FERC last week denied requests for rehearing on a formula rate it approved in April for Northeast Transmission Development’s construction of a transmission line across the Delaware River (ER16-453).
A graphical depiction from PJM of the proposed line across the Delaware River
Both NTD and the Delaware Municipal Electric Corp. had requested rehearing of the order, though for opposing reasons. NTD argued the commission erred in denying it a 50-basis-point risks and challenges return on equity adder in its initial order, while DEMEC argued the commission erred in granting NTD a 50-basis-point adder for joining PJM and turning over operational control of the line to the RTO upon completion.
DEMEC had also argued that FERC erred in allowing any of NTD’s affiliates or subsidiaries to use the rate. The commission also denied this, clarifying that it applies to any affiliates or subsidiaries that may be formed in the future as well.
The efforts might all be for nothing though, as NTD’s line is part of the Artificial Island project, which has been mired in years of delay. The project — PJM’s first competitive solicitation under FERC’s Order 1000 — is undergoing reanalysis and scope changes that won’t be known until at least April. (See PJM Analysis on Artificial Island Project Delayed Again.)
FERC on Wednesday accepted transmission calculations submitted by Southwestern transmission-owning utilities in support of their requests for market-based rates in their balancing areas.
But the commission’s approval of the simultaneous import limit (SIL) values provided by the Arizona and New Mexico utilities was accompanied by pointed advice about how FERC expects SIL studies to be performed and reported in the future (ER10-2302, et al.).
| APS
The commission’s Jan. 24 decision directly affects Arizona Public Service, El Paso Electric, Public Service Company of New Mexico (PNM), Tucson Electric Power, UNS Electric and UniSource Energy Development in Arizona and New Mexico. Also included in the order, which included 10 dockets, were Public Service Company of Colorado, Northern States Power and Southwestern Public Service Co., which submitted their SIL analyses at about the same time as the Southwestern companies in an effort to help FERC expedite its approval process for such studies.
PNM’s application for market-based rate authority within its own territory was rejected by FERC in October 2015 in part because of an inadequate SIL analysis. The PNM order was issued at the same time the commission issued a rule to clarify and streamline its MBR program, the first major update to the policy since codifying it in Order 697 in 2007 (RM14-14). (See FERC Refines Market-Based Rate Rules.)
The commission said it will use the accepted SIL values when reviewing updated market analyses submitted by the Southwestern transmission owners, as well as those filed by non-transmission-owning entities in the region.
Order 697 requires a utility to perform SIL studies in order to determine the amount of available transmission capacity that can serve the utility’s home market “under the most limiting normal and single-contingency operating contingencies.” The analysis is designed to determine how transmission constraints will limit energy imports to compete with the utility controlling the area.
The study, which examines transmission links with “first-tier” — or neighboring — balancing authority areas (BAAs), is expected to provide “a reasonable simulation of historical conditions” rather than a theoretical maximum transfer capability between areas.
FERC’s order commended the Southwestern utilities, which in many cases function as first-tier BAAs for each other, for coordinating the preparation of their SIL studies and sharing SIL values with each other.
“Such a coordinated approach leads to more accurate and consistent SIL study results,” the commission said, noting that the submitted studies were “generally” done correctly. “However, our review of the SIL studies and acceptance of the SIL values was hindered and delayed because of various modeling issues and incomplete or ambiguous reporting of results.”
In light of those shortcomings, the commission outlined guidance for submitting SIL studies. FERC said future filers:
Should study system contingences in both the home and first-tier areas that are historically used and identified in the energy seller’s available transfer capability and OASIS practices documentation.
Should furnish documentation showing that the contingency lists provided align with the BAA’s OASIS practices. A “valid” contingency would consider the realistic conditions and operating procedures for the home and first-tier areas.
Must consider that, if a contingency does not solve in a powerflow simulation, it could be difficult proving that the contingency would not cause an overload somewhere within the system. That could affect SIL values, the commission said.
Should ensure the accuracy of transmission line ratings in the home and first-tier areas.
May use historical capacity factors for certain energy-limited resources, such as hydroelectric and wind capacity.
Should explain the reason for changes in SIL values from previous studies and identify significant changes in the system, such as major generation additions or retirements and construction of new high-voltage lines.
ALBANY, N.Y. — Standard utility rate cases in New York can now be expected to include innovative rate designs and programs to encourage energy efficiency and clean energy technologies following Tuesday’s action by the Public Service Commission.
In its approval of the three-year Consolidated Edison rate plan (16-E-0060, et al.), the PSC also passed a companion order that advanced the state’s Reforming the Energy Vision initiative (15-E-0229).
Heat Map of Behind-the-Meter Solar in 2015 and 2030 | NYISO
Con Ed’s March 2016 filing was in compliance with the PSC’s December 2015 Targeted Demand Management Program order, which allow utilities to propose non-wire alternative (NWA) projects that replace or defer the need for transmission and distribution infrastructure through customer-side distributed energy resources or load reductions.
The commission’s latest orders specify the utilities’ incentives for such investments, with most the financial benefits returned to ratepayers.
“This is a big step on the way to implementing REV,” Commissioner Gregg Sayre said at the meeting. “The REV orders only give us a framework and policy guidance on this process, and it’s in cases like this where the rubber meets the road and real progress is made.”
A benefit-cost analysis would be performed for any NWA, with various checkpoints set up through the approval and implementation processes to verify its viability, the order states.
The order adopts Con Ed’s proposed incentive mechanism, but the commission reduced the utility’s proposal of a 50-50 split of the benefits between shareholders and ratepayers. The order provides 30% of the net benefits to shareholders and 70% to ratepayers.
“As the commission articulated in the REV Track Two Order, incentive opportunities should be financially meaningful and structured such that they encourage enterprise-wide attention at the utility and spur strategic, portfolio-level approaches beyond narrow programs,” the order states. “Further, incentive opportunities should be commensurate with the level of financial risk borne by utility shareholders.
| Edison
“The 30% sharing adopted here represents a financially meaningful incentive opportunity that should encourage Con Edison to pursue the innovative portfolio-level approach to implementing NWA projects, while producing significant net benefits to customers and reflecting the financial risk required of Con Edison shareholders,” the order continues.
Commissioner Diane Burman abstained on the Con Ed order, “consistent with my past voting record.”
Burman says she prefers a “holistic approach” rather than deal with these items individually. “I think there’s a lot here that is affecting other items that are still policy decisions that have not had finality, and we will work through that,” she said.
Con Ed is already using demand management in a pilot program, the Brooklyn-Queens Demand Management program. It deferred a $1.2 billion substation with a combination of energy efficiency, DERs and demand response. (See Overheard at the NYISO Distributed Energy Resource Workshop.)
A new, “expedited” CAISO initiative seeks to establish a process for selecting and procuring black start resources, needed to restore segments of California’s transmission system in the event of regional outages.
The effort will follow an ambitious timeline: The ISO hopes to present a plan to its Board of Governors for approval in May.
The initiative represents the second phase of a 2013 undertaking to address NERC reliability standard EOP-005-2, which required transmission operators to draw up plans for system restoration in the event of widespread blackouts.
The ISO decided to explore the procurement issue after identifying a need for additional black start resources in the transmission-constrained San Francisco Bay Area.
CAISO’s black start procurement initiative was prompted by the need to better prepare the transmission-constrained San Francisco area for system restoration. | SF Travel
“This need is the impetus for this stakeholder initiative,” Scott Vaughan, CAISO lead grid assets engineer, said during a Jan. 24 call to kick off the effort.
CAISO staff have determined that, unlike in Southern California, where black start resources are more evenly distributed near major load centers and can provide more rapid restoration, resources serving the Bay Area are relatively far from population centers.
Under current practice, ISO and transmission owner restoration plans rely on black start resources either owned by a utility or acquired through a long-term contract. For a TO plan, a utility is able to recover the costs for resources through retail rates. Generation providing black start capability under the ISO’s plans are subject to a three-party agreement among the ISO, the applicable TO and the generator for a zero-price term.
Still, CAISO’s Tariff allows it to enter into black start service contracts for payment. If specific costs are not outlined in a contract, then the resource will be paid as exceptional — or out-of-market — dispatch and is entitled to bid cost recovery. The Tariff also outlines that scheduling coordinators can be required to pay for the service.
The new initiative would likely modify the current approach to procuring black start capability by ensuring that costs are spread beyond just the transmission-owning utility.
“Any such procurement would benefit all transmission customers in the area, yet may not result in the allocation of costs to all transmission customers if procured by the investor-owned utility,” said an ISO issue paper, released Jan. 17, in reference to the Bay Area’s specific need. “For instance, non-bundled customers taking service from a community choice aggregator, electric service provider or municipal utility in the area that rely on the black start capability may not face any cost allocation.”
CAISO has floated two ideas for cost allocation. The first would have the ISO enter black start contracts and charge all scheduling coordinators, rather than specific TO areas, for incremental black start capability. The other idea would entail it shifting cost allocation to local transmission access charge areas and recovering the costs from TOs as reliability service costs.
The Bay Area, however, poses unique challenges for black start procurement. One is the lack of eligible resources there.
“The ISO has said that there is a relatively small set of units from which this service could be procured,” said Brian Theaker, director of market affairs at NRG Energy. “Will the ISO disclose what that subset of units is?”
CAISO staff were reluctant to wade into that aspect of the issue before laying out a framework for procurement.
“At this point, we were not planning on getting into any more of the details around the specific requirement in the area or how we would go about procuring,” said Neil Millar, CAISO executive director of infrastructure development. “The goal right now is to land on the cost allocation process and the procurement process itself that would set out how we would go about doing this.”
Robert Jenkins of Flynn Resource Consultants picked up on Theaker’s theme.
“I was looking for what kind of characteristics is the ISO valuing in identifying this small number of units,” Jenkins said. “Is it geography? Is it size? Is it connectivity” to the ISO’s system? He added that he would be interested in learning more about the scope of the market when that information became available.
Millar responded by offering some qualifications, pointing out that CAISO wanted stakeholders to consider the procurement issue within the context of the relatively small number of resources eligible to participate in the market.
“It’s not a case of any generator located anywhere in the system,” Millar said. “Location does matter very much and there’s a relatively small subset, so that could affect people’s input on how we should go about planning this procurement process to pick a couple of units out of a relatively small subset.”
Bonnie Blair, a consultant representing the “Six Cities” utilities of Anaheim, Azusa, Banning, Colton, Pasadena and Riverside, pressed the ISO on the importance of the location of the resources.
Millar explained the “piecemeal” approach of restoring a part of the system after a blackout. The ISO starts by first bringing up a black start resource, then energizing individual transmission lines and “picking up other generators, a bit of load, more generators, then more load” to reach into the affected areas.
“So as you keep considering sources further and further away, you quickly get to where the time it would take to do all those steps wipes out the benefit of getting the resource in the first place,” Millar said.
Paul Nelson, electricity market design manager at Southern California Edison, wanted more specifics on the timeframe for acquiring the resources.
“Is this something that needs to be done in 2017, 2018?” Nelson asked. “Because that impacts the approaches for procuring it.”
“We’d like to have some sort of contractual arrangement by the beginning of 2018 or end of 2017,” Vaughan replied, adding that the small set of potential resources are not identified as black start capable and would likely require upgrades.
Theaker questioned whether the ISO schedule for completing the initiative was realistic, given the need to deal with issues of “compensation, context, structure and cost allocation,” as well as to draw up a straw proposal.
“It’s highly aggressive, but I think it is realistic,” Vaughan responded.
“Then I’d encourage you to identify some near-term milestones in terms of what has to be in place [and] when, in order to get this ready — not only for the board meeting in May, but also lay out the milestones for getting [resources procured by January 2018], as we’ve just discussed,” Theaker said.
Comments on the issue paper must be submitted to CAISO by Jan. 31. The ISO will publish a straw proposal Feb. 14.
WASHINGTON — President Trump on Thursday appointed Commissioner Cheryl LaFleur as acting FERC chair, replacing Norman Bay.
Hours after the announcement, Bay said he would resign his post Feb. 3, 16 months before the end of his term.
Bay’s departure, announced in a six-page letter reciting the agency’s recent accomplishments, will leave the commission with only LaFleur and fellow Democrat Colette Honorable — one member short of the three-person quorum required to issue other than routine orders. (See related story, Backlog, Delays Feared as FERC Loses Quorum.)
That will add urgency to the need to fill the three vacant Republican seats on the five-member panel. It could allow the reappointment of Honorable, whose term expires June 30 and was otherwise expected to be replaced by a Republican.
Calling his service on the commission “the greatest honor and privilege of my professional life,” Bay praised his fellow commissioners and the “dedicated and talented career staff” with whom he had worked.
“The last few years have brought dramatic change to the energy space. The shale revolution and an abundance of low-priced natural gas, technological innovation, the expanded use of renewable energy, increased energy efficiency and flat load growth, state and federal public policy, and consumer choice have been drivers for change,” Bay said. “As chairman, I have sought to help consumers realize the benefits from this change, while assisting the wholesale markets and industry in adapting to the change and maintaining just and reasonable rates and reliability.”
LaFleur’s Focus
LaFleur said she will remain focused on the same priorities as before: system reliability, grid security, transmission, energy supply diversity “and trying to adapt competitive markets to some of the state initiatives that we’ve seen.”
“While I recognize that FERC is in a state of transition as we await nominations to fill vacant seats at the agency, it is important that FERC’s work on the nation’s energy markets and infrastructure move forward,” she said in a statement. “I would particularly like to thank Chairman Norman Bay for his leadership of the commission over the past two years, and I look forward to working with him, Commissioner Colette Honorable, the terrific staff throughout the agency and future colleagues at FERC to continue to address the important energy issues facing our nation.”
Honorable issued a statement Monday praising Bay for his “grace and humility.”
“His leadership was critical for our continued work on gas and electric coordination, competitive transmission development, price formation and energy storage,” she said. “The utility sector is in the midst of profound change, and former Chairman Bay made certain that the commission kept pace and did not leave consumers behind.”
Republican Distrust
LaFleur’s appointment as acting chair suggests Bay never overcame the distrust of Republican congressional leaders, who had sought to keep LaFleur in the top spot she had ascended to after Jon Wellinghoff’s departure in November 2013.
President Barack Obama nominated Bay as chairman in a move engineered by then-Senate Majority Leader Harry Reid (D-Nev.), who publicly said he did not want LaFleur as chairman.
Bay was confirmed on a 52-45 party-line vote in July 2014, following a deal with the White House that delayed his move to the chairmanship for nine months. LaFleur was confirmed to a second term at the same time by a 90-7 vote.
Cheryl LaFleur and Norman Bay being sworn in at their Senate confirmation hearing in May 2014.
The deal was a concession to those who questioned why Bay — who had served as director of FERC’s Office of Enforcement since 2009 but had never served as a state utility regulator — would be appointed directly to the chairmanship over LaFleur, a former utility executive who has served on the commission since 2010. The last five chairmen before then had served a median of 30 months before becoming chair.
Bay also came under fire for what some energy lawyers and legislators called his heavy-handed running of the commission’s enforcement division.
Bay’s appointment to the chairmanship was strongly opposed by Sen. Lisa Murkowski (R-Alaska), ranking member at the time, now chairman of the Senate Energy and Natural Resources Committee. Sen. Mitch McConnell (R-Ky.), now Senate majority leader, said he feared Bay would be a “rubber stamp for the [Obama] administration’s anti-coal agenda.” (See At FERC, Uncertainty Remains Despite Norman Bay’s Nod.)
Republican Majority Coming
LaFleur acknowledged that her return to the center seat at the commissioners’ table is likely temporary. In a podcast posted Monday, she said that her appointment and Bay’s resignation made for “a pretty strange week.”
“I’d already decided to serve out my term,” she said. “I’ve been part of the Democratic majority ever since I’ve been here, and I knew that going forward I would be part of a Democratic minority, and if I was going to be here, and asked to lead, I thought I should.”
Although the commission has not traditionally been marked by partisan divisions, the president gets to appoint members of his party to three of the five seats and to pick the chairman. Since Republicans Philip Moeller and Tony Clark left, the five-member panel has been all Democrats.
Carolyn Elefant, a former FERC attorney advisor and partner at a D.C. law firm specializing in energy regulatory issues, wondered why the Trump administration didn’t have a Republican ready to fill the slot immediately. “I cannot recall a time in my 27 years of FERC practice that the commission has been down to two members,” she said.
“I know that Sen. Murkowski has posted a statement on the Senate Energy Committee website about the importance of filling the seats promptly, but I don’t know how much pull she has with the administration,” Elefant said.
“The fact that Commissioner LaFleur — a Democratic appointee — was elevated to the chairmanship suggests to me that the administration hasn’t given much thought to FERC appointments; if it had, I would have expected a Republican nominee for chairman right out of the gate.”
Differences over Enforcement
LaFleur and Bay have always been cordial publicly, regardless of which one of them held the gavel. But they have had differences on policy.
When Bay was enforcement chief, FERC won more than $670 million in fines and disgorged profits from Morgan Stanley, Constellation Energy, Deutsche Bank and JPMorgan Chase.
Although LaFleur supported all of the settlements Bay brought to the commission, the two have not always seen eye-to-eye. In response to questions from the Senate, LaFleur detailed seven cases in which she issued separate concurrences or dissented from the majority on matters such as the way the commission applied its penalty guidelines or when it would share deposition transcripts with investigation targets.
Subjects in four of the cases LaFleur cited were represented by former FERC General Counsel William Scherman, who coauthored an Energy Law Journal article in May 2014 accusing Bay’s unit of ignoring subjects’ due process rights. Scherman and some other members of the energy bar had been criticizing Bay’s enforcement tactics privately and in industry forums for months.
The criticism became louder when the principals of Powhatan Energy Fund, which had been under investigation by Bay’s unit for three years without being charged, released documents they say prove they had been unfairly hounded.
On Bay’s last day as enforcement chief in August 2014 — before his swearing in to the commission — FERC issued a “notice of alleged violations” against Powhatan and its principals accusing them of market manipulation for making riskless back-to-back up-to-congestion trades to profit on line-loss rebates. In May 2015, the commission ordered Powhatan and its leaders to pay $34.5 million in penalties and disgorged profits in the case (IN15-3). The company is fighting the case in U.S. District Court for the Eastern District of Virginia.
Policy Changes?
Elefant said that once the Trump administration installs its three new members, FERC is likely to act swiftly to undo many of Bay’s enforcement initiatives. “I think that many of his aggressive enforcement policies will be dismantled — if not immediately, then once other commissioners are appointed,” she said.
But attorney Ken Irvin, co-leader of Sidley Austin’s global energy practice, said he doesn’t see anti-manipulation enforcement being significantly curtailed. “They’ve made a robust effort and collected a lot of monetary penalties,” he said in a statement. “I don’t expect to see any let-up.”
The Long Island Power Authority on Wednesday approved a contract for a 90-MW offshore wind farm, by far the largest such facility contemplated in the U.S.
The site, 30 miles off the island’s Southern Fork, is the first part of a wind development in federally leased waters that could support up to 1,000 MW of offshore wind.
Gov. Andrew Cuomo two weeks ago proposed the state develop 2,400 MW of offshore wind in various sites off Long Island to support the goal of 50% renewable energy by 2030. He also prompted the LIPA Board of Trustees to act on contract negotiations that had stalled since the summer. (See Cuomo Proposes 2,400 MW of Offshore Wind by 2030.)
The wind farm could provide enough electricity to power 50,000 homes. If the Cuomo proposal is realized, as many as 1.25 million homes could be powered.
The wind farm developer, Deepwater Wind, built the nation’s first offshore wind farm off Block Island in Rhode Island, which was commissioned last month.
The LIPA board approved a contract submitted by Deepwater Wind for the South Fork Wind Farm after a yearlong process. Offshore wind was the lowest-cost option in the request for proposals from LIPA, beating out natural gas generation.
Neither LIPA nor Deepwater released contract terms on Wednesday.
The 20-year power purchase agreement includes a pay-for-performance clause, which allows LIPA to only pay for delivered energy, eliminating operating and construction risk, the authority said. LIPA said technology improvements reduced the project’s “all-in” energy costs to be competitive with other renewable energy sources.
“Depending on the schedule for permitting, construction could start as early as 2019, and the wind farm could be operational as early as 2022,” Deepwater spokeswoman Meaghan Wims told RTO Insider.
LIPA CEO Tom Falcone said in a statement, “We are confident this is the first step to developing the tremendous potential of offshore wind off Long Island’s coast and meeting Gov. Cuomo’s Clean Energy Standard. This project is the right size, at the right location and demonstrates how smart energy decisions can reduce cost while providing renewable energy and clean air for all of Long Island.”
Elizabeth Gordon, director of the New York Offshore Wind Alliance, said, “LIPA’s 90-MW South Fork project moves New York to the forefront of offshore wind development in America. Major progress on what will be the nation’s largest offshore wind project, combined with Gov. Cuomo’s 2,400-MW commitment, makes it clear that New York is entering a new energy era — one where offshore wind power is poised to play a key role in meeting downstate’s electricity needs.”
FERC last week approved NYISO’s revised demand curves but said the ISO must eliminate the assumption that new peaking plants in the New York Control Area (NYCA) will require emissions controls (ER17-386).
The Jan. 17 order approved NYISO’s Nov. 18 proposal on all but one of nine contested issues. The new demand curves will take effect with the ISO’s capacity auction for the 2017/18 capability year beginning May 1 and will be the basis for auctions through the 2020/21 delivery year. (See IPPNY: Demand Curve Reset ‘Top Priority’.)
The ISO will continue to use the F class frame peaking turbine as the proxy unit for setting the cost of new entry. It also continued the requirement that peaking plants include dual-fuel capability and selective catalytic reduction (SCR) emissions controls for the New York City, Long Island and G-J Locality demand curves.
But the commission rejected the ISO’s proposal to extend the SCR requirement to the NYCA, where gas-only designs were permitted.
The curves, calculated for NYISO by consulting firm Analysis Group, suggest increased prices in most zones, with Zones G-J starting at about $22/kW-year, up from less than $20 for 2014/15. Long Island’s curve starts at almost $25, versus about $21 in the previous curve. The New York City curve is virtually unchanged with a $26 starting point.
The NYCA curve would have jumped from a starting point of about $14 to almost $20.
In its last demand curve reset, the ISO proposed that the NYCA peaking plant operate under an annual operating hours limit in lieu of installing SCR emissions controls. FERC said that assumption still holds, despite the ISO’s contention that peakers without the controls risk not obtaining necessary air permits.
“It is undisputed that SCR emissions controls are not required for peaking plants located in load zones C and F in NYCA,” the commission said. “In addition, NYISO admits that the F class frame turbine can meet the New Source Performance Standard requirement to limit nitrogen oxides emissions while operating on natural gas without SCR emissions controls.”
The ISO acknowledged that F class turbines can meet New Source Performance Standards for carbon dioxide emissions without SCR controls by limiting their operations to 3,300 hours annually, a capacity factor limit of 38%.
The Independent Power Producers of New York joined the ISO in calling for the SCR inclusion, contending that increasing concern in New York over fossil fuels will pressure the state’s Siting Board to require tougher controls.
FERC said their position was “speculative,” quoting from its order in the last reset that “while there is always a risk that regulations will change in the future, we cannot base the finding of viability on speculation that the EPA or New York state regulators will act at some point in the future.”
It noted that the demand curve reset process takes place every four years “so that changed circumstances, such as new regulations, can be taken into account.”
“We find more compelling the statements from [the New York State Department of Environmental Conservation] and evidence that New York state has issued air permits and Article 10 certificates for electric generators without SCR emissions controls in recent years. Specifically, NYSDEC stated in its comments to the NYISO Board of Directors that its permit reviews are fact specific, so SCR emissions controls to limit nitrogen oxides emissions “may not be required or appropriate in every case, such as where other control measures are available or where a facility accepts federally enforceable permit conditions to limit emissions below the applicable thresholds.
“We are more persuaded by NYSDEC’s comments and N.Y. Siting Board precedent than speculation about future public involvement in [plant] certification proceedings,” the commission said.
The commission ordered the ISO to file a revised Tariff within 30 days removing the SCR requirement for NYCA.
FERC otherwise approved the ISO’s filing as is, siding with it on the choice of the F class turbine, peaking plant costs, property tax treatment, natural gas forecasts, and incorporation of shortage pricing into the net energy and ancillary services revenues assumptions.
The auction for the 2017 summer capability period (May 1- Oct. 31) will be conducted March 30-31, with results posted April 4.
Two energy sellers that engaged in market manipulation during the Western Energy Crisis of 2000/01 will be prohibited from using the costs associated with illegal trading activity to offset the amount of money they’re expected to refund back to California, FERC has ruled.
The commission will also hold an evidentiary hearing to determine which cost offset claims submitted by Shell Energy North America and Hafslund Energy Trading stemmed from crisis-period trading practices such as “false exports,” “phantom ancillary services” and “false load scheduling” — all of which contributed to the widespread manipulation that bilked California ratepayers for billions of dollars (EL00-95-295). (See related story, FERC Denies Multiple Energy Crisis Rehearing Requests.)
Bankrupted by high wholesale electricity costs during the 2000-01 Western Energy Crisis, Pacific Gas and Electric is party to the ongoing proceedings related to market manipulation during the period.
“We find that sellers should not be permitted to offset their refund liability by the costs incurred while engaged in activities in violation of the then-effective tariffs,” the commission said in its Jan. 23 order.
Under the commission’s refund methodology, prices for all short-term sales into CAISO and the now-defunct California Power Exchange are to be capped at a specific “mitigated market clearing price,” with sellers expected to refund amounts above that level.
The commission initially allowed generators who believed that the mitigated price did not cover their operating costs to file cost-of-service rates in order to recover full costs, a provision that was later extended to energy marketers such as Shell and Hafslund for recovery of costs associated with their transactions.
FERC’s decision comes after California petitioned the 9th U.S. Circuit Court of Appeals to contest the commission’s previous acceptance of cost offsets submitted by Shell and Hafslund, a petition that the court held in abeyance.
The California parties — which include the state’s attorney general, the California Public Utilities Commission, Pacific Gas and Electric and Southern California Edison — later filed a brief with the commission contending that the two companies’ offset claims included costs associated with illegal trading activities.
The commission last year took up the issue on voluntary remand after getting approval from the 9th Circuit.
FERC’s decision reopens the record on the proceeding and allows participating parties to supplement existing information. The commission also encouraged the parties to reach a “mutually acceptable” settlement ahead of a new hearing.
“We note that there have been numerous settlements already filed and approved by the commission in the refund proceeding and related proceedings,” FERC said.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:30)
Members will be asked to endorse the following manual changes:
A. Manual 11: Energy & Ancillary Services Market Operations and Manual 12: Balancing Operations. Revisions to account for the updated regulation requirement developed by the Regulation Market Senior Issues Task Force. (See “Regulation Requirement Changing from ‘Peak’ to ‘Ramp,’” PJM Operating Committee Briefs.)
4. Underperformance Risk Management Senior Task Force (URMSTF) (10:00-10:15)
Members will be asked to endorse proposed revisions to the Tariff and Reliability Assurance Agreement specifying requirements for external resources seeking qualification under Capacity Performance rules. (See No End in Sight for PJM Capacity Market Changes.)
5. Energy Market Uplift Senior Task Force (EMUSTF) (10:15-10:45)
Members will be asked to endorse a Phase 1 proposal endorsed by the task force and to discuss whether to proceed with a vote on the Phase 2 proposal in light of FERC issuing a Notice of Proposed Rulemaking on the topic last week. (See related story, FERC Proposes More Transparency, Cost Causation on Uplift.)
Members will be asked endorse proposed Tariff, Operating Agreement and RAA revisions that clean up definitions.
Members Committee
Consent Agenda (2:20-2:25)
Members will be asked to endorse:
B. Operating Agreement revisions associated with residual auction revenue rights enhancements.
C. Revisions to the Tariff resulting from discussions at special Planning Committee sessions regarding new service request cost allocation and study methods. (See PJM Considering Injection Rights for Demand Response.)
D. Tariff and Operating Agreement revisions developed by the GDECS.
2. Underperformance Risk Management Senior Task Force (URMSTF) (1:40-2:00)
Members will be asked to endorse proposed Tariff and RAA revisions specifying requirements for external resources seeking qualification under CP rules. (See MRC item 4 above).
DALLAS — During an unusually animated meeting last week, SPP’s Strategic Planning Committee eventually agreed that it was the correct body to take up the contentious issue of cost shifts when new members join existing transmission-pricing zones.
“I think this is a policy decision all the way, and this is where [the discussion] should be held,” SPP Director Harry Skilton said.
Skilton’s comments were echoed by other members — and by staff — and helped wrap up an hour-long discussion that revisited charges over whether SPP had circumvented the stakeholder process last October, when Kansas City Power & Light’s proposal to revise the zonal-placement criteria was pulled from the Regional Tariff Working Group and given to the SPC. (See SPP Moves to Head off KCP&L Measure on Tx Cost Shifts.)
After several stakeholders said the stakeholder-driven process had been overridden when KCP&L’s revision request had been “arbitrarily” pulled from the RTWG, SPP CEO Nick Brown grabbed a microphone.
“I take issue with the use of the word ‘arbitrarily,’” Brown said. “From a strategic perspective and a regulatory perspective, and in many board members’ view, we were heading down a road that would not have been good for our reputation. We would have been using the wrong tools, and there were a lot of people involved in that debate.”
“This characterization that we have hijacked the process is just false,” said Michael Desselle, SPP’s vice president of process integrity. “We have followed the process.”
Several members pointed a finger at South Central MCN’s Noman Williams, who chaired the Markets and Operations Policy Committee last year, for taking KCP&L’s proposal (RR 172) away from the RTWG. Williams did not attend last week’s SPC meeting, but he later said that he and RTWG Chair David Kays, of Oklahoma Gas and Electric, discussed where the revision request belonged.
Kays “recognized the potential for broader policy issues,” Williams told RTO Insider. “I agreed and said I thought there were broader policy issues that had historically resided at the SPC and board, and that I would suggest that the RR also be presented and reviewed at the October SPC to determine if there needed to be additional discussion and guidance.”
Denise Buffington, KCP&L’s director of energy policy and corporate counsel, said her preference was to send RR 172 back to the RTWG and then the MOPC and Board of Directors.
She is also open to other ideas.
“If someone can bring me a better solution that solves my equity issue and cost-shifting issue, I’m all ears,” she said. “I’m willing to negotiate or take someone else’s ideas. I don’t want to spend another six, eight or 10 months in a working group or task force to try and solve a problem that’s a real problem today.”
Buffington said KCP&L would probably file a complaint at FERC and “get a change made there” should the SPC not resolve RR 172 “to our satisfaction and in a timely manner.”
“I agree this is an issue that needs to be resolved. I agree with the urgency,” Brown responded, suggesting the process would drag out further if the RTWG continued to handle KCP&L’s proposal. “You could file a [Section] 206 [complaint] with FERC today. My response to FERC would be, ‘Please give us the opportunity to resolve this through the stakeholder process. Every time we’ve done that in the past, [our request has] been granted.”
“We are open to having it resolved [in the SPC], but we are not interested in it being paralyzed by the SPC,” Buffington said Monday.
Buffington agreed to keep KCP&L’s proposal within the SPC, but she said she wants a discussion and vote if no progress has been made before the April MOPC meeting. “There is a process in place, and I want it followed,” she said.
The SPC agreed to schedule another meeting within a matter of weeks to continue its discussion of RR 172 and review specific policy language from staff, but no date has yet been set.
The committee in October agreed to defer action on RR 172 pending alternative proposals from SPP. Staff returned last week with a straw proposal for zonal placement criteria for existing facilities. That plan limited the scope to integrating existing facilities with the zonal annual transmission revenue requirement (ATRR) costs under Schedule 9 of the RTO’s Tariff, or a current transmission owner’s purchase of existing facilities that would be included in its zonal ATRR.
The SPC agreed unanimously to codify SPP’s criteria for determining whether to put transmission facilities and the ATRR into an existing pricing zone or create a new one, but there was some disagreement on whether or not staff’s current criteria will be sufficient.
Those criteria include:
Whether the new TO’s ATRR is less than that of an existing zone with the smallest ATRR;
The extent to which a new TO’s facilities are embedded within a pre-existing zone;
The extent to which a new TO’s facilities are integrated with (including number of interconnections) an existing TO’s facilities; and
The extent to which the new TO’s facilities substantively increase the SPP footprint.
KCP&L said its proposal is designed to strike a balance between attracting new transmission-owning customers to SPP and eliminating the unnecessary and unfair potential for new members to shift costs to existing members by codifying SPP’s zonal selection criteria in the Tariff. The revision is intended to establish a bright line between the costs of legacy transmission and new facilities planned by SPP.
Buffington said its revisions to RR 172 provides a bidirectional approach to protect both new TOs and new and existing transmission customers from paying for facilities that were not jointly planned. Following the new TO’s integration into the RTO, all SPP-studied and approved projects would be allocated in accordance with its Tariff, she said.
KCP&L has been driven by SPP’s decision to put the City of Independence, Mo., into the utility’s transmission pricing zone, a move Buffington last year said “blindsided” the utility and led to a multimillion cost shift to its customers. The KCP&L zone has some of the lowest transmission costs among SPP’s 19 zones, thanks to the Kansas City area’s load.
“The crux of the problem for KCP&L is there’s a price impact to us when someone comes into our zone,” Buffington said. “We tried to put a bright line out there so people know what to expect going forward and so people can know what to expect when they become a member of SPP.”
“I don’t want to build walls to prohibit people from coming in,” American Electric Power’s Richard Ross said, “but I don’t want to do things that cause detriment to our existing customers.”
Several stakeholders have spoken out against the proposal’s hold-harmless provisions, in which new TOs would have their facility costs allocated to their load and current zonal TOs and customers would have the costs of their facilities allocated to their load. They assert this gets away from SPP’s concept of transmission providing value to the SPP system, not those who built it.
Brett Hooton, vice president of business development for South Central MCN, called RR 172’s hold-harmless provisions “anti-competitive, unduly discriminatory and a logistical nightmare.” He also said the proposal’s “unintended consequences” have yet to be vetted and discussed.
“This impacts all segments of SPP membership,” Hooton said. “The focus should be on areas with broad stakeholder agreement [zonal placement criteria and informational requirements], rather than forging ahead with a controversial hold-harmless proposal that is also contrary to the principle that networked transmission can provide value to the Bulk Electric System.”
SPC Agrees to Reconstitute Congestion Hedging Group
The SPC also agreed to reconstitute the Congestion Hedging Task Force to address the large amounts of wind energy and other renewables that could come online in the future. SPP has 21,535 MW in its interconnection queue, on top of 15,728 of installed wind energy.
The CHTF would report to the MOPC. The committee’s chair, Paul Malone of the Nebraska Public Power District, said he would work with staff to move the task force forward.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
