ERCOT on Wednesday asked Texans to reduce their electricity usage Thursday and Friday, when the state is expected to see some of the highest temperatures of the year amid tight reserve margins.
The National Weather Service expects temperatures to reach triple digits in all the state’s major metropolitan areas through Sept. 7. The grid operator issued an extreme hot weather alert on Tuesday for Friday and Saturday.
ERCOT is projecting peak demand of 72.7 GW on Thursday and 73.3 GW on Friday. That would smash the two new September demand records of more than 68.4 GW set earlier this week, which themselves were more than 1.5 GW above the previous mark set in 2016.
“ERCOT’s job is to ensure power is available all over Texas,” CEO Bill Magness said in a statement. “When electricity demand and heat reach levels like we expect on Thursday and Friday, we ask Texans to consider taking a few steps to help keep power flowing for all of us.”
Public Utility Commission Chair DeAnn Walker echoed Magness’ comments and noted the stress placed on generators by the sustained high temperatures.
“Operating at high efficiency like this can be a bit of a balancing act, so the PUC and ERCOT are working together to encourage Texans to conserve on Thursday and Friday afternoon,” she said in a statement.
The markets are expecting real-time prices to spike along with the temperatures. Thursday prices in the day-ahead market were settling on Wednesday afternoon at just over $5,000/MWh for the 5 p.m. hour.
Heat will be a major factor during Saturday’s Texas-LSU game. | Texas Sports
ERCOT expects to see the same trough of early afternoon wind generation that, combined with nearly 5 GW of generation outages, replicates the situations that led to the grid operator calling two energy emergency alerts (EEAs) in August. Prices hit the $9,000/MWh limit during both EEAs. (See “ERCOT CEO Briefs Commission on Summer Performance,” Texas PUC Briefs: Aug. 29, 2019.)
However, the grid operator expects demand to be higher this week than it was during the EEAs.
ERCOT began the summer with an 8.6% reserve margin. It set a new all-time peak of 74.7 GW on Aug. 12, and it has recorded 11 other demand marks above the record set a year ago. Last year, ERCOT broke its previous record 14 times.
Austin, home to ERCOT, exceeded 100 degrees Fahrenheit during 27 of August’s 31 days.
FirstEnergy Solutions asked the Ohio Supreme Court on Wednesday to block a vote to repeal $150 million in subsidies for its two nuclear plants.
The company argued the new ratepayer fees — ranging from 80 cents up to $2,400/month — are equal to a tax, making the underlying legislation, House Bill 6, ineligible for the petition that Ohioans Against Corporate Bailouts is currently circulating for a ballot referendum. (See Ohio Nuke Ballot Petition Approved.) The lawsuit names both the group and Secretary of State Frank LaRose, the state’s chief election official, as defendants.
“The charges levied by House Bill 6 are a tax and laws providing for the levy of a tax are exempt from a referendum under the Ohio Constitution,” said Tom Becker, an FES spokesperson. “The referendum is inherently misleading and confusing to Ohio voters. Ohioans and the state of Ohio should be spared the costs associated with this futile attempt to place this unconstitutional referendum on the ballot.”
Perry Nuclear Power Plant, located about 40 miles northwest of Cleveland
FES requested a truncated timeline giving the anti-subsidy group (referred to in the lawsuit as the respondents committee) just five calendar days for a response. Briefs on the merits would be due from FES in another 15 days and from the committee 15 days after that before potential oral arguments.
Meanwhile, Ohioans Against Corporate Bailouts has until Oct. 21 to gather almost 266,000 signatures for the referendum to appear on the November 2020 ballot.
“Time is of the essence in this case because the respondent committee, within the last few days, has started undertaking a misleading and ultimately futile solicitation of voter support and signatures for the committee’s illegal referendum effort,” FES wrote. “It is inherently misleading and confusing to Ohio voters for the respondent committee and its circulators and other agents to circulate and file a referendum petition that states, implies or otherwise suggests that H.B. 6 is subject to a referendum when that is not true.”
Gov. Mike DeWine signed the Ohio Clean Air Act into law on July 23 after months of debate over whether the Davis-Besse and Perry nuclear plants were worth saving. (See Ohio Approves Nuke Subsidy.) FES, currently negotiating a Chapter 11 bankruptcy settlement plan, said both facilities would close without the subsidies — taking 4,300 jobs and most of Ohio’s carbon-free emissions with them. The act replaces the state’s renewable energy mandates with ratepayer surcharges to support the reactors and two Ohio Valley Electric Corp. (OVEC) coal plants.
Gene Pierce, spokesperson for Ohioans Against Corporate Bailouts, blasted the lawsuit in an emailed statement that called into question FES’ legal standing and state lawmakers’ own attempts to frame the bill as anything but a tax.
“This frivolous lawsuit is another desperate attempt by FirstEnergy Solutions to protect their ill-gotten billion-dollar bailout,” he said. “In addition to having no legal basis, their own proponents in the legislature repeatedly stated that H.B. 6 was not a tax increase in their efforts to secure enough votes for passage of the bill.”
The Western Energy Imbalance Market is poised to expand across Northern California after three municipal utilities and the Western Area Power Administration’s Sierra Nevada (WAPA SN) division jointly announced they intend to join the growing real-time market.
The Balancing Area of Northern California (BANC) and WAPA said Wednesday they will sign an implementation agreement with CAISO that would allow WAPA SN and BANC members Modesto Irrigation District (MID), Redding Electric Utility and Roseville Electric Utility to begin trading in the EIM in April 2021. The decision does not affect any other WAPA regions.
The agreement represents the second phase of BANC’s approach to incorporating its members into the EIM. Sacramento Municipal Utility District (SMUD) entered the market in April. (See SMUD Goes Live in Western EIM.)
“BANC is excited to expand its participation in Phase 2 after becoming the first publicly owned agency to become an EIM entity,” BANC General Manager Jim Shetler said in a statement. “The success of Phase 1 … and the benefits we’ve realized encouraged more of our public power members to participate. We expect the transition will be as smooth for Phase 2 as it was for Phase 1.”
BANC members Modesto Irrigation District, Redding Electric and Roseville Electric will join the Western EIM in spring 2021, along with WAPA-SN. | BANC
While SMUD represented the first publicly owned utility to join the EIM, WAPA SN would be the first federal power marketing agency to participate. The Bonneville Power Administration, which operates about 15,000 miles of transmission in the Pacific Northwest, has begun a multiyear effort to examine EIM membership. (See Customers Probe BPA on EIM Impact.)
WAPA SN primarily markets wholesale power generated by the U.S. Bureau of Reclamation’s Central Valley Project, which includes the Shasta, Folsom, Trinity and New Melones dams. Its customers include towns, rural electric cooperatives, public utility districts, federal and military agencies, and Native American tribes in Northern and Central California and parts of Nevada.
Together with BANC, the agency is part owner of the California-Oregon Transmission Project, a 340-mile, 500-kV line that links BANC’s balancing authority area to BPA’s territory. The two connect via the Captain Jack substation in Southern Oregon, one of two major transfer points for energy flowing between the Northwest and California.
“Joining the Western EIM will help SN ensure the reliable delivery of our hydropower while adjusting to a changing energy mix. Given our footprint within the BANC balancing authority area, the Western EIM is the best fit for SN,” WAPA SN Regional Manager Sonja Anderson said.
MID provides electricity to more than 122,000 customers and irrigation water to 2,300 agricultural accounts in California’s Central Valley. The utility’s portfolio consists of about 66 MW of hydroelectric resources and 389 MW of gas-fired generation, including three peaking units.
“Joining the EIM will provide MID continued access to the market’s diverse, readily-available power resource mix,” MID General Manager Scott Furgerson said. “Access to this low-cost, growing pool of resources will also further ensure and enhance service reliability to our customers.”
MID estimates it will incur $3.3 million in start-up costs and about $1 million in annual expenses to participate in the EIM, with recovery anticipated within three years.
Redding Electric serves more than 42,000 residential and commercial customers within the city of Redding and owns 83 MW of gas-fired generation. With about 53,000 customers, Roseville Electric obtains most of its power from its own gas-fired generation and WAPA.
BANC members Shasta Lake and Trinity Public Utilities District have not committed to the EIM.
The task team examining changes to how MISO selects its Board of Directors is closing in on a set of recommendations that could alter eligibility requirements for future members.
Among the possible suggestions? Reserving a board seat for candidates who have experience representing the interests of utility customers.
The Board Qualification Task Team (BQTT) could offer up that and more later this month at MISO Board Week in St. Paul, Minn.
Jennifer Easler, an attorney with the Iowa Office of Consumer Advocate, said the move would ensure customer views are better represented on the board.
“I believe the current structure is more heavily dominated by industry perspectives,” Easler said during a Sept. 3 BQTT conference call. “I believe the price of particular initiatives is something good to keep in the forefront.”
Easler said she envisioned the position being filled by anyone with experience advocating for consumer interests, whether at a public or non-governmental organization. She said it would be helpful for RTOs to be more cost-conscious.
But some members of the task team cautioned a consumer expertise requirement might be too broad and is probably already represented among current board members. Others said they worried further earmarking of board seats for specific backgrounds could lead to a shallower pool of candidates.
MISO’s Transmission Owners’ Agreement dictates that the nine-member board contain six members with experience in corporate leadership at the senior management or board level or in the areas of finance, accounting, engineering or utility laws and regulation. The three remaining director seats are divided among those with transmission system operations, transmission planning and commercial markets and trading experience.
When she served on the Nominating Committee last year, Madison Gas and Electric’s Megan Wisersky said she was explicitly told to look for candidates with a regulatory background, even though regulatory experience was not a prerequisite. The committee eventually recommended then-sitting Minnesota Public Utilities Commission Chair Nancy Lange. (See MISO Elects Lange to Board; Keeps 2 Incumbents.)
“Where does this come from?” she asked, calling for MISO and its Advisory Committee to be more transparent about which skills and background they’re seeking each year in new directors. She asked MISO to share how it decides what qualifications will help better position the RTO to navigate grid change.
MISO earlier this year tasked the BQTT with examining possible Nominating Committee changes, either expanding or eliminating the RTO’s yearlong “cooling-off” period imposed on board candidates, and potentially detailing more director qualifications.
Exelon’s David Bloom said the team will likely provide a draft of its recommendations at the Sept. 18 Advisory Committee meeting during MISO Board Week. The AC is expected to vote in December on whether to put the recommendations before the board’s Corporate Governance and Strategic Planning Committee.
MISO sectors have generally agreed to recommend increasing the number of stakeholder representatives on the Nominating Committee that selects board candidates. (See MISO Sectors OK Expanding Nominating Committee.) The BQTT appears ready to suggest boosting the number of stakeholder seats from the current two to three or four and rotating the sectors from which participants are drawn. Three committee seats are reserved for sitting board members.
The BQTT also looks set to recommend applying MISO’s current yearlong cooling-off period before board eligibility to state and federal regulators as well as those coming out of the industry.
“State commissioners and staff are market participants in every sense of the word but the legal definition. Their decisions affect what happens in MISO,” Wisersky said.
Three MISO directors’ terms will conclude at the end of this year. Additionally, the board is involved in a special process to decide on a candidate to replace former board member Thomas Rainwater. (See “Board Moving on Rainwater Replacement,” MISO Board of Director Briefs: June 20, 2019.)
BQTT leaders will likely ask MISO to extend the life of the group by at least a month in order to consider feedback from AC members through October. Bloom said while he hoped the team could wrap up next month, he wouldn’t rule out an extension through the end of the year.
A group of grassroots organizations opposed to high-voltage transmission projects summed up the initial comments in FERC’s inquiry into its transmission incentive policies quite nicely (PL19-3).
“Those who profit from transmission incentives believe incentives should remain the same or be increased. Those who pay transmission incentives believe incentives should be reduced or phased out entirely. And those who believe transmission incentives are key to saving the planet champion new incentives at any cost,” said the group, which included organizations such as the Coalition for Rural Property Rights, the Eastern Missouri Landowners Alliance, Say NO to NECEC and STOP Transource Power Lines MD. “It is the unenviable position of this commission to referee these disparate interests to set policy that best serves its mission to ensure economically efficient, safe, reliable and secure energy services for consumers.”
Under an inquiry it opened in March, FERC is examining whether it should continue to grant transmission developers certain incentives, whether to increase or decrease them, and whether they should be based on projects’ risks and challenges or on the benefits they provide. Initial comments were submitted in late June. (See Tx Incentives NOI Brings Calls for Broader Reforms.)
Stakeholders largely reiterated their positions as they rebutted each other in their reply comments in the docket, submitted last week. Below, based on a review of more than two dozen filings, is a sample of what FERC heard.
“Not surprisingly, the initial comments contain conflicting recommendations for how the commission should proceed at this crossroads,” the California Public Utilities Commission said. “There is, however, general consensus that the historical decline in transmission investment that motivated Congress to enact Section 219 [of the Federal Power Act] in 2005 has been conclusively reversed.”
Defense of the Adders
The Edison Electric Institute said it “does not agree with commenters arguing that because Section 219 of the FPA and Order No. 679 have helped to promote increased transmission investment, the job is done and changes to the commission’s incentives policy to continue to encourage transmission development are not needed. Nor does EEI agree with those commenters who go even further and advocate that the commission rollback its incentives policy, because this would be counterproductive to meeting Congress’ objectives in implementing Section 219.”
The New Jersey Board of Public Utilities and the state’s Division of Rate Counsel filed joint comments saying transmission owners should not receive an incentive for RTO membership because “the benefits of RTO membership are a sufficient incentive,” citing economies of scale and efficiencies in the transmission planning process. “If the commission continues the RTO incentive adder, it should not be generically applied ‘regardless’ of why transmission owners participate in RTOs,” they wrote.
But others argued that FERC is required to provide an RTO/ISO participation adder under FPA Section 219. The commission approved the adder in Order 679 in 2006.
U.S. annual transmission investments for FERC-jurisdictional and ERCOT transmission owners up to 2017, with EEI projections beyond | The Brattle Group
“Some commenters that argue for elimination of the current RTO participation incentive do not even acknowledge that the commission is statutorily obligated under FPA Section 219 to provide an RTO incentive,” a group of MISO transmission owners said. “Those that do acknowledge the obligation fail to provide a compelling reason to conclude that the current, modest 50-basis-point adder incentive is no longer reasonable, omit any detail regarding what ‘incentive’ the commission should offer instead, and do not provide any evidence to demonstrate the reasonableness of any such alternative incentive.”
“The initial comments opposing retention of the RTO participation adder do not offer compelling arguments,” American Electric Power said. “Some commenters suggest that the RTO participation adder should be eliminated, or should be phased out for current RTO members and available for a fixed period only for new RTO members. Such proposals are in tension with the legislative text and the commission’s interpretation of that text.”
Others defended the participation adder on its own merits.
“The role of RTOs and the need for consistent, stable membership of transmission owners will only be heightened in the next phase of investments into the transmission system,” MISO said. “Incremental changes, even changes that may occur in separate proceedings over the course of several years, have the potential to erode the foundation upon which RTOs were built.”
MISO insisted the participation adder is necessary to expand voluntary RTO membership, saying that membership has “stalled,” far from the “near universal” participation FERC envisioned when it issued Order 2000 in 1999.
Eversource Energy said that the RTO participation subjects TOs to risks, as they turn over their operational control and transmission planning functions, and they also face coordination issues, such as outage scheduling.
“Transmission-owning RTO/ISO members assume the considerable risks associated with RTO/ISO participation for the benefit of their customers, as many of the benefits of RTO/ISO participation accrue to customers and not to the utilities themselves,” agreed Exelon.
In joint comments, Pacific Gas and Electric and San Diego Gas & Electric urged FERC to maintain both the participation adder and the abandonment incentive, which permits recovery of 100% of prudently incurred costs for projects canceled because of factors that are beyond TOs’ control. Any reduction, even in certain circumstances, could act as a disincentive to new investment, the utilities said.
Competition
Eversource also said the commission should dismiss the suggestion to condition the application of the RTO participation incentive on the relevant RTO or ISO having at least 33% of the transmission investment in its region originating from competitive solicitations. “There is nothing in the language of Section 219c to suggest that the incentive for joining a regional transmission organization should be conditioned upon the level or percentage of transmission investments subject to the competitive solicitation process. Indeed, in the [Notice of Inquiry], the commission itself pointed out that Order No. 1000 is not related to ‘the commission’s obligations under Section 219.’”
EEI’s most recent historical and projected transmission investment data | Edison Electric Institute
Both PJM’s Independent Market Monitor and LS Power said the existing structure provides enough incentive to attract infrastructure investment and, if anything, should subject more projects to competitive bidding.
LS Power asked FERC to withhold incentives from upgrades or new builds that aren’t “independently reviewed.”
“FERC does not need to change its current incentives policies in order for ratepayers to obtain the benefits of competition, but FERC can significantly expand these benefits by taking steps to expand the number of projects selected through competitive transmission solicitations,” the company said.
“Rules permitting competition to provide financing for PJM and other RTO transmission expansion projects could reduce the cost of capital for transmission projects and significantly reduce total costs to customers,” the Monitor said. “Rules that allow incumbent owners to exclude, limit or condition the development of new or replacement transmission projects create barriers to competitive investment.”
Advanced Tech
The Grid Advancement Coalition — 18 companies, environmental organizations and trade groups, including ITC Holdings, the American Wind Energy Association and the Natural Resources Defense Council — called for policies to encourage relatively low-cost investments that could make existing transmission more efficient, such as dynamic line rating and power flow controls. “This action is needed to comply with FPA Section 219b(3), adopted in the Energy Policy Act of 2005, because the commission never introduced specific regulations implementing that section in Order 679 or elsewhere,” it said.
It also asked the commission “act separately to promote a more expansive transmission planning regime that fully considers the benefits of grid expansion and integration across seams.”
“There are many benefits of transmission investments that are unrecognized and uncredited in the commission’s current regulatory scheme, making ‘free riders’ of many consumers while others are faced with locally concentrated costs, leading them to oppose transmission development they should favor,” the group wrote. “The commission should reset that scheme by focusing its evaluation of transmission incentives on the consumer benefits that proposed transmission investments supported by incentives will deliver, rather than on how ‘risky’ or ‘challenging’ a transmission project may be to develop.”
Potomac Economics, which provides market monitoring services for MISO, NYISO and ISO-NE, had also proposed an incentive to encourage the use of dynamic line ratings as a way of increasing existing lines’ capacity. The MISO TOs, however, came out against that idea.
“Introducing economics into transmission facility rating decisions could work at cross-purposes with actions of utility operators to objectively perform their reliability functions,” they said. [On Sept. 10-11, FERC will hold a technical conference on transmission line ratings, with a focus on dynamic and ambient-adjusted ratings (AD19-15)].
The Working for Advanced Transmission Technologies (WATT) Coalition proposed a new incentive for small projects using advanced technologies that produce quantified congestion benefits, an idea supported by AEP.
No New Incentives
But other stakeholders were vehemently opposed to new incentives, increases to existing adders or making qualification for them easier.
“The commission’s incentives policies are already quite flexible and allow transmission owners the ability to seek a range of incentives … for various purposes,” the National Rural Electric Cooperative Association said. “It would be inappropriate, however, to enshrine the various perks that transmission owners want into the commission’s incentive regulations.”
NRECA called out WATT’s proposal specifically, saying such projects “may hold promise of such consumer benefits, but the commission should not approve a new incentive rate treatment for them in this proceeding.” It cited FERC’s 2012 incentives policy statement, where it explained that “having distinct standards apply to advanced technologies contributes to confusion.”
“Sticking with this case-by-case process for these kinds of projects is the best way to ensure that regional planning requirements can be established; that the relevant costs and benefits can be identified and defined; and that the appropriate shared-savings rate treatment can be evaluated,” NRECA said.
| R Street Institute
FERC in Order 679 established a requirement that each applicant must demonstrate that there is a “nexus” between the incentive sought and the risks and challenges of the investment being made.
“Industry commenters that propose making the nexus test less rigorous and the commission’s incentives policy more expansive look ahead to justify their recommendations, by speculating on how the commission’s incentive policy must evolve to appropriately incent investment to facilitate the grid of the future,” the California PUC said. That argument is flawed for several reasons, it said, including a lack of evidence that FERC’s incentives have increased transmission reliability, reduced congestion and lowered costs. FERC needs to show proof before it starts adding new incentives for new purposes, such as ensuring resilience in the face of climate change and extreme weather.
The CPUC rejected suggestions that the commission automatically award the abandoned plant and construction work in progress incentives.
“Instead, the CPUC recommends that the commission should now make the nexus test more rigorous, transparent and data-driven by, for example, implementing a cost-benefit analysis, cost caps and other forms of cost containment, and ex post verification of project benefits.”
The New England States Committee on Electricity said it “strongly disagrees” on the need for a new category of FERC transmission rate incentives to help implement state-jurisdictional energy and environmental laws. It pointed to the Massachusetts Department of Public Utilities’ approval of contracts to deliver power over a new 1,200-MW HVDC line, and the 2015 solicitation by Massachusetts, Connecticut and Rhode Island for clean energy projects, none of which ended up needing new transmission, as evidence that “transmission incentive reforms are not needed to advance New England states’ laws.”
The Eastern Massachusetts Consumer-Owned Systems (EMCOS) said the commission “should be wary” of any proposal to grant TOs additional incentives. “The evidence shows that continued transmission investment has produced smaller and smaller benefits to consumers at greater and greater costs,” the group said. “If the commission chooses to revisit Order No. 679, it should examine whether the costs of its current transmission incentives outweigh the benefits produced.”
The grassroots groups were more colorful, urging “the commission to proceed thoughtfully, and with a realization that transmission owners will continue to chase higher returns and profit, no matter the decision reached in this docket.”
“Like any spoiled child whose lollipop is taken away, transmission owners may kick and scream and promise to hold their breath until they die. We all know that’s an impossibility and that highly profitable transmission investment will continue to happen, even without an incentive lollipop.”
Michael Brooks, Amanda Durish Cook, Rich Heidorn Jr., Michael Kuser, Hudson Sangree and Christen Smith contributed to this report.
FERC last week rejected an administrative law judge’s finding that PJM’s transmission study process is unjust and unreasonable for developers seeking to secure incremental auction revenue rights (IARRs) by making upgrades to reduce grid congestion (EL15-79).
The commission reversed ALJ Philip C. Baten’s January 2018 initial decision ordering PJM to reinstate three interconnection queue positions he said were unfairly eliminated when developer TranSource refused to pay for a facility study, the next stage of its interconnection process after the system impact study (SIS). FERC also reversed Baten’s conclusion that PJM should refund TranSource’s SIS application fees. (See FERC Judge Faults PJM, TOs on Transmission Upgrade Process.)
TranSource filed a complaint in June 2015 contending that PJM and transmission owners Public Service Electric and Gas, PPL, Jersey Central Power & Light and Delmarva Power & Light inflated the cost of upgrades necessary to approve three requests for IARRs. (TranSource is not to be confused with Transource Energy, a joint venture of American Electric Power and Great Plains Energy.) (See Transmission Developer: PJM TOs Inflating Upgrade Costs for ARRs.)
The commission affirmed Baten’s decision to reject other remedies TranSource sought, including its claim for $63.6 million in “lost business” opportunities. And it agreed with Baten that it could not determine whether the $1.7 billion in upgrades PJM identified were indeed necessary, noting that the case focused on the impact studies, which are supposed to produce only “good faith” cost estimates.
Readington-Roseland Line
TranSource’s upgrade proposals used facility ratings from FERC Form 715 filings made by PJM on behalf of the TOs. Baten said that was a “reasonable” assumption based on “statutory and regulatory provisions” and language in PJM’s Tariff.
PJM testified its cost estimates were based on the line ratings expected at the time that the project being studied would be in service, including planned upgrades. PJM’s estimates also incorporate the host TO’s review of limiting elements based on the methodologies they file under NERC reliability standard FAC-008-3. The methodologies are not public and not the same as those used for Form 715.
A primary conflict was over estimates for upgrading PSE&G’s Readington-Roseland 230-kV line in New Jersey.
PJM’s analysis of transmission upgrade requests under Tariff Attachment EE is done in two steps. The SIS provides developers with an estimate of what their plan will cost with +/- 40% accuracy.
The first component of the SIS is the simultaneous feasibility test, in which PJM tests whether the developer’s IARR request can be accommodated without diminishing the income of the current ARR holders. After that, PJM identifies the facilities that are impacted by the IARRs, and the relevant TOs conduct “desk-side” studies — so called because they do not involve site visits — using the confidential methodology to identify upgrades needed to accommodate the IARRs and their estimated cost.
If the developer chooses to proceed based on the SIS results, PJM conducts an in-depth facilities study that requires a refundable deposit of at least $100,000 and is supposed to provide a more accurate itemization of required upgrades.
A facilities study done for Exelon in late 2014 pegged the cost to repair the Readington-Roseland line at about $14.2 million. Although the towers had been in service for 80 years, “based on visual observation only, tower replacements are not anticipated,” the study said.
But an SIS done for TranSource six months later increased the estimate more than nine times to nearly $126.5 million. When Richard Crouch, a PSE&G electrical engineer, reviewed the project three months later, he called for a complete wreck and rebuild for more than $142.7 million, a $16 million increase.
Analyses of the condition of the Readington-Roseland line was a source of contention in the TranSource case. | PJM
By 2016, PSE&G engineers had put the line on its list of facilities violating the company’s Form 715 end-of-life criteria.
TranSource contested the SIS for Readington-Roseland and its other requested upgrades, saying it lost financing because of what it called PJM’s “badly inflated” estimates. The RTO eliminated TranSource’s queue positions when it refused to pay for the studies.
Baten ruled that the lack of transparency in PJM’s SIS process made it “unduly discriminatory” to merchant developers by depriving them of business opportunities.
But while the commission directed PJM to add more detail regarding its SIS methodologies and assumptions to its Tariff, it ruled that the RTO’s treatment of TranSource “represent a transparent process that is just and reasonable.” It said the Exelon facilities study cited by TranSource was an interconnection study, not a transmission planning study.
The commission also reversed Baten’s findings that the line rating methodology lacked transparency and that it was reasonable for TranSource to rely on Form 715 ratings in conducting its own evaluation of its upgrade requests.
And it said the judge ignored precedent and the facts in concluding that PJM’s SIS process was unduly discriminatory. Citing Congress’ creation of classes under civil rights statutes, Baten concluded that FERC had “created a class” of merchant developers and established “benefits for the class.” He said that since the IARR program began in 2007, only one project (combining five queue positions) had been awarded IARRs out of 41 Attachment EE queue positions.
FERC said Baten failed to make a finding that PJM treated TranSource differently than other Attachment EE customers or that Attachment EE customers were treated differently than other classes of customers.
“We agree with PJM, the PJM transmission owners and trial staff that the presiding judge’s reliance on the fact that very few Attachment EE requests have resulted in IARRs being awarded is misplaced,” the commission said. It added that he ignored testimony from David Egan, then manager of PJM’s Interconnection Projects Department, that “to make a profit under Attachment EE, a developer must find a ‘sweet spot’ where the transmission upgrades reduce congestion, but enough congestion remains so that the resulting IARRs have value.”
The commission dismissed as moot TranSource’s request to require PJM to add a pre-SIS phase to the Attachment EE process, noting that FERC approved the addition of a feasibility study to the process in April 2018.
PJM must open Form 715 transmission projects to competitive bidding — with regional cost sharing for those projects involving high-voltage lines — FERC ordered Friday.
The directives came in two orders prompted by the D.C. Circuit Court of Appeals’ August 2018 remand that found FERC erred when it assigned all the costs for two Form 715 transmission projects proposed by Dominion Energy to the Dominion zone.
Owners of transmission at or above 100 kV must file Form 715 Annual Transmission Planning and Evaluation Reports that detail the planning reliability criteria that the transmission owners use to evaluate the strength and limits of their systems. About $1.5 billion of the $2.1 billion in baseline spending in PJM’s 2018 Regional Transmission Expansion Plan was for Form 715 projects.
In its order on remand Friday, FERC rejected a PJM Tariff amendment that had assigned all costs of projects included in the RTEP solely to address Form 715 local planning criteria to the respective TOs’ zones. It also directed PJM to refile the assignment of cost responsibility for transmission projects in its RTEP between May 25, 2015, and Aug. 30, 2019, “that solely address individual transmission owner Form No. 715 local planning criteria” (ER15-1387-004).
About $1.5 billion of the almost $2.1 billion in baseline spending in PJM’s 2018 Regional Transmission Expansion Plan was for Form 715 projects. | PJM 2018 RTEP
In a separate order, FERC opened a Federal Power Act Section 206 proceeding requiring PJM to revise its Operating Agreement, ruling that because the Tariff amendment is no longer applicable, neither is the provision that allows projects without competitive bids (EL19-61).
“Because the costs of projects needed solely to address individual transmission owner Form No. 715 local planning criteria will no longer be allocated 100% to the transmission zone of the transmission owner whose Form No. 715 local planning criteria underlie each project, we are instituting a proceeding pursuant to Section 206 of the FPA to require PJM to revise the PJM Operating Agreement to no longer exempt from the competitive proposal window process such projects, or to show cause why such changes are not necessary,” FERC said.
“We are still looking at these orders and we’ll be assessing the workload impact and identifying the appropriate action,” PJM spokeswoman Susan Buehler said Monday.
“This is a significant win for competitive transmission developers,” said Sharon Segner, vice president with LS Power. “This should increase the number of competition windows in PJM and bring the benefits of more transmission competition to PJM customers.”
“I think it is [a good order], but there’s a lot more to do,” Ed Tatum, vice president of transmission for American Municipal Power (AMP), said in an interview Monday. “This ruling gets us back on track to the structure and concept that was envisioned 22 years ago where transmission was planned by … the regional transmission organization.”
But Tatum said AMP will continue to push for PJM to assert control over TOs’ supplemental projects, which dwarf even Form 715 spending.
Supplemental projects are not required for compliance with grid criteria governing system reliability, operational performance or economic efficiency. PJM does not approve supplemental projects but does study them to ensure they won’t harm reliability.
Since 2015, PJM has evaluated more than $13.5 billion in supplemental projects, including $5.7 billion in 2018 alone. AMP says supplemental projects have tripled over the last 13 years, accounting for 62% of the submitted RTEP project costs since January 2017.
Since 2015 PJM has evaluated more than $13.5 billion in supplemental projects, including $5.7 billion in 2018 alone. | PJM 2018 RTEP
Dispute over Cost Allocation for Dominion Projects
The D.C. Circuit’s ruling stemmed from two Form 715 transmission projects by Dominion; the first one, Elmont-Cunningham, was proposed in 2013. PJM’s rules then required that half of the cost of high-voltage projects be assessed on a pro rata basis to all 24 utilities in the RTO based on customer demand, with the remainder allocated to zones based on benefits, as determined by a distribution factor (DFAX) analysis.
Dayton Power & Light objected to using the 50% pro rata allocation for the Elmont-Cunningham project, prompting PJM to propose a Tariff amendment that would prohibit cost sharing for projects proposed to satisfy TOs’ own planning criteria.
FERC initially rejected the proposal, saying it violated Order 1000 and was inconsistent with the commission’s earlier finding that high-voltage transmission lines provide “significant regional benefits that accrue to all members of the PJM transmission system.”
Most baseline projects since 2015 have been below 345 kV. | PJM 2018 RTEP
After a technical conference, however, the commission reversed its decision, ruling that projects such as Elmont-Cunningham belonged in a new category of projects included in the RTEP for coordination but not selected for cost allocation. The commission then used the amendment to reject regional cost sharing for the Elmont-Cunningham and a subsequent Cunningham-Dooms project.
Commissioner Cheryl LaFleur dissented, saying that the commission should preserve regional cost allocation “for certain high-voltage projects, even if those projects are selected solely to address local planning criteria.”
The D.C. Circuit agreed, saying FERC’s approval of the Tariff change was “arbitrary” and would result in a “severe misallocation of the costs” of high-voltage projects. It noted that the Dominion zone would receive less than 50% of the benefits of each of the two projects.
“High-voltage power lines produce significant regional benefits within the PJM network, yet the amendment categorically prohibits any cost sharing for high-voltage projects like those at issue here,” Judge Gregory Katsas wrote for the three-judge panel. (See DC Circuit Rejects PJM Tx Cost Allocation Rule.)
In its Friday orders — issued on LaFleur’s last day at the commission — FERC rejected the Tariff amendment it had previously accepted and ordered PJM to make all Tariff corrections necessary to reflect the rejection within 30 days. It also gave PJM 30 days to amend its OA to eliminate the competitive exemption for Form 715 projects or make a show cause filing.
Most of the Form 715 projects in 2018 were proposed by Public Service Electric and Gas ($1.1 billion), Dominion ($295 million), American Electric Power ($71 million) and PPL ($57 million).
Efforts to obtain comments from Dominion, PSE&G and PPL were unsuccessful. An AEP spokeswoman said the company was “still digesting the orders” and had no immediate comment.
It was unclear from FERC’s order whether the commission expects PJM to open all Form 715 projects to competition or only those that are subject to regional cost sharing.
In 2016, the commission approved PJM’s proposal to exempt reliability upgrades on facilities below 200 kV from competitive windows under Order 1000 (ER16-1335).
PJM said such projects are almost always assigned to incumbent developers, and the change would enable its engineers to focus on problems more likely to result in a competitive greenfield project. The commission limited the exemption to projects within a single transmission zone, saying those involving two or more zones must be opened to a proposal window. (See FERC Orders PJM TOs to Change Rules on Supplemental Projects.)
RENSSELAER, N.Y. — NYISO energy prices fell sharply in the second quarter, but congestion costs surged during the period despite lower gas price spreads and load levels, according to the Market Monitoring Unit.
Energy prices fell by 9 to 36% in the second quarter compared to the same period last year, while average load dipped to the lowest second-quarter level since 2008, Pallas LeeVanSchaick, of MMU Potomac Economics, told the ISO’s Installed Capacity/Market Issues Working Group on Thursday in presenting its quarterly report on the markets.
Falling locational-based marginal prices and lower capacity costs in most areas accounted for the overall price decline. Average all-in prices fell in all areas and ranged from $20/MWh in the North Zone to $55/MWh in New York City.
While capacity prices were up 4% in the city, they fell by 14 to 56% in other areas of the state because of lower peak load forecasts, uprates and new generation coming online. The report also showed that energy costs fell by 11 to 34% in most regions because of lower natural gas prices, which dropped 17 to 29% from the previous year in Eastern New York.
The Monitor’s 2018 State of the Market Report, presented by LeeVanSchaick in May, showed that rising natural gas costs and increased load levels drove up NYISO electricity prices by 23 to 36% last year, with peak load up 7% — “quite a large increase,” he said. (See “State of the Market: Peak Load Up 7%,” NYISO Business Issues Committee Briefs: May 13, 2019.)
Second quarter electric and natural gas prices in NYISO and neighboring regions | Potomac Economics
DA Congestion Revenues Rise 37%
Day-ahead congestion revenues rose 37% from the second quarter of 2018, the Monitor reported.
The West Zone marked the largest increase in congestion costs because of the combined effects of modeling 115-kV constraints in the market software; more costly transmission outages; the return to operation of the South Ripley-Dunkirk 230-kV line on the PJM-NYISO seam, which has increased the impact of loop flows; and an increase in imports stemming from low Ontario spot prices.
“West Zone constraints were hard to manage despite recent modeling enhancements,” LeeVanSchaick said. “The most significant factor leading to BMS [Business Management System] limit reductions was the cap on clockwise changes.”
The BMS and Energy Management System (EMS) encompass the critical core reliability functions on the grid. When physical (EMS) flows exceed flows considered by the scheduling models (BMS flows) by a significant margin, the ISO reduces scheduling limits to ensure flows remain at acceptable levels.
The cap on clockwise changes in circulation was previously set at 75 MW per real-time dispatch (RTD) interval, which prevented dispatch from reducing flows sufficiently after sudden changes in loop flow. NYISO increased the cap to 125 MW in June and 200 MW in July.
Frequency (top) and value (bottom) of day-ahead and real-time congestion along major transmission paths by quarter | Potomac Economics
NYISO increased the constraint reliability margin (CRM) on the Niagara-Packard 230-kV lines and the Niagara-Robinson Road 230-kV line from 20 MW to 40 MW in June and to 60 MW in late July to assist in managing the constraints.
Noting the change to the Niagara-Packard and Niagara-Robinson Road CRMs and cap on loop flow changes, Chris Wentlent, representing the Municipal Electric Utilities Association of New York State, asked, “Are those going to remain in place going forward?”
“They’re not temporary, but the CRMs and the cap on circulation changes can always be modified,” LeeVanSchaick said. “The increased cap on circulation changes recognizes that the dispatch model needs to redispatch generation when circulation changes by a large amount.”
Moving East and South
“NYISO is looking whether to relocate the proxy bus for Ontario to reflect that those imports tend to increase unscheduled power flows in the clockwise direction around Lake Erie,” LeeVanSchaick said.
Another issue has to do with the Saint Lawrence phase angle regulator (PAR), which can be used to reduce congestion in the West Zone by diverting a portion of Ontario imports to northern New York, but the PAR is generally less flexible than assumed by RTD.
In August, the ISO reduced the optimization range used by RTD to be more consistent with the anticipated operation of the PAR, which “tightened up some of the modeling assumptions to better reflect how it’s actually going to be operated,” LeeVanSchaick said.
Asked by Wentlent when the St. Lawrence PAR might be evaluated, LeeVanSchaick said he was not sure, “because those are complicated issues. Hopefully we can answer by the next quarterly report.”
Asked how the transmission build-up in the western part of the state would affect constraints, LeeVanSchaick said, “You might see more Ontario imports, which would hit hidden downstream bottlenecks, like perhaps Central East, but it’s not something that we’ve looked at carefully.”
Central East congestion increased primarily because of increased exports to New England from eastern New York, which were up approximately 400 MW, and more transmission outages leading to reduced transfer capability in April and May.
“Modeling these 115-kV constraints allows the market to reflect the congestion appropriately,” he said. “In the Hudson Valley-Dunwoodie category, we saw significant constraints, which is due to some new combined cycle natural gas generation in the Hudson Valley, and not as much energy being wheeled from the Hudson Valley through New Jersey to New York City.”
When the Indian Point nuclear plant retires in 2021, it will shift the location of congestion to another area south of the UPNY-SENY interface, LeeVanSchaick said.
New York City
NYISO’s efforts to manage constraints “have greatly reduced out-of-merit actions, especially in the West Zone,” LeeVanSchaick said.
However, most reliability commitments occur in New York City because additional generation is needed to satisfy operating reserve requirements that have not been reflected in the NYISO market, he said. On June 26, the ISO began to model city-wide requirements in the day-ahead and real-time markets.
Supplemental commitments for reliability in NYC by reason and location in New York City, where most reliability commitments occur | Potomac Economics
Couch White attorney Kevin Lang, representing the city, questioned the extent to which market-based approaches would reduce the need to dispatch particular units in specific locations for reliability purposes.
“That’s a legitimate concern,” LeeVanSchaick said. “If you have higher energy and ancillary services prices, there’s going to be an decrease in uplift. … Generators should be able to earn more of what they need through providing those energy and ancillary services products.”
The ISO’s “granular operating reserves” project would define a set of locations so that the market is procuring what the system needs, he said.
“If we can shift investment toward areas where new resources provide real value in the day-ahead and real-time markets, it will be more efficient, even if the investment is driven by subsidies, and it will reduce the likelihood of needed [reliability-must-run] contracts,” LeeVanSchaick said. “Now is a particularly important time to have more efficient market signals.”
Ohio Attorney General Dave Yost last week approved a draft petition to repeal the state’s nuclear subsidy program, giving supporters just seven weeks to collect more than 265,000 signatures to get the referendum on the November 2020 ballot.
Gene Pierce, spokesperson for Ohioans Against Corporate Bailouts and sponsor of the petition, said the “quick resolution will help Ohio voters exercise their constitutional right to put controversial legislation up to a statewide vote.”
Yost rejected the first draft last month, citing disparities in its language compared with the Ohio Clean Air Act signed into law on July 23. (See Ohio Approves Nuke Subsidy.)
Davis-Besse nuclear power plant
The controversial law makes Ohio the third state in the PJM footprint to provide subsidies for its nuclear plants as cheap natural gas floods the wholesale power market and drives energy prices down to record low levels. (See Monitor: PJM Markets Remain ‘Under Attack’.) Supporters say keeping the reactors operating will reduce carbon emissions — a primary target of clean energy bills across the country — and provide around-the-clock reliability to support the intermittency of solar and wind power.
Pierce’s group argues the law amounts to a “corporate bailout” that wastes money on less efficient resources at the expense of continuing to expand Ohio’s renewable energy portfolio. And it has some powerful, if not unlikely, allies on its side: the natural gas industry, independent power producers, environmental activists and clean energy groups.
But not everyone agrees. Last month, Ohioans for Energy Security launched a $1 million television and radio ad campaign that links the petition to furthering the interests of the Chinese government, warning residents not to sign away the state’s jobs and energy security.
The Energy and Policy Institute, a renewable energy advocacy group, said Ohioans for Energy Security’s spokesperson, Carlo LoParo, has connections to FES and also fronts the Ohio Clean Energy Jobs Alliance, a known proponent of the subsidy program.
“These ads are designed to intimidate and threaten our petitioners who are exercising their constitutionally guaranteed right to place this ridiculous bailout on the ballot,” Pierce said. “This is the kind of garbage that will get someone hurt, and we will hold all parties associated with their campaign responsible for any harm that comes to our circulators.”
But Pierce is also tight-lipped about where his group’s money comes from, telling RTO Insider previously that he will disclose its financial supporters as required by Ohio campaign finance law.
“Until then, I can say that you will find that they are many of the same groups and individuals who testified against the bill in the legislative debate over the bill,” he said.
MISO is poised to recommend nearly $4 billion in spending in its 2019 Transmission Expansion Plan (MTEP), making it the second costliest such package in the RTO’s history.
The draft MTEP 19 was brought into focus over a final series of subregional planning meetings last week. The transmission projects in the bundle so far number 483 at a total cost of $3.95 billion, with MISO South’s 72 proposed projects accounting for $760 million. The priciest projects are clustered in southern Illinois, southern Michigan and southern Louisiana.
MISO will post a final draft on Sept. 16, a day before putting the plan before the System Planning Committee of the Board of Directors at its meeting in St. Paul, Minn.
MTEP 19 breakdown | MISO
Last month, MISO was positioned to recommend 529 new projects at $4.4 billion. Even with the loss of about four dozen projects, the latest MTEP is positioned to be second most expensive behind the 2011 package that contained the multi-value project portfolio. Last year, MTEP 18 rang in at $3.4 billion and 442 projects. (See MTEP 19 Revealing High Price Tag.)
During an East subregional planning meeting Wednesday, Thompson Adu, MISO senior manager of transmission expansion planning, advised stakeholders that the cost and project figures are still subject to change, but he said the numbers are “almost finalized.”
MTEP 19 contains new breakdowns in MISO’s “other project” category to capture the specific drivers of projects. This year’s $2.7 billion “other” category is now broken down into about $1.2 billion in reliability projects, $768 million in age- and condition-based projects, $644 million in load growth projects and $105 million worth of other local needs. Baseline reliability projects account for almost $1 billion in spending, while generator interconnection projects make up $245 million. MISO said the majority of MTEP 19 projects are expected to be in service within five years.
Director of Planning Jeff Webb said MISO had been mulling creating an MTEP project classification for age- and condition-based upgrades to avoid having so many projects simply labeled as “other.”
Webb said the number of MTEP projects falling into the “other” category is a “carried-over legacy” from when the RTO had to separate regional reliability projects from local reliability projects for cost allocation purposes.
“Every time we take the [project] bar charts to the board, it’s mostly ‘other.’ … We’re thinking of changing that. We’re tired of having to explain exactly what ‘other’ is over and over,” Webb said during a June planning meeting.
During an Aug. 23 West subregional planning meeting, stakeholders criticized MISO for modeling too few future wind resources in congestion relief planning. Multiple staff members pointed to the planned overhaul of futures in time for the 2021 transmission planning schedule. But some stakeholders said MISO was planning for less wind for 2030 than would be actually installed in 2020.
“I find myself wondering why we’re building futures with significant future generation and don’t include the likely associated interconnection upgrades,” WPPI Energy’s Steve Leovy said.
Some stakeholders at the meetings also said the MTEP timeline is challenging, only allowing for stakeholders to suggest alternative projects in June and July.
Historical MTEP spending with draft MTEP 19 data | MISO
1 Possible Project from MCPS
Stakeholders last week also learned that few proposals were able to demonstrate enough benefits to pass the first round of scrutiny in this year’s Market Congestion Planning Study (MCPS), designed to identify congestion-relieving projects.
Among the proposals, MISO will only take a deeper look at two possible solutions to resolve the congested Bosserman-Trail Creek 138-kV line in northern Indiana. Both projects are also under consideration as part of the MISO-PJM Coordinated System Plan, and the RTOs will make a recommendation at the Sept. 20 Interregional Planning Stakeholder Advisory Committee meeting if they plan to pursue one of the two.
MISO has until Sept. 23 to file another cost allocation plan with MISO Mulling Next Steps on Cost Allocation Overhaul.) MISO staff said they hope to have a revised interregional cost allocation structure in place before project approvals in December.
MISO planning staffer David Severson said no projects in the RTO’s North region or along the SPP seam met requirements in the MCPS. Project candidates to address congestion on the Helena-to-Scott County 345-kV line in southern Minnesota did not pass a robustness analysis, MISO said. The $32 million line was one of eight initially promising projects to come from the MCPS. (See “8-Project Draft from Congestion Study,” MISO Studying Projects to Cut North-South Tx Reliance.)
Last week’s planning meetings did not address the ongoing analysis into a possible project to ease traffic on the North-South transmission constraint. That effort is being conducted separately from the MCPS and will continue beyond the MTEP 19 approval deadline in December. MISO staff earlier this year said they weren’t bound to an MTEP 19 deadline to submit any project recommendations and could take more time to conduct thorough testing of candidates.
