virginia. AMP has “prioritized trying to find ways to mitigate the impact of the increasing transmission costs” on its members, she said, and chief among those is shedding light on the RTO’s supplemental projects.
| AMP
“Our members are seeing their transmission rates skyrocket,” AMP President Marc Gerken said in a statement. “We need to able to tell them why this is happening.”
Aging Infrastructure
At a 2015 FERC technical conference, PJM Vice President of Planning Steve Herling told commission staff that supplemental projects are often proposed to replace aging infrastructure. “If you went down the list in our database, I guess half of them start with the word ‘replace,’” he said. (See PJM TOs Defend Jurisdiction at FERC Conference.)
The conference led FERC last year to issue a show cause order finding that PJM’s TOs were not complying with Order 890’s requirements that stakeholders have “early and meaningful input and participation” in the planning process for supplemental projects (EL16-71). The commission said some TOs “appear to be identifying — and even taking steps toward developing — supplemental projects before providing any opportunity” for stakeholders’ input through the Regional Transmission Expansion Plan. (See FERC Orders PJM TOs to Change Rules on Supplemental Projects.)
While insisting they already comply with Order 890, the TOs in October proposed a Tariff amendment they said would increase transparency. FERC, which had no quorum between February and August, has yet to act on their response.
“PSE&G works closely with PJM and its stakeholders to review and respond to questions about its transmission projects, including supplemental projects,” said Karen Johnson, PSE&G director of communications. “Projects also obtain state and local permits and approvals from state agencies, municipalities, environmental permitting agencies and other local stakeholders. We work closely with all of them to ensure that transmission is built in a cost-effective manner that mitigates environmental impacts and is consistent with customer needs.”
Johnson also said that investment in transmission “puts downward pressure on energy and capacity prices by alleviating congestion on the system” and that ”PSE&G’s electric bills have remained flat to slightly lower over the past nine years.”
AEP and PPL did not respond to requests for comment.
AMP wants to “proceed as aggressively as we can in the current PJM stakeholder process in trying to get the transmission owners to provide a similar amount of information and transparency of data for the supplemental projects as they do for the baseline and Regional Transmission Expansion Plan projects,” Ed Tatum, AMP’s vice president of transmission, said at the teleconference. FERC’s show cause order gives the organization “a good opportunity to get the transparency that we need. But it’s important that those orders be implemented in the spirit with which the commission intended them.”
Asked by RTO Insider why PSEG, PPL and AEP proposed so much supplemental spending, Tatum responded, “I think you make our point for us right there: We don’t know.”
He said PJM should be doing more to protect ratepayers.
“By virtue of being the regional transmission organization … they are in charge of the planning and operation of the system. We see [TO-proposed] projects that come in that talk about building new infrastructure or replacing infrastructure. We have this crazy idea that it’s planning. … There’s certainly an important role for the transmission owners, but at the end of the day we do believe it’s PJM’s process and I think the commission has been clear on that, saying that PJM is in charge of not only the regional but the local planning processes as well.”
“This is a complex issue and one we continue to work through with our stakeholders. It is important to note that there is an active FERC proceeding right now,” PJM spokesperson Paula DuPont said. “We believe in the importance of transparency in all aspects of the planning process and that’s why we’ve been working with stakeholders on it.” She pointed to Planning Community – an online communications platform – and the new Manual 14F: Competitive Planning Process, saying they “demonstrate the value we place on transparency.”
AMP acknowledged that PJM is not alone in seeing increasing transmission costs. But “this supplemental cost category is unique to PJM and those are the ones we really have an issue with because they lack the same rigorous oversight process,” said Lisa McAlister, AMP’s senior vice president and general counsel.
MISO ‘Out-of-cycle’ Controversy
TO-proposed projects also have generated controversy in MISO. In 2015, the RTO approved a $187 million “out-of-cycle” project by Entergy in Lake Charles, La. Transmission developers complained that they had been denied an opportunity to compete on the project, which Entergy had argued was an “immediate need” and thus could not wait for the RTO’s next Transmission Expansion Plan. The complaints led the RTO to change the rules for dealing with out-of-cycle proposals under a new “expedited review” procedure that was added to its transmission planning manual (Business Practices Manual 20) in May 2016. (See Ideas to Reform MISO Out-of-Cycle Process Emerge.)
After two months of significant discussion at various levels of ERCOT’s stakeholder process, the Technical Advisory Committee on Thursday unanimously approved compromise language eliminating the reduction of congestion revenue rights (CRRs), or “deration.”
The nodal protocol revision request (NPRR821) eliminates the deration process for resource node-to-hub or load zone CRRs. Stakeholders drafted compromise language in the Protocol Revision Subcommittee (PRS) to address concerns that the deration process interfered with hedging behavior.
In the end, stakeholders agreed that the language deters the exploitation of CRR gaming opportunities that pose the most risk to loads, and continues the policy of sharing CRR underfunding costs established when the nodal market went live.
“Stakeholders have been working on and debating a solution for three months now,” Reliant Energy’s Bill Barnes said. “Parties on all sides have had follow-up discussions and gotten comfortable with what’s proposed here.”
Reliant Energy’s Bill Barnes (right) makes his point as VEH/Discount Power’s Mohsin Hassan (left) and Just Energy’s Eric Blakey (middle) listen.
“This solution is better than what we had,” Shell Energy’s Greg Thurnher said. “I do believe this particular solution solves the vast majority of the needs. … I suggest we test the waters with this solution and revisit it in the future. The seemingly yearlong discussion may have been unnecessary, but we’ve rid ourselves of unnecessary processes.”
Morgan Stanley’s Clayton Greer (speaking); Shell Energy Services’ Greg Thurnher (left)
The new process will be implemented by July 1, 2019, despite a request by the Lower Colorado River Authority (LRCA), one of those pushing for the change, to deploy it as soon as possible.
“As soon as it’s implemented, we eliminate the risk we’re concerned about,” LCRA’s John Dumas said.
Stakeholders also easily approved NPRR817, which will allow additional trading liquidity and forward price discovery in the Texas Panhandle with the creation of the “Panhandle 345-kV Hub.” The revision excludes the new hub from the existing ERCOT-wide hub and bus average calculations.
Citigroup Energy’s Eric Goff argued the NPRR’s estimated $150,000 to $200,000 implementation costs would be a one-time hit, eased by additions of new hubs in ERCOT’s southern or western footprint.
“I anticipate further need for additional hubs that will reduce the cost substantially each time,” he said. “This NPRR allows very simple hedging for the Panhandle.”
Goff explained that, under current practice, any generator in that area seeking to hedge must pick a resource node that could at times be subject to a random outage because of maintenance or some unforeseen event.
“This will improve the commercial hedging and has one-time upfront costs that address concerns raised by those comments [about costs],” he said.
Staff agreed, saying future hubs could be created at 30 to 40% of the cost of the new Panhandle hub.
TAC Tables Several Market Changes
After a roll call vote following vigorous discussion, stakeholders agreed to table NPRR815, which would revise the current limit of 50% for load resources providing responsive reserve service (RRS) to any capacity above a minimum level of RRS offered by resources providing primary frequency response (PRF).
TIEC legal counsel Katie Coleman
Katie Coleman, legal counsel for Texas Industrial Energy Consumers, asked to table the NPRR following the filing two days earlier of a related revision request (NPRR848), which would create separate pricing for load resources and PRF-capable resources providing RRS. Coleman said she had not yet been able to gather her group’s position on the latest change.
“There’s a relationship between the issues in this NPRR and the issues in 848,” she said. “If 848 moves forward, we would want not only this but probably much more significant changes to how the load megawatts are determined.”
Resolved Energy’s Bob Wittmeyer
The motion to table was opposed by several generating members, who feared reliability issues. Bob Wittmeyer, a consultant with Resolved Energy, pointed to the change’s estimated $3 million in average savings and urged the TAC to considering rejecting the motion to table.
“Tabling this today is not a one-month delay; it’s a two-month delay,” he said. “There are two groups of people in this room — the ones that sell ancillary services and want to table it, and the ones that get fired if we have a reliability problem. The ones that get fired if we have a reliability problem are saying this is not a reliability problem. They’re also saying we can save $3 million a year.”
ERCOT’s Sandip Sharma
ERCOT staff pushed back against claims that grid reliability would be harmed, with Sandip Sharma saying he wanted to “rule out reliability issues.”
“This NPRR allows ERCOT to procure ancillary services in a more cost-effective way, while it is meeting its reliability obligation,” he said. “In the absence of this NPRR, we would do exactly the same study we do today, but we would increase the number, because there is a limitation on load resources. The loads are not allowed to provide more than 50%, especially during the time when they are more effective solving reliability issues … that’s the main issue here.”
Only three members eventually opposed tabling the NPRR.
The committee also tabled NPRR825 and a verifiable cost manual revision request (VCMRR019). Staff said it missed a system requirement in the NPRR’s impact analysis (IA), which likely would increase the costs of issuing DC tie curtailment notices before curtailing the tie’s load.
Dynegy’s Bob Helton, ERCOT’s Kenan Ögelman lead the TAC meeting.
“We’re reviewing the IA process, so we can improve and bring things to you more accurately,” said Kenan Ögelman, ERCOT’s vice president of commercial operations. “That may require us taking more time than we have on some of these, but ERCOT-wide, from the executives to every person, we’re not satisfied with how this is playing out.”
PRS Adds Resource Definition Task Force
The TAC approved a previously tabled revision request (NPRR829), despite a revised impact analysis of between $200,000 and $300,000. The increase came after staff added previously overlooked distributed generation resources in its analysis.
The change requires the day-ahead market to use telemetered data from non-modeled generation to more accurately calculate collateral requirements for qualified scheduling entities (QSEs). The NPRR increases day-ahead liquidity through the increased participation of non-modeled generation, and potentially allows ERCOT to gain near real-time transparency into the generation.
“If we don’t do these infrastructure changes now, it’ll be sometime in the future,” Thurnher said. “It’s not a small segment anymore, in terms of megawatts. The class that will use this will continue to grow in the future. This levels the playing field. Right now, distributed generation does not get the same credit treatment as traditional generation does when it injects into the system.”
The NPRR passed, with three members voting against it.
The committee unanimously approved single NPRRs, nodal operating guide requests (NOGRR) and system change requests (SCR). It also approved ERCOT’s high-impact transmission element list, which doubled last year’s list at 222 elements.
NPRR840: Synchronizes implementation of NPRR782, which removes inconsistencies in protocol language governing the settlement of ancillary services for resources unable to deliver on their responsibilities due to transmission constraints. The change removes the two-hour advance notice period inadvertently left in the protocols when 782 was approved, allowing ERCOT to declare an ancillary service as infeasible in either the adjustment or operating period.
NOGRR173: Removes orphaned grey-boxed language in order to align with NOGRR166, which struck language added with NOGRR084. The change cleans up removal of other items related to NOGRR084 and NOGRR166, but does not remove any current reporting requirements in Section 9.4.3 (Resource-Specific Responsive Reserve Performance)’s duplicative language to the current black-lined language.
SCR791: Populates unused megawatt price values in SCED generation-resource data energy-offer curves with null values rather than zero. The zero values make the energy-offer curves non-monotonic and are indistinguishable from valid zero offers.
