Peak Reliability and PJM Connext on Tuesday refined their pitch to attract participants to a new Western energy market, saying they envision “a marketplace built by and for the West.”
“We sense, and we have heard, some people saying it’s coming down to the time for some choice in markets in the West again,” PJM Connext’s Fran Barrett said during a Feb. 6 meeting and conference call hosted by Peak. He added that PJM is “heavily, heavily focused on the bottom line.”
Barrett emphasized PJM’s experience operating a 13-state market in the East, and indicated a focus on reliability, self-governance and providing options for various market structures for potential participants. Officials from the organizations provided more detail on how the new Peak/PJM market would coordinate with other market and non-market areas, including possible congestion management practices.
Peak and PJM Connext this week outlined how their proposed market would coordinate with other market and non-market areas.
Peak and PJM first described their joint market initiative in January. (See Peak, PJM Detail Western Market Proposal.) In a presentation Tuesday, they laid out three possible market options “customized to the needs of participants,” each of which includes a nodal real-time market, day-ahead market, financial transmission rights, integrated settlement and credit management. Settlement would be based on PJM’s structure, modified for the West, with a central counter-party structure and weekly billing.
Interregional Coordination Proposed
Peak and PJM also provided more detail about how their proposed market would coordinate with other areas in the West. Their goal is to implement the market in two phases, the first using an “enhanced curtailment calculator” tool in a process comparable to the transmission loading relief procedure used in the Eastern Interconnection.
A second “market-to-market” phase would be more complex and similar to how PJM conducts coordination with MISO and NYISO. In those cases, the RTOs use combined redispatch as a joint congestion management tool for greater efficiency, and costs are allocated between RTOs based on transmission flows and negotiated historical rights.
Barrett said Peak and PJM did not know exactly what minimum size footprint or configuration would be necessary to make the proposal work, noting they were gathering data to study the issue.
“We haven’t modeled in the Swiss cheese or the string cheese or if we will have people all over the place,” Barrett said, describing the possible variable shapes of the market’s footprint.
RENSSELAER, N.Y. — New York’s Integrating Public Policy Task Force (IPPTF) hit resistance on the first paragraph when it unveiled its final work plan for pricing carbon into the state’s wholesale electricity on Monday.
That section sets out the plan’s intended purpose: to explore incorporating the costs of carbon into the market while “providing the greatest benefits at the least cost to consumers.”
Several stakeholders at the Feb. 5 meeting sought a clearer definition of “benefits,” while others wanted to know why the plan would focus primarily on benefits to consumers. In addition, some expressed concerns about how carbon pricing would translate into actual carbon reductions, given existing constraints within the state.
| DOE
The IPPTF is a joint effort of NYISO and the state’s Department of Public Service (17-01821). The group’s latest plan includes five issue tracks, reduced from six: 1) straw proposal development; 2) wholesale energy market mechanics (including “carbon leakage” and how to measure emissions) and interaction with other wholesale market processes; 3) policy mechanics, such as setting the carbon charge; 4) interaction with other state policies; and 5) customer impacts. (See New York Stakeholders Debate Carbon Policy ‘Issue Tracks’.)
Energy Market Primer
IPPTF co-chair Marco Padula, DPS deputy director for market structure, clarified that the group wasn’t created to review the contents of the state’s Clean Energy Standard but to achieve the objectives set out in the rule — namely, that 50% of New York’s electricity come from renewable energy sources by 2030.
Padula said the task force should work out the details of each track over the course of the year, as it posts reports from each meeting along with stakeholder comments. The task force will meet nearly every Monday to work through the tracks and plans to develop preliminary proposals by early August to deliver a unified proposal by December.
Erin Hogan, of the DPS Utility Intervention Unit, said the task force needs to better understand what goal is being discussed because state policy calls for 50% of the target to be met by energy efficiency measures, meaning “that renewables needed afterwards would be less.”
In the near future, stakeholders “should perhaps have a primer, maybe a little presentation just to level what exactly we’re talking about, so we don’t tie ourselves up in knots in the middle of meetings without having that level of understanding what the goals really are,” Hogan said.
Representing a coalition of large industrial, commercial and institutional energy customers, Couch White attorney Michael Mager reminded the task force of a key goal of the exercise.
“I don’t care whether you get to it now or when we get to the last track,” Mager said. “At the last meeting … there was some agreement in the room that, in addition to price impacts, we should also be measuring exactly what carbon abatement would be taking place. It doesn’t seem to have been reflected in the work plan, [which] still kind of limits the last track to customer impacts. It doesn’t seem to address anywhere actually measuring whether we’d be reducing carbon emissions at all.”
The Transmission-Emissions Nexus
The predicament of New York’s biggest metro area loomed large during the meeting. Ron Minsk, a consultant to New York City, delivered a presentation that emphasized the need for a new transmission to deliver renewable energy to the state’s largest load center. With a peak load of more than 11,500 MW, the city accounts for approximately 30% of the state’s load. The downstate region, including Long Island, represents about 50%. Minsk’s presentation echoed comments the city filed with the task force in January.
Transmission Congestion Corridors in New York State | City of New York
“We don’t want to end up having an approach where we have renewables displacing other renewables,” Minsk said. “So this gets to the transmission issues, which the city has expressed concern about before. It goes to that submission, making sure that the benefits are widely distributed. … Even with new transmission projects that are already on the books, there are transmission constraints that keep upstate power from getting downstate.”
The upstate grid is already pretty clean, with about 85% of generation carbon free, he said.
“In order to meet the state’s goals, you’re going to have to get more renewable power downstate, and, in order to do that, you have to relieve transmission,” Minsk said.
The city’s comments pointed out that NYISO has already drawn a similar conclusion, noting that even if the state adds the desired quantity of new renewables by 2030, it will not realize their full benefits without new transmission or local storage resources — or if renewable development occurs far from load centers.
Mark Younger of Hudson Energy Economics said more renewable generation will provide no consumer benefits whatsoever if it’s built in the wrong location.
Modeled future carbon intensity (tCO2e/MMBtu) of the electric grid with ranges based on changes to NYC electric demand. | City of New York
“Maybe the proper way to look at it is how are you getting the cheapest dollar per ton reduction, considering that to serve New York City and the southern area, [either] you’re … paying directly for generation there or you’re paying for generation somewhere else and the infrastructure that’s necessary to get there,” Younger said.
The transmission infrastructure is part of the price of achieving the desired carbon reduction, he said.
“You can’t ignore that infrastructure because … it looks very cheap to build all your renewable resources far away, but then incur billions of dollars that you don’t recognize as part of that decision to build the resources far away,” Younger said.
The task force next meets Feb. 12 at NYISO headquarters.
MISO on Tuesday opened a bidding window for its second-ever competitive transmission solicitation, a process required under FERC Order 1000.
Developers will be eligible to bid on the $130 million, 500-kV Hartburg-Sabine Junction project in eastern Texas until July 20. The congestion-relieving line and substation are slated to be in service by June 1, 2023.
Hartburg to Sabine Junction project | MISO
MISO’s Board of Directors last week granted late approval for the project under the RTO’s 2017 Transmission Expansion Plan. (See MISO Board Approves Texas Competitive Tx Project.) MISO expects to select a developer by the end of the year and post a full report on its evaluation no later than Jan. 30, 2019.
“When completed, this project will help bring economic benefits to a transmission-constrained area of Texas,” said Kent Fonvielle, executive director for MISO’s South region.
MISO will judge the proposals based on weighted criteria, which include cost and design, project implementation, operations and maintenance, and participation in the planning process. The RTO has revealed that 11 potential developers will already receive the 5% planning participation credit for suggesting the Hartburg-Sabine project in MISO’s annual Market Congestion Planning Study. They include Ameren Transmission Company of Illinois, Duke-American Transmission Co., East Texas Electric Cooperative, Entergy Texas, Grid America, ITC Holdings, Midcontinent MCN, Midwest Power Transmission Arkansas, NextEra Energy Transmission, Transource Energy and Xcel Energy.
Each proposal requires a $100,000 fee before MISO will begin considerations.
Prospective developers are required to communicate about the project using MISO’s TDQS@misoenergy.org email address and are instructed not to contact any RTO personnel directly. As with its first competitive transmission project in 2016, MISO will publicly post all developer questions and any answers it can provide on its competitive administration webpage. MISO will accept questions about the request for proposals until June 25 and will hold three informational meetings by conference call on Feb. 27, April 9 and May 29.
MISO has redacted some critical energy infrastructure information from the public version of its RFP, including interconnection requirements, some of Entergy’s local planning criteria, the coordinates of the new substation and aerial views of existing lines in the area.
CAISO’s operating revenues jumped 4.4% to $214 million last year on the back of increased Energy Imbalance Market (EIM) earnings and an uptick in summer activity.
The ISO reported “true operating income” (operating revenue minus operating expenses) of $47.4 million for the full year, compared with $44.4 million in 2016. True operating income fluctuates throughout the year as a large portion of revenue comes in the summer, when energy demand and prices are higher.
CAISO is a nonprofit corporation that earns the bulk of its revenue from a grid management charge (GMC), composed of market services, system operations and congestion revenue rights charges assessed by the megawatt-hour. The ISO also collects other charges and fees, including those for trades between scheduling coordinators. It additionally operates the EIM.
Including depreciation and amortization, CAISO’s fourth-quarter report showed a $6.9 million net operating income “loss,” but spokesman Steven Greenlee said that is “merely an accounting outcome.”
“The level of net operating income has no effect on our cash flow, budgeting or grid management charges,” Greenlee told RTO Insider.
CAISO collected $47.3 million of its operating revenue from its GMC in the fourth quarter, up from about $45.8 million the previous year. Other operating revenues totaled $4 million during the last quarter. GMC revenue for 2017 grew by 3% to $198.3 million and was higher than what CAISO had budgeted.
August Sees Highest Take
CAISO’s gross market revenues for all services going through the ISO market peaked at $1.2 billion in August, the period of highest summer demand and when the ISO dealt with the impact of the solar eclipse on solar generation. (SeeGrid Operators Manage Solar Eclipse.) Revenues fell to their lowest in February, at slightly more than $500 million.
The gross revenue figure represents the total value of all energy transactions and related services included on ISO invoices. CAISO recoups its costs through the GMC, which is a small component of these overall market revenues, the ISO said.
Q4 Expenses Grow
The ISO’s fourth-quarter operating expenses were $51 million, up about 16% from the same period a year earlier. Expenses include salaries and benefits to employees, building and facility costs, insurance, outside contractors, legal and auditing services, training, travel and professional dues.
CAISO’s expenditures for consulting and contracting services grew by $2.9 million quarter-over-quarter to $7.2 million. Third-party vendor contracts rose from $2.6 million to $3.5 million between the same two periods.
CAISO’s expenses grew by $7 million, or 67%, compared with fourth quarter 2016
While expenses grew, they were $7.1 million less than CAISO had budgeted for the year. The ISO cut salaries and wages by about $1 million quarter-over-quarter and had lower “building, leases and facilities” costs, and lower legal and auditing expenses. The ISO cut three full-time positions in 2017, leaving the headcount at 599.
Revenue Exceeds Budgeted Level
Fourth-quarter operating revenues exceeded the budget by $7.5 million, mostly because of EIM administrative charges and forecasting fees beating projections, the ISO said.
CAISO’s Corporate Management Committee approved $19.5 million in projects last year to increase electric system performance and to meet FERC mandates, the ISO said. These include market improvements, technology, customer service, grid readiness and other funds.
The ISO on Jan. 3 had $1.9 billion in collateral from market participants to support $294 million in aggregate liabilities in the market.
In a potential victory for merchant transmission developers, a FERC administrative law judge has concluded that PJM’s system impact study (SIS) process is unjust and unreasonable because of a lack of transparency (EL15-79).
ALJ Philip C. Baten’s Jan. 19 initial decision ordered 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 SIS. He also ordered the refund of TranSource’s SIS application fees.
Baten dismissed several other remedies TranSource — not to be confused with Transource Energy, a joint venture of American Electric Power and Great Plains Energy — sought, including its claim for $63.6 million in “lost business” opportunities. Parties have 30 days to file exceptions to Baten’s decision.
PJM spokesman Ray Dotter said the RTO will challenge the ruling.
“We have concerns about the judge’s proposed remedy to put the project back into the planning queue because it would be disruptive to other interconnection customers with pending projects,” he told RTO Insider. “PJM has looked at and revised its processes. We have made great progress on the identified transparency points. As the next step in the proceeding, we will file with the commission a brief on exceptions to the initial findings.”
Inflated Costs?
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 incremental auction revenue rights (IARRs). (See Transmission Developer: PJM TOs Inflating Upgrade Costs for ARRs.)
Baten said he 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.
But he sided with FERC trial staff in faulting PJM for failing to provide transparency throughout TranSource’s efforts to secure IARRs for making upgrades that would reduce congestion on the transmission grid.
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.
But the RTO 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, Baten said.
A TranSource witness, electrical engineer Dale Douglass, testified in the case that FirstEnergy’s FAC-008-3 ratings methodology was “clear and logical” but that the other three TOs did not clearly specify the maximum conductor temperature used to determine the line ratings.
“For some years the commission has fostered policies to pry open the transmission grid to greater competition. … The commission does recognize that interconnection customers should be able to reasonably estimate their cost before entering the queue,” Baten wrote. “Nowhere in the PJM [Open Access Transmission Tariff], Operating Agreement, or manuals or any written manifestation, which may be presented to outside parties, does PJM explain or indicate that the FERC Form 715 ratings are not used to process IARR requests. … The evidence is sufficient to show that TranSource was not advised of these parts of the model within a time frame to afford it the opportunity to make sound business judgments.”
Readington-Roseland Line
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.
Analyses of the condition of the Readington-Roseland line was a source of contention in the TranSource case | PJM
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.
Branchburg — Pleasant Valley Transmission Tower Damage | PJM
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 that he couldn’t adequately explain, the decision said. In his testimony, Crouch said he based his replacement decision on his “institutional knowledge” of the conditions of several other lines that are similar in age and terrain, which he used as surrogates in his own “desk-side” study.
By 2016, PSE&G engineers had put the line on its list of facilities violating the company’s Form 715 end-of-life criteria.
“If the line had such a dire status by 2016, it could not have been in a better condition in 2014 when the [TranSource study] began. The FERC Form 715 of that earlier period should have noted the condition,” Baten wrote. PSE&G “did not timely report the end-of-life condition of this line on FERC Form 715.”
“PSE&G follows the FERC-approved PJM process for all planning decisions, including with regard to the facilities discussed by Judge Baten in the TranSource decision,” spokesman Mike Jennings said.
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.
Unduly Discriminatory
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. He noted that, because IARRs were implemented in 2007, only two projects out of 100 submissions under two separate Tariff sections have been awarded IARRs.
The judge said that trial staff generally sided with PJM in the case, but that a staff witness, economist C. Shelley Norman, agreed that “PJM’s process for reviewing and evaluating IARR requests was significantly lacking in clarity and transparency.
“Even PJM’s witness David Egan [manager of the Interconnection Projects Department] agreed during his deposition,” Baten added.
“PJM’s lack of clarity and transparency in its IARR study process has likely caused systemic issues and contributed to the low completion rate of successful merchant IARR projects,” wrote Baten, who noted the record included hundreds of pages of email correspondence between TranSource and the RTO between June 2013 and March 2015. PJM’s “dribbling out of piecemeal information over time … is not consistent with the level of transparency that the commission orders have envisioned. … These obvious failures in this case are indicative of a severely flawed SIS process.”
Revised IARR Manual
During the hearing in the case, PJM and its Independent Market Monitor developed a manual detailing the procedures that the RTO followed to determine the TranSource upgrades. Baten said that although the manual was intended to improve transparency, it “does not provide any methodologies that the TOs use or will use to rate their facilities when they get the request from PJM to determine the extent and any necessary upgrades to meet an IARR request.”
Because the manual was not litigated at the hearing, Baten said he could not rule on whether it is sufficiently transparent.
“The commission on its own motion may order that PJM should offer the manual to a stakeholder process for proper vetting. At this point, the manual represents the efforts of PJM and the IMM to clarify the IARR process. On its face it does neglect a discussion of the role of the TOs in the process. More flaws could be undiscerned at this point in its development.”
Two-Stage SIS?
The judge rejected as beyond the scope of the docket TranSource’s request that PJM add another phase of impact studies before the facilities study so that requests by merchant transmission developers are handled in the same manner as requests for generation interconnection studies. Baten said the commission “should consider” TranSource’s request. PJM’s Planning Committee began a discussion on whether an additional study phase is necessary in September. Tariff revisions, which include replacing an initial study for projects with a feasibility study prior to an SIS, were approved by the Markets and Reliability Committee in December and the Members Committee in January. PJM plans to present additional manual revisions at Thursday’s Planning Committee meeting. (See “Interconnection Study Process to be Rearranged,” PJM Planning/TEAC Briefs Oct. 12, 2017.)
VALLEY FORGE, Pa. — One thing is clear in the PJM turf war over control of the transmission replacement process: Neither side is conceding an inch until a FERC decision forces them to.
Representatives of transmission owners and their customers once again staked their claims at last week’s meeting of the Transmission Replacement Processes Senior Task Force (TRPSTF). TOs argued it’s their sole right and responsibility to manage their infrastructure, while transmission customers called for increased transparency of the processes TOs use to determine when towers and other equipment should be replaced. The projects are part of a class of transmission development that doesn’t require PJM approval, known as “supplementals.”
PJM staff stuck to a strict definition of the RTO’s role over such projects.
“We look at the reasonability of the information [TOs provide] and that they have followed the procedures that have been specified, but validation is a much stronger word,” Vice President of Planning Steve Herling said. “We validate that they follow their procedures. We cannot validate the individual elements of the actual material condition.”
The task force has made little progress since it was chartered in May 2016 to “develop alternatives for providing more transparency and consistency in the communication and review of end-of-life projects in the Regional Transmission Expansion Plan.” (See PJM Demands Agreement on Tx Replacement Definitions.)
FERC issued a show cause order in August 2016 questioning whether PJM TOs’ procedures for planning supplemental projects provided stakeholders opportunity for “early and meaningful input and participation,” as required by Order 890 (EL16-71). TOs included in their response a proposed addition to the Tariff known as Attachment M-3, which they argue would improve transparency.
The show cause order precipitated a 10-month hiatus of the task force, which ended in July. Since then, American Municipal Power and Old Dominion Electric Cooperative — who say they are advocating for their customers — have proposed an alternative to Attachment M-3 that would give PJM more say over when and how TOs can replace aging equipment. Currently, TOs fully control that process through Form 715.
The sides spent much of last week’s meeting walking through AMP and ODEC’s responses to questions TOs had posed about their proposal. The TOs argued that many of the AMP/ODEC provisions violate PJM’s governing documents and the organizational structure TOs agreed to when they joined the RTO. Exelon’s Gary Guy and Gloria Godson led much of the TO criticism.
“I cannot agree to” the AMP/ODEC proposal, Guy said. “We subjected ourselves to PJM, to their operational control … but not to any other third parties, and we’re not going to use the Tariff of PJM to write rules of compliance between us and third parties.”
PJM staff maintained their neutrality, saying that they expect TOs to provide explanations of their decisions but not information necessary to replicate their studies. Staff said the control they have over projects needed to address system reliability issues — known as “baseline” projects — doesn’t extend to supplementals.
“If it’s a baseline project, we get involved in that conversation [on sizing and specifications]. If it’s a supplemental … I don’t believe we have a role,” Herling said.
“I maintain my water heater … but after a while, when the bottom fell out of it, I went ahead and I had to get a new one. But I’m not characterizing my new water heater as maintenance,” AMP’s Ed Tatum said.
“You may choose to replace your water heater when the bottom falls out. Others may choose to replace it when it starts to get rusty on the top,” PJM’s Paul McGlynn responded.
PJM staff then walked through proposed solutions they developed internally. The proposals received substantial feedback from stakeholders, but TOs clarified at the end that their engagement didn’t represent approval.
“We’re not negotiating against our [M-3 proposal] in the FERC docket,” PPL’s Frank “Chip” Richardson said. “PJM’s proposal may go well beyond what transmission owners filed in that docket. We don’t know yet. We have to take it back and look at it.”
The D.C. Circuit Court of Appeals ruled Friday that FERC failed to adequately explain why it approved capacity market rules for ISO-NE in 2014 like those it had rejected in PJM for suppressing prices.
The Feb. 2 ruling granted petitions for review by Exelon and the New England Power Generators Association on rules allowing new suppliers to lock in their first-year clearing prices for six additional years while requiring them to offer at $0 in years 2 through 7 (15-1071).
“On the record before us, we conclude that FERC did not engage in the reasoned decision-making required by the Administrative Procedure Act,” the court said. “FERC failed to respond to the substantial arguments put forward by petitioners and failed to square its decision with its past precedent.”
PJM Ruling
NEPGA and Exelon contended the rules reduce clearing prices paid to both new and existing suppliers.
The petitioners said the commission’s approval of the rules is at odds with its 2009 ruling rejecting a similar construct in PJM (ER05-1410, et al.). In the 2009 ruling, FERC ruled that zero-price bidding would result in unjust and discriminatory pricing. It said a bid-floor was needed to ensure that a price-locked new entrant “will not reduce [the] price to the existing resources by submitting a $0 bid in years 2 and 3, knowing that it is guaranteed to be paid its first-year bid price no matter what it bids.”
NEPGA and Exelon contend the New England rules are likely to result in more severe price suppression than would have occurred in PJM, which has only a three-year lock-in. In addition, the lock-in — available to any new market entrant in New England — was rarely triggered in PJM.
No ‘Reasoned Analysis’
The opinion by a three-judge panel led by Robert L. Wilkins said FERC “brushed aside the seeming contradiction” between its ISO-NE and PJM rulings.
New England Dispatch Zones | ISO-NE
“FERC’s responses to petitioners’ arguments below amounted to conclusory statements that dismissed petitioners’ concerns without providing reasoned analysis. To respond to petitioners’ main contention that the ISO-NE Tariff rules suppressed prices and discriminated against existing suppliers in a way that the commission rejected in PJM, FERC first stated that conditions in the two markets were different, and then pointed to the vertical demand curve in place at the time under the ISO-NE Tariff. The commission issued this explanation despite the fact that it issued an order the very same day adopting an ISO-NE proposal to start using a sloped demand curve.”
The petitioners argued that the commission should have either rejected ISO-NE’s lock-in rules, required it to eliminate the zero-price offer requirement when it accepted a sloped demand curve or found another way to address the price suppression for existing suppliers.
The court noted that FERC cited “numerous cases to stress the broad array of practical difficulties to balance and interests to consider, including higher consumer prices, reliable price signals, producer flexibility, producer confidence, system reliability, and increasing system capacity and efficiency.”
“FERC contends that it truly has changed its view about the lock-in and capacity-carry-forward rules since its PJM decision and even doubled down by suggesting at oral argument that it would be more receptive to the Tariff changes at issue in PJM if they were proposed today,” the court said. “All this may be true. But FERC’s complex mandate doesn’t relieve it of the requirements of reasoned decision-making. … Although FERC may be sincere in its change of heart and, as a substantive matter, correct that its new rationale is just and reasonable, the commission must provide some analysis and explanation in its orders regarding why it changed course.”
The court declined to rule on whether the petitioners had met their burden to demonstrate that the ISO-NE rules resulted in unjust and unreasonable rates. But it said, “FERC must provide a more robust rationale for its seeming inconsistency with past precedent and practice.”
NextEra Energy, which quit the Nuclear Energy Institute last month over the trade association’s push for subsidies, last week accused the group of “extortion,” saying it was spitefully denying the company access to a database used to screen workers.
The company initially declined to say publicly why it was leaving NEI when it informed the organization of its decision on Jan. 4.
But NextEra ended its silence after NEI notified it on Jan. 30 that it was terminating its access to the Personnel Access Data System (PADS). NextEra said NEI informed it that it would be cut off Feb. 4 unless it paid $860,000, “the vast majority of which is NEI membership fees unrelated to PADS.”
“NEI’s actions were taken for no purpose other than to retaliate against the NextEra companies because of their withdrawal as NEI members,” said the suit, filed Feb. 2 in U.S. District Court for the Southern District of Florida.
NEI CEO Maria Korsnick issued a statement Monday saying she “vehemently denies” NextEra’s allegations and “will vigorously defend our position in court.”
NextEra said losing access to PADS could threaten seven scheduled refueling outages at its nuclear plants in 2018, including one set to begin Feb. 7 at the St. Lucie nuclear plant owned by its Florida Power & Light subsidiary. The company said St. Lucie’s workforce would jump from 700 to 1,700 during the monthlong outage.
The nuclear industry developed PADs in the mid-1990s as a shared database for employee security information such as criminal history reports, fitness-for-duty test results and psychological screenings.
NextEra said it would be “exceedingly difficult” to meet Nuclear Regulatory Commission requirements without PADS, noting that staff can more than double during plant outages. “Many of the additional maintenance workers employed during these refueling outages are highly transient — moving from plant to plant across the country to work during outages,” the company said. “Without access to PADS, nuclear operators would be forced to start from scratch in screening individual applicants for unescorted access, and they would do so without the benefit of consulting information already collected by other nuclear operators in an easily accessible electronic format. Similarly, without universal industry participation in PADS, the database would become incomplete. This would result in additional manual screening efforts even for continuing PADS participants.”
The company contends the PADS participation agreement, which it signed in 1995, does not require participants to be NEI members. “NEI took this retaliatory action notwithstanding that the NextEra companies have been at all times in compliance with the agreement and have paid millions of dollars to develop and upgrade PADS,” it said.
Korsnick disagreed with NextEra’s interpretation of the participation agreement. “When NextEra voluntarily chose to discontinue its NEI membership, it was no longer entitled to continue participating in PADS,” she said. “Even then, NEI conveyed to NextEra that it would supply the information in PADS necessary to maintain strict compliance with the NRC regulations. That exchange has been accomplished and will continue throughout each work week.
“To call NEI’s approach retaliatory, or even suggest the notion of extortion, is both counterfactual and offensive to the good faith effort the offer represents,” she continued. “NEI’s good faith outreach was intended to open a dialogue that would advance the industry’s interest in remaining unified, or as unified as possible, on regulatory and other policy positions. Unfortunately, rather than even opening a dialogue, NextEra immediately followed its rejection of NEI’s offer with a baseless lawsuit.”
Break over Policy
NextEra owns all or part of the Duane Arnold Energy Center in Palo, Iowa; the Point Beach Nuclear Plant in Two Rivers, Wis.; and the Seabrook Station in Seabrook, N.H., equivalent to 6% of total U.S. nuclear generating capacity. In addition to the St. Lucie plant near Fort Pierce, Fla., FPL owns the Turkey Point plant near Miami. As of the end of 2016, NextEra also owned about 16% of U.S. wind capacity and 11% of the country’s solar capacity.
NextEra — which had been paying about $3 million in NEI dues annually — quit last month over what it called the trade group’s “irrational and unreasonable policies that would distort electric energy markets.”
Its suit cited NEI-funded studies “that call into question the reliability and costs of the electric system, attempting to create a false sense of panic and unfairly and incorrectly maligning the operations of its members, including the NextEra companies.”
“NEI claims that the ‘grid-based electricity supply portfolio in the United States is becoming less cost-effective, less reliable and less resilient,’” the complaint continues. “Such a thesis is unfounded. In fact, the policies that NEI is advocating would produce those very results by introducing artificial constraints on the way in which an electric system is planned and operated. … As large nuclear generators, the NextEra companies obviously support nuclear energy. But the NextEra companies cannot financially, or otherwise, support an organization that fundamentally mispresents the state of grid reliability in this country.”
Korsnick said NEI’s lobbying in support of Energy Secretary Rick Perry’s call for price supports for coal and nuclear plants followed “a rigorous process for gathering input from member companies to inform our policy positions.”
“On most issues [NEI] does not advocate a position until it has been approved by members of the Executive Committee. NextEra may not have agreed with NEI’s effort to support the continued operation of existing plants, but our work was guided by the interests of our member companies,” she said.
“NEI remains committed to achieving its foundational mission: to preserve, sustain, innovate and grow the nuclear energy industry. All of NEI’s actions should be and are consistent with that purpose. NEI also ensures all decisions and actions taken maintain a safe, effective and well operated nuclear energy fleet. NEI’s commitment to each of those core principles will always be absolute without compromise.”
NEI did not respond to a question about NextEra’s contention that the group is “suffering from financial difficulties.” NextEra cited NEI’s Form 990 for 2015, which it said “shows negative six-figure net assets for the 2015 and 2014 tax years.”
Entergy also Left NEI
Entergy, which operates seven nuclear plants in the U.S., also quit NEI last month, but it has not commented publicly on its reason for doing so.
“NEI has been one of several vehicles through which to advocate our positions on important policy and regulatory issues impacting the nuclear power industry,” Entergy spokeswoman Emily Bealke Parenteau said in response to a question about the company’s departure. “Entergy has made the decision to leverage its other internal and external resources for advocacy efforts.
“While Entergy will no longer be a member of NEI, we have a system in place that replaces PADS. We will continue to engage actively and cooperatively with the industry in both the operations and public policy arenas,” she added.
One industry official with knowledge of the situation said Exelon and some other NEI members view Entergy as a “traitor” for closing its uneconomic merchant nuclear plants rather than fighting for subsidies.
Exelon purchased Entergy’s James A. FitzPatrick nuclear plant in New York after the latter said it would close the plant regardless of whether the state approved zero-emission credits. Entergy also has agreed to close its Indian Point plant under pressure from Gov. Andrew Cuomo.
“Exelon told other NEI members that Entergy effectively forced them to buy [FitzPatrick] — they believed that … to get ZECs passed, they needed solidarity, and Entergy wasn’t playing ball,” the official said. “The fact that Entergy is closing Pilgrim [in Plymouth, Mass.] without a whimper and Palisades [in Michigan] when their contract ends in a few years has some NEI members upset. … Every time that a nuclear plant closes, it hurts their specialty vendors and, as a result, vendors shrink, and remaining ones have some market power. And that raises costs for every remaining plant.”
OKLAHOMA CITY — Spurred on by two of its newest members, the SPP Regional State Committee last week tasked its Cost Allocation Working Group (CAWG) with drafting a report on adding new members and determining their impact on existing cost allocations.
Geri Huser, chair of the Iowa Utilities Board, led the push for the motion, which passed unanimously and came during a report from SPP CEO Nick Brown on the integration of Mountain West Transmission Group into the RTO. She was supported by DeAnn Walker, chair of the Texas Public Utility Commission, and long-time RSC member and Oklahoma Corporation Commissioner Dana Murphy.
“I would like to know we are getting information from our staff on the CAWG and be able to discuss that with other members,” Huser said during the RSC’s Jan. 29 meeting. The CAWG, composed of state commission staff members, reports to the RSC and its commissioners.
“I find it’s difficult for information to be shared in a manner that is timely for those of us that serve on other commissions or boards,” Huser said. “We would like to have as much information as early as possible in the process, so we can make decisions.”
Brown told the regulators that a small negotiating team composed of himself, Board of Directors Chair Jim Eckelberger, Director Larry Altenbaumer, Westar Energy’s Kelly Harrison and Golden Spread Electric Cooperative’s Mike Wise have been meeting “almost daily” with Mountain West representatives as part of a “very concerted effort” to reach a final decision by the end of February. (See SPP, Mountain West Resolving ‘Contentious’ Issues.)
He said SPP is intent on scheduling a “decision meeting” in mid- to late February with the board and Members Committee, to review the results of those negotiations and other closed-door meetings.
“Assuming the board and member companies accept those policy statements, we will engage our normal and very public stakeholder process to take those policy decisions and put them into specific language that would become part of our Tariff,” Brown said. He reminded the RSC that Tariff language and other changes would go through the board before being filed with FERC.
“Many had hoped we would have reached a decision by now,” Brown said. “In my personal view, while we are very close, we’re just not quite there. We have a lot of details that need the full vetting of our Members Committee, which has yet to see the details arrived at by our smaller negotiating team.”
Murphy responded that there were “many who had hoped” a decision wouldn’t have been reached by now. She said she has met with Oklahoma SPP members whose constant concern seems to be the timeline.
“The overarching concern I have, and it was raised by the Integrated System [and its 2015 integration], was the pattern of special meetings,” Murphy said. “I know at least three other states had that issue as well. It’s a little bit concerning to be having off-pattern meetings, given the scope and complexity of this potential integration.”
The commissioners have primary responsibility for cost allocation, financial transmission rights, resource adequacy and remote resources planning issues, and have held two Commissioners Forum meetings on Mountain West. Most of the CAWG members have signed nondisclosure agreements that have allowed them to participate in Strategic Planning Committee meetings on the integration.
That is not enough for some members of the RSC.
“SPP staff has done a good job trying to provide us with information that’s needed, but when things change so quickly, we don’t have time to digest them,” Murphy said. “When we talk about a possible decision being made, I get concerned. We just found out what some of the changes are” in a closed education session.
Brown asked the committee whether it wanted the CAWG report before negotiations end and the board and members consider “high-level” policy matters.
“We’re simply telling them to perform the duties that have been laid out [for the CAWG],” Huser said. “If we provide them with this direction, they can begin preparing and providing us with information.”
“If you started today, it would not be a wasted effort,” Brown said. “We’re prepared to provide a lot of information that’s not going to change.”
The CAWG’s John Krajewski, a private consultant, agreed that, under the group’s New Member Review Process document, enough information on Mountain West’s pending integration had been disclosed to trigger a mechanism to allow the work to proceed.
The RSC asked for an action plan and that the CAWG’s report include — but not be limited to — information on the new members’ transmission facilities and planning, generation and load numbers, and proposed modifications to SPP’s governing documents. The report will also include a cost allocation review of rate standards, impacts to existing members, facilities and entities to which cost sharing applies, and a benefit-cost analysis.
Huser, who said transparency is very important to her, did not let the matter rest. Concerned that the previous discussion might not be reflected in the minutes, just before the meeting adjourned she requested a motion for a special meeting or closed session in April so that the commissioners can deliberate the Mountain West integration. The motion carried unanimously.
Committee Takes on Cost Allocation Issues
The RSC also directed the CAWG to work with staff on identifying cost allocation issues and report back to the committee in April. Members unanimously passed an action item rather than a motion, following a lengthy deliberation over how to word the action.
The vote followed a presentation on cost allocation in wind-rich areas by Sunflower Electric Power’s Al Tamimi, chair of the Generation Interconnection Improvement Task Force. The group has been working to suggest improvements in SPP’s study processes that address the “extreme amounts” of new generation in its interconnection queue and new requirements from FERC-proposed rulemakings.
Tamimi, representing a small entity focused on keeping its customer rates low, said SPP has undergone a paradigm shift in why it builds transmission infrastructure. Projects used to be based on changes in load or in designated resources in the same geographical area where the facilities were built, he said, but today’s renewable generation is built at great distances from load centers, with many wind projects in small load zones exported elsewhere.
This additional wind benefits the SPP market, but not necessarily the local zones, Tamimi said. He said those zones are saddled with two-thirds of the costs of byway projects in SPP’s highway/byway methodology but don’t benefit from the reduced energy costs.
“Load growth is mostly stagnant … in our footprint,” Tamimi said, “but we’re still seeing transmission getting built, we’re still seeing wind being integrated on our system.”
The presentation was eventually swallowed up in the larger discussion of cost allocation and how to frame direction to the CAWG.
“I agree with expanding and looking at the total impact,” Tamimi said. “The wind-rich areas, especially those with small loads and ratepayers, are the ones I’m looking to protect.”
“This is something that needs to be addressed. You did a great job of teeing up the issues,” Southwestern Public Service’s Bill Grant told Tamimi. “We ruled out other possible solutions because of Z2 and other issues we have. The study needs to be comprehensive, not just highway/byway funding. It’s how we plan the system … studying wind deliverability is the low-hanging fruit.”
Tamimi shared with the RSC study results that showed Sunflower, which accounted for 2.41% of SPP’s load from 2011 to 2018, wound up paying $143,874/MW in byway costs for its share of the load. It was the only company above six figures, with second-place SPS at $98,788/MW.
The study, which didn’t include the Integrated System entities, was conducted with data from energy management firm ACES. Working with SPP staff will enable the CAWG to widen its pool of data.
“This is obviously well within the RSC’s authority,” said Kelson Energy’s Rob Janssen, who represents Dogwood Energy and helped develop the highway/byway methodology. “[We] came up with a very strong process that led to wind development and a robust grid, but we’ve gone well beyond the amount of wind we originally thought the customers would want to pay for. I’ve become more and more convinced we need to have a serious look at cost allocation again. I see Sunflower’s presentation as a plea for help, but my concern is where does the stakeholder involvement come in?”
“I’d like to move forward, but not on a really narrow path,” Walker said. “This discussion has gone beyond wind-rich areas. I don’t think you can look at the wind-rich areas and what Sunflower has raised in a vacuum or a silo.”
SPP staff pushed back on the RSC’s direction, pointing out the Strategic Planning Committee had just held a long discussion on transmission planning and energy-only resources two weeks prior. (See “Energy-only Resources Report Leads to Discussion, not Results,” SPP Strategic Planning Committee Briefs.)
“We’re respectful of the urgency Sunflower has shown, but this is just one of half a dozen issues that all need to be addressed together, rather than in one-off ways that tend to create unintended consequences,” Brown said. “We’re trying to get our hands around all the issues we’ve discussed over the last six months and determine the best way to tackle these in a comprehensive way.”
“I don’t know if the RSC members are aware of what the SPC issues are,” pointed out RSC Chair Shari Feist Albrecht, of the Kansas Corporation Commission.
Eckelberger expressed his support for the motion, before it was transformed into an action item.
“From my point of view, broader would be better,” he said. “What bothers me a lot is that we’ve seen this come along for three to four years now in the wind-collection areas. They’re being hurt. We need to do something to make sure equity comes out of the planning process as soon as we can. Let’s take that small step to see what’s really wrong here with the lack of equity and who’s paying the bills.”
RSC Agrees with Working Group’s Recommendations
While not being saddled with additional work, the CAWG also brought forward several recommendations to the RSC, all of which passed.
The committee endorsed the working group’s lessons learned from its work on SPP’s aggregate study safe harbor criteria. Safe harbor is applied when the utility granted a transmission service request (TSR) has no more than 20% of its designated resources (used to meet a load-serving entity’s capacity margin requirement) coming from wind or has designated resources greater than 125% of forecasted load, and when it has a five-year minimum commitment for the TSR.
Among the CAWG’s suggestions were to work with staff and stakeholders to come up with a reasonable methodology in updating the $180,000 safe harbor amount, determine whether the 125% criterion adversely affects smaller transmission customers and verify whether the original concerns that led to the 20% wind limit still exist.
“We just don’t have the algebraics [on the CAWG],” joked Adam McKinnie, chief utility economist with the Missouri Public Service Commission who was deeply involved with the group’s work.
The CAWG also recommended the RSC endorse the Supply Adequacy Working Group’s revision request (RR251) that addresses three issues FERC used in rejecting SPP’s resource adequacy package last year. (See FERC Again Rejects SPP’s Resource Adequacy Revisions.)
SPP Works on Response to FERC Resiliency Inquiry
But the CAWG didn’t monopolize the RSC’s agenda. Brown also briefed the committee on SPP’s planned response to FERC’s review of how RTOs define and ensure resiliency, which was initiated following the commission’s rejection of the Department of Energy’s call for cost-of-service payments to coal and nuclear generators. (See FERC Rejects DOE Rule, Opens RTO ‘Resilience’ Inquiry.)
Brown said staff have crafted its initial thoughts on the set of 39 questions FERC has asked in the docket (AD18-7) and will work with the SPC to compile stakeholders’ thinking on a “topic that is extraordinarily broad.”
“FERC raises any number of questions, many of which are outside the roles of at least this RTO,” he said. “We initially considered seeking an extension of time, but after seeing the questions, they’re so broad that the most the commission could be looking for at this point is initial thinking. We realized there’s no way in the world we could attain any consensus.”
The SPC has scheduled a Feb. 23 webinar to discuss the draft of responses, which will be distributed by Feb. 20, and will solicit additional input. Final comments will be due March 2, so that SPP can meet FERC’s March 9 deadline.
“It will be interesting to see what this morphs into,” Brown said. “I could see this going nowhere on one extreme, or on the other extreme we end up with a whole portfolio of resiliency standards, to which the industry must comply.”
RSC-Related Membership Changes
January’s RSC meeting was the first for Albrecht as its chair. She replaces Steve Stoll, who left the committee when his term on the Missouri PSC ended. Stoll was replaced on the RSC by Missouri Commissioner Scott Rupp.
The committee expects to add Louisiana Public Service Commissioner Foster Campbell for April’s meeting.
Albrecht and Paul Malone, chair of the Markets and Operations Policy Committee, are working to fill two vacancies on the Regional Allocation Review Task Force, which works with both committees to define the analytical methods using in reviewing the reasonableness of regional and zonal cost allocation.
Dennis Grennan, with the Nebraska Power Review Board, assumed the task force’s chairmanship on Jan. 1.
On Jan. 24, the Senate Energy and Natural Resources Committee held a hearing “To Examine the Performance of the Electric Power System Under Certain Weather Conditions, Focusing on the Northeast and Mid-Atlantic Regions.” The witnesses included Andy Ott, CEO of PJM. (See FERC, RTOs: Grid Performed Better in Jan. Cold Snap vs. 2014.)
In 2016, PJM’s fuel mix was 35% nuclear, 34% coal, 26% gas and almost 5% renewables.1 The data PJM collected during the recent bomb cyclone proves at least two important points. The first is that we need coal-fueled power plants. The second is that we should be cautious about relying too much on natural gas to generate electricity.
Coal Fleet
Over a four-day period (Jan. 3-6, 2018), when the average daily temperature was 12 degrees Fahrenheit, PJM relied heavily on so-called conventional sources of baseload electricity, namely coal and nuclear. Some have implied that these fuel-secure sources of baseload electricity are outmoded, which seems to suggest that we don’t really need them anymore. However, over the four-day period, these “outmoded” electricity sources were responsible for almost two-thirds of PJM’s electricity:2
Jan. 3: 61% (coal + nuclear)
Jan. 4: 64% (coal + nuclear)
Jan. 5: 64% (coal + nuclear)
Jan. 6: 64% (coal + nuclear)
Overall, coal was responsible for 37% of PJM’s electricity over the four-day period, with nuclear providing 27%, natural gas 22% and wind 2%.
Natural Gas
PJM provided data on forced (unplanned) outages caused solely by fuel supply problems, as well as forced outages for all causes.3 The chart on the left below is based on PJM data and shows that on Jan. 5 when electricity demand peaked (wind chill temperature was minus 5 degrees that day4), natural gas-fired power plants experienced 14 times more forced outages (4,395 MW) because of fuel supply issues than the PJM coal fleet (306 MW). The chart on the right shows all forced outages. This chart shows that natural gas-fired power plants experienced 9,252 MW of forced outages versus 6,082 MW for the coal fleet. In short, the coal fleet outperformed the gas fleet when electricity was needed most by PJM.
| ACCCE
What’s my point?
During the bomb cyclone, PJM relied heavily on its coal fleet. Unfortunately, some 54,000 MW of coal-fueled generating capacity in PJM, MISO, ERCOT and SPP will have retired by the end of 2020.5 Nationwide, more than one-third of the coal fleet — 111,000 MW, so far — has shut down or plans to close.6 According to the U.S. Department of Energy, the retirement of fuel-secure electricity sources, such as coal, is threatening the reliability and resilience of the electricity grid.7 There are a number of steps that should be taken to preserve the coal fleet, including properly valuing the reliability and resilience attributes of the fleet in wholesale electricity markets.
Paul Bailey is CEO of the American Coalition for Clean Coal Electricity.
3Data based on PJM Operating Committee PowerPoint presentation, “Cold Weather Summary, Dec. 27, 2017–Jan. 7, 2018,” Jan. 25, 2018. (“Jan. 25 PJM presentation”) Besides unplanned outages due to fuel supply problems, PJM lists other causes as “boiler system, fuel system, electrical, emissions/environmental, pumps/fans, start failure, unit trip and other.” http://www.pjm.com/-/media/committees-groups/committees/mrc/20180125/20180125-item-10-cold-weather-summary.ashx
4Jan. 25 PJM presentation.
5ACCCE, “Retirement of U.S. Coal-Fired Electric Generating Units, Status as of Jan. 17, 2018.” As of mid-January, some 45,000 MW of coal-fueled generating capacity in RTO/ISO regions had retired. An additional 14,500 MW are expected to retire over the 2018-2020 period. Two-thirds of these future retirements have been attributed to wholesale electricity market conditions. http://www.americaspower.org/wp-content/uploads/2018/01/Coal-Unit-Retirements-Jan-2018.pdf
