WILMINGTON, Del. — John Horstmann of Dayton Power and Light expressed concern that PJM’s proposed regulation changes will have a “huge impact” on existing Reg D providers and noted that complaints have been filed at FERC opposing the changes PJM implemented in January. (See “New Regulation Rules Improving ACE Control,” PJM Operating Committee Briefs.)
Based on the potential issues, Horstmann made a motion at Thursday’s Markets and Reliability Committee meeting to defer a vote on the package until June, which would allow for the comment period at FERC to close. Members approved the delay in a 3.76 sector-weighted vote.
The package, jointly developed by PJM and the Independent Market Monitor, would replace the benefit factor with the “regulation rate of technical substitution,” and the effective megawatt calculation would be the area under its curve. The mileage ratio from the regulation performance credit would be replaced with the “marginal rate of technical substitution” (MRTS), which will be added to the regulation capacity credit. Bowring said later that PJM meeting rules prevented him from responding to comments from Horstmann that he believed to be inaccurate.
The 24-month transition period will have a minimum MRTS of .65 for the first year, followed by a floor of .5 for the last year. The minimum allowable participation threshold will be raised from 40% to 50%.
“The transition offer by PJM, while a nice gesture, [is] not really compensatory for existing Reg D providers,” Horstmann said.
CCPPSTF Charter Approved
The MRC approved the charter for the Capacity Construct/Public Policy Senior Task Force, declining to adopt language changes proposed by Market Monitor Joe Bowring.
Bowring suggested that one of the group objectives in the charter, which calls for “modifications to [the Reliability Pricing Model] that could accommodate/address both capacity construct objective and state actions,” wasn’t consistent with the charter’s mission to “ensure potential state public policy initiatives and Reliability Pricing Model objectives are not at odds.”
Bowring found no members willing to take up his suggested edits, and the charter passed with one objection and two abstentions.
PJM’s David Schweizer presented a first read of the RTO’s plan to address FERC’s recent Notice of Proposed Rulemaking on frequency response. PJM’s proposal has suggested that it might consider compensating units for maintaining primary frequency response, even though the NOPR is silent on the topic. (See “PJM Wants to Study Frequency Response,” PJM Operating Committee Briefs.)
John Farber of the Delaware Public Service Commission staff took issue. “If we’re purchasing this premium [Capacity Performance product], it should include this primary frequency response,” he said.
He asked that the problem statement and accompanying issue charge include language that the compensation would be considered “if appropriate or necessary.” Schweizer said the documents were developed to allow dialogue on the topic while designing proposed solutions.
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He said he will be seeking the Operating Committee’s approval on Wednesday and asked that any proposed changes be submitted as soon as possible.
Manual Changes OK’d
Stakeholders endorsed by acclamation two manual revisions:
Manual 14B: PJM Region Transmission Planning Process. The changes correcting wording in the baseline thermal analysis section to match analytical procedures and replace all occurrences of “special protection system” with “remedial action scheme” per a change to the NERC glossary of terms.
Manual 18: PJM Capacity Market. The revisions conform to FERC’s March 21 order tentatively approving PJM’s “enhanced aggregation” plan to allow seasonal capacity participation as CP resources. Stakeholders deferred sunsetting the Seasonal Capacity Resources Senior Task Force until the May meeting so they can be informed of any action on the seasonal capacity filing at FERC. (See PJM Outlines Aggregation Rules for Upcoming Capacity Auction.)
Members Committee
Members Endorse Pricing Revisions
The Members Committee endorsed revisions to PJM’s Tariff and Operating Agreement to address shortage pricing through the operating demand curve. (See “Shortage Rule Takes Effect amid FERC Silence,” PJM Market Implementation Committee Briefs.)
Both changes had received substantial discussion in previous meetings, so members had little to say about them Thursday. Bowring reiterated concerns he has mentioned previously about PJM’s approach to handling fuel-cost policies.
The Energy Storage Association recently filed a complaint with FERC seeking a review of PJM’s prior unilateral changes to its market for frequency regulation. Electricity markets are founded on the principle that practices affecting rates won’t be changed arbitrarily, which ensures fair treatment of companies that invest in and operate electric resources. This is particularly important to ensure new resources like advanced energy storage enter markets and increase competition. For this reason, the decisions impacting tariffs that PJM has made must be submitted for review by FERC.
PJM was the first market to use the near instantaneous response time and precisely controlled input and output of storage systems as a cost-effective tool to ensure short-term grid stability. PJM’s fast frequency regulation service (RegD) was designed for dynamic electric supply assets that are high-power, duration-limited and fast-responding, matching the moment-to-moment deviations of supply and demand to maintain the frequency of the electric grid. In contrast, PJM’s conventional frequency regulation service (RegA) continued to enable the participation of traditional electric supply resources, which have slower response times and ramp rates but can sustain service indefinitely.
As a result, more than 265 MW of advanced energy storage are currently deployed in PJM — nearly all of it competing in the regulation market. These energy storage systems have lowered costs and generated value for the millions of customers in PJM.
Regulation Market Certainty & Unilateral Changes
Over the course of 2015, larger system conditions were leading PJM to call on its energy storage resources to sustain longer-duration service regularly. Because RegD service was designed to be short-duration, PJM decided to make changes to the frequency regulation market while convening a stakeholder consultation process. In late 2015, PJM artificially capped how much RegD service can be provided, and in early 2017, PJM changed the parameters of RegD service, including ending its use for only short-duration needs.
The changes to the parameters of RegD service undermine its original purpose — to provide efficient response to short-term deviations of system frequency (typically measured in minutes). Keeping the grid in balance over longer periods — up to an hour or more — is the role of energy markets or, in emergencies, reserves. In effect, PJM has decided to rely on regulation resources to correct prolonged system imbalances rather than address their root causes. Additionally, the parameters of RegD service also determine how market participants are compensated, and these changes constitute a substantive modification to the actual rates.
Typically, when changes of a magnitude that impact market structures and compensation are being considered, the market operator submits these changes to FERC for review and approval. This review is an important step and is a legal requirement because it ensures that our nation’s wholesale electricity markets remain fair and accessible and that capable assets of all types are rewarded for their performance.
That is why ESA has submitted a Section 206 filing with FERC: to review the decisions made by PJM and enable the changes to RegD service to be considered as a formal tariff change. Moreover, without such review, nothing stops PJM from making changes of similar magnitude again in the future — creating significant uncertainty for energy storage market participants.
It is important to note that PJM staff were presented with proposals to address the broader system challenges that prompted the review of the frequency regulation market design — including proposals from ESA and its members — designed to meet PJM’s needs as the grid operator while enabling energy storage owners to adapt to new conditions.
After much discussion, these proposals from many different stakeholder groups were not put into place, and instead PJM decided to implement the rule changes opposed in our complaint — changes that have obstructed advanced energy storage system owners, operators and developers, and substantively impacted the market tariffs and resulting compensation.
The Path Forward
We very much agree with PJM staff and other stakeholders that the rules and parameters applicable to RegD service can continue to be improved and can also be adapted (or be a model for future markets) to address broader system challenges at PJM like overgeneration and the need for more fast-responding, medium-duration reserves on the system. To date, PJM has done an effective job of addressing these challenges and has not seen any significant change to relevant system reliability metrics (e.g., NERC Control Performance Standard scores) since RegD service was implemented.
However, the root causes of system conditions that led PJM to seek longer-duration response from regulation resources in the first place have not been explored. In effect, PJM has sought to solve a larger system reliability issue through the regulation market. It is important that PJM staff investigate what appears to be a consistent oversupply issue that is leading to the prolonged system imbalances — and specifically calling on RegD resources to be continuously charging over extended periods of time.
Further review by FERC will ensure that the broader influences of these changes on market tariffs and performance are considered holistically, and that PJM will continue to be a leading innovator in creating the model for competitive energy marketplaces. We look forward to working with PJM staff, regulators and a broader group of grid stakeholders on developing a better strategy for ancillary services and applications for energy storage, and by undergoing a more formal process, we can ensure that PJM customers don’t miss out on the ultimate objective — affordable and reliable energy, from increasingly sustainable sources.
Matt Roberts is executive director of the Energy Storage Association, the voice of the energy storage industry, representing manufacturers, utilities, grid operators, developers and technology companies, and working to promote the adoption of competitive and reliable energy storage systems. More info is available at www.energystorage.org.
WILMINGTON, Del. — Solutions for reducing uplift charges have been more than four years in the making, so PJM members at last week’s Markets and Reliability Committee meeting were largely unconvinced when financial traders argued that voting on the solution’s third phase was being rushed.
Financial stakeholders campaigned unsuccessfully for more than an hour to change the proposal.
Stakeholders then approved a package designed by PJM “to strike a balance between retaining the theoretical benefits of virtual trading while eliminating opportunities for virtual transactions to profit from the market without providing those benefits.” It limits incremental offers and decremental bids to “locations where the settlement of physical energy occurs,” where they compete directly with physical assets or trading hubs, where traders can take forward positions.
Up-to-congestion transactions would be limited to hubs, zones and interfaces — locations that are large aggregates. PJM said the change will address concerns that some UTC trades “do not benefit the market at a level commensurate with the profitability of the transactions.” (See “Members Approve Uplift Proposals,” PJM Markets and Reliability and Members Committees Briefs.)
Financial stakeholders mounted several efforts to influence the vote. They first called for deferring it until FERC has acted on Phase 2, which failed in a sector-weighted vote with 1.04 in favor. The MRC requires a two-thirds sector-weighted vote (3.33 out of 5). Only the Other Supplier sector — which includes financial traders — was in favor of the delay, with the other sectors almost unanimously opposed.
Attorney Ruta Skucas, who represents the Financial Marketers Coalition, called for the deferral, which was seconded by Joe Wadsworth of Vitol. Skucas said the proposal was changed significantly shortly before it went to vote and never received vetting at the Energy Market Uplift Senior Task Force, where the issue had been hashed out for years. The changes eliminated all but 41 nodes for UTCs, she said.
Wadsworth described the proposal as taking “a sledgehammer to the market,” saying the root issue was modeling errors that could be addressed by a more “surgical” approach, such as eliminating trading at locations where the day-ahead and real-time models can’t be aligned.
“When we start removing what traders can do in managing their portfolios on a day-ahead and real-time basis, we’re going to take away the uniqueness traders bring that leads to competition in the markets,” he said.
Bruce Bleiweis of DC Energy also supported a delay, saying he’s been involved with PJM for 21 years, and “this is the first time we’ve come to a rush to judgment.”
“My clients would have a different opinion of that,” said attorney Susan Bruce, who represents the PJM Industrial Customer Coalition. “This is a solution that’s a long time coming.”
Direct Energy’s Jeff Whitehead took exception to the accusations of rushed voting.
“I believe this issue has seen its day in court. There are buses that are available to virtual traders on the system today … where there are modeling issues between the day-ahead and real-time market. And because those modeling issues ostensibly can’t be corrected by PJM, arbitrage opportunities exist that simply cannot be converged between the two markets,” he said. “If traders are simply trading with themselves at points that cannot converge, I don’t call that a market.”
“The purpose of the markets is to provide real power to real customers at the lowest possible cost,” said Joe Bowring, PJM’s Independent Market Monitor. “To the extent that virtual transactions are not contributing to that, it’s not appropriate to allow them to continue.”
PJM’s Adam Keech agreed, saying that rules for virtual trading are designed to have the “highest probability of adding the most to the system.”
PJM staff said it’s not clear when the proposal will be filed with FERC because contested filings require a quorum of commissioners to resolve, and the filing seemed likely to attract protest. Noha Sidhom, a financial trader who doesn’t participate in the virtual market, then proposed bifurcating the package into separate filings so that the noncontroversial portions — the limits on INCs and DECs — could be approved by FERC staff and implemented, while the UTC changes — which likely will receive protest — can wait until the commission has a quorum.
Stakeholders debated for some time whether that proposal should be considered prior to voting on the original package, and eventually determined that it should not. The original proposal passed with a 4.07 sector-weighted vote, with all but the Other Suppliers in support.
ERCOT’s Technical Advisory Committee last week unanimously approved changes to the ISO’s congestion revenue rights (CRR) activity calendar and its Nodal Operating Guide.
Both votes were conducted by email following an April 24 information session. The TAC canceled its regularly scheduled meeting due to a lack of voting items.
The first change updates ERCOT’s CRR calendar following the Board of Directors’ approval earlier in April of a nodal protocol revision request (NPRR). NPRR808 extended the CRR auction process into the third year forward — with one monthly and one long-term auction each calendar month — and revised the percentages sold in its long-term sequence. It also aligned modifying load zones to the timetable.
Power Traders | SearchforEnergy.com
“This should be a huge benefit to our market, and I’m excited to see it implemented,” Morgan Stanley’s Clayton Greer emailed his fellow TAC members after the vote.
ERCOT’s Carrie Bivens, manager of forward markets, said during the information session that the TAC’s approval was required by May 1 in order to be ready for the long-term auction that begins this fall. She said staff has not yet completed testing to ensure the credit monitoring and management system can handle the additional inventory.
“We believe we can, but the risk remains out there,” Bivens said.
The change to the Nodal Operating Guide (NOGRR167) revises it to be consistent with NPRR776, which was also approved by the board in April and aligns the protocol language with currently used verbal communication practices between transmission service providers, qualified scheduling entities and generation resources. The TAC had tabled NOGRR167 during its March meeting.
TULSA, Okla. — The issue of cost shifts within transmission pricing zones may soon surpass transmission upgrade credits as one of the most vexing problems facing SPP stakeholders.
Strategic Planning Committee Chair Mike Wise said last week that his committee has been unable to reach consensus on a more equitable means of determining cost shifts when new members join existing transmission pricing zones despite talks that began in January.
Kansas City Power and Light called for revising SPP’s policy after the RTO put the City of Independence, Mo., into the utility’s transmission pricing zone, increasing costs for KCP&L customers. (See Strategic Planning Committee to Continue Work on Tx Cost Shifts.)
The SPC held two special meetings during April — a month in which it doesn’t normally meet — trying to reach consensus on a staff proposal for a “symmetrical” cost/benefit analysis and a phase-in process for regulatory assets that evaluates the time value of money.
“During discussion, it became clear we still didn’t have agreement on staff’s proposal,” Wise told the Board of Directors and Members Committee last Tuesday. “It’s concerning to me that in the stakeholder process, we couldn’t come to a conclusion on this.”
The SPC last met April 20 in Dallas, where it voted on a motion to adopt part of staff’s proposal, rejecting calls to end the discussion entirely. The motion included a reference to “the understanding that the SPC does not endorse the outcome of any staff zonal placement decisions.”
“Basically, [we] just approved a staff process for communication of potential zonal placements,” KCP&L’s Denise Buffington said.
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She said in January her company would likely file a complaint with FERC if the SPC doesn’t resolve the issue “to our satisfaction and in a timely manner.” Stakeholders did agree to the first steps in the process, which begin with the applicant transmission owner (ATO) notifying SPP of its intention to join the RTO. Staff would then request data from the ATO, study the zonal placement and cost analysis, and facilitate discussions between the ATO and the transmission zone’s incumbents.
Staff’s straw proposal suggested that the ATO be given an opportunity to negotiate cost shifts with the other transmission owners and network customers in the affected zone, with any resulting agreements filed with FERC.
If no agreement is reached, SPP proposed filing a cost-shift mitigation plan if the shift increased network customers’ baseline costs under Schedule 9 of the Tariff by more than 2.5%.
But staff now say there is little consensus for having a cost-shift threshold. Several stakeholders were adamant that they did not want SPP deciding what costs would be placed upon their customers.
“The problem is not with the mitigation, but the zonal placement criteria,” Buffington said. “The criteria lead to the zonal placement, and it’s the zonal placement that leads to cost shifts. The criteria that [dictate] the placement [are] the problem.”
Staff has suggested using the following criteria in determining whether to place the facilities in a new zone:
Whether the transmission facilities’ annual transmission revenue requirement (ATRR) is less than the minimum zonal ATRR benchmark;
The extent to which the transferring facilities substantively increase the SPP regional footprint; and
The extent to which the transferring facilities’ load received network service or long-term firm point-to-point service within existing zones prior to the transfer.
If the facilities are not placed in a new zone, staff would apply the following criteria in determining the existing zone in which to place the facilities:
The extent to which the facilities are embedded within an existing zone;
The extent to which the facilities are integrated with an existing zone; and
The extent to which the facilities load received network service or long-term firm P2P service within each existing zone prior to the transfer.
Buffington has been leading the work on a revision request (RR172) that she said would establish a bright line between the costs of legacy transmission and new facilities planned by SPP to protect customers from paying for facilities that were not jointly planned. That work has been on hold, pending the SPC discussions.
Wise agreed the SPC would return with another update for the July meeting in Denver.
“This cannot die where it is,” Board Chair Jim Eckelberger said.
TULSA, Okla. — SPP Strategic Planning Committee Chairman Mike Wise said the committee’s Export Pricing Task Force agrees with staff’s determination that even building additional transmission will not guarantee the RTO can deliver its ample wind power outside its footprint.
In the group’s most recent meeting in March, SPP staff said a market exists for renewable resources, but “rate stress” from building additional transmission and uncertainty that the energy would be deliverable led it to its conclusion. (See “Renewable Exports Unlikely, Task Force Concludes; Readies Final Report,” SPP Briefs.)
“We’re choking on wind,” Wise told the Board of Directors meeting last week. “We run up against the export threshold [about 2,500 MW] on a continued basis.”
Westar Energy’s Kelly Harrison wondered aloud whether transmission is so expensive that it makes wind energy uneconomic to export.
“We’re looking for a business proposition to mitigate that,” Wise responded.
Harrison then asked whether SPP should leave it up to Clean Line Energy to move the wind energy. Clean Line’s Plains & Eastern Clean Line would deliver wind-generated power from the Oklahoma Panhandle through Arkansas to Memphis, though it has met opposition. (See Arkansas Landowners Seek to Stop Plains & Eastern Clean Line Project.)
“That’s why we’re still meeting, until we can get a business proposition that makes sense,” Wise said.
The task force will meet again in June, after several members pushed back against staff’s recommendation to end the group’s work.
Board Asks MOPC to Revisit Mitigated Offers
The board directed the Markets and Operations Policy Committee to revisit a revision request it had passed despite stakeholder concerns it needed more work (MRR214). (See “MWG Closing out MMU’s Recommendations,” SPP Markets and Operations Policy Committee Briefs.)
Board Chair Jim Eckelberger asked Nebraska Public Power District’s Paul Malone, MOPC chair, to expand the discussion to look at the use of rapid-starting units “almost like ping-pong balls” and coal units.
“The way those units are being used is not being reflected in the market,” Eckelberger said.
The change would allow market participants to use a 10% adder for mitigated offers, giving them more margin for error when submitting a mitigated offer curve. The Market Working Group also said the change would improve price formation in SPP’s markets by removing a penalizing feature that may be suppressing offered prices today.
However, MWG Chair Richard Ross of American Electric Power said additional information since the MOPC meeting — where the request received seven “no” votes — had caused him to change his mind. Working with staff, Ross said, he realized the change would modify a mitigated offer as it was cleared, so that when units were dispatched above their minimum bids, it would affect LMPs.
“We didn’t appreciate [that] those units on the margin, and sometimes not on the margin, needed cost recovery under the [make-whole payments],” Ross said. “Technically, [MRR214] does what it says, but it’s impacting the LMPs. It wasn’t until we looked into things and said, ‘Wait a minute. You may get everything you’ve set out to get in the request, but you don’t settle the make-whole payments.’”
Ross said that while the change wouldn’t affect the “lion’s share” of the market, he said the MWG didn’t give the revision request “the full scrutiny we probably should have.”
“These RRs are developed by the members and looked at by staff,” said Dogwood Energy’s Rob Janssen, a former MOPC chair. “You expect to catch everything, but sometimes you don’t.”
The board did approve MRR125, which removes a day-ahead must-offer requirement the Market Monitoring Unit deemed unnecessary in its 2014 State of the Market report. The measure received opposition from three members; two more abstained.
“The day-ahead must-offer has limited value in this market,” MMU Director Alan McQueen said. “This market is very robust in the day-ahead. Our analysis shows this [offer] doesn’t really matter. Whether subjected to day-ahead limited must-offers or not, we see the same patterns.”
Wise said stakeholders should work to clarify the market’s use of physical withholding but received little support.
MMU Nears Compliance with FERC Audit
Oversight Chair Joshua W. Martin III told the board and members that SPP is on pace to complete the changes recommended by FERC’s audit of the MMU. The audit, which took 17 months to complete, said the unit “should strengthen its independence and enhance its separation from” the RTO. (See FERC Calls for Changes to Protect SPP Market Monitoring Unit Independence.)
Martin said the project is almost completed and that testing had just begun of the card-access system that will separate MMU staff from RTO staff. MMU staff had worked alongside other RTO staffers, most in open cubicles.
Eric Callisto, an attorney with Michael Best & Friedrich who has served as the MMU regulatory counsel for two years, said much of the work was “already being implemented while the audit was ongoing.” He said two more compliance reports will be filed by the end of July to wrap up FERC’s recommendations.
Callisto pointed to the Oversight Committee’s 2015 position statement on the MMU’s independence, which opened by requiring the unit to “function independently of the RTO to avoid actual or apparent conflicts in its oversight role.”
“One of the key items was the MMU had the resources to make comments to FERC at any point, even if it disagreed with the position that came through the stakeholder process,” Callisto said.
He said the MMU now holds executive sessions with the committee and without SPP staff present, but still holds other executive sessions with SPP executives when relevant to the OC.
“It’s that dialogue with the Oversight Committee that gives the MMU its independence,” Callisto said. “The keystone of the relationship is having the ability to go into that confidential forum, talk about ideas and get confirmation of ideas.
“The last two years, we have seen the MMU file at FERC more often than it has in the past. I believe the MMU is more independent now than it was a year and a half ago,” he said.
Among other changes, Callisto said, is the Oversight Committee’s use of a non-SPP staff secretary when meeting with the MMU, the unit’s logging of non-routine interactions with SPP executives and stakeholders, the MMU’s use of outside counsel and a separate IT budget, and its “awareness that its role is advisory.”
SPP Releases 2016 Annual Report: ‘Forward’
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SPP celebrates a milestone year with its 2016 annual report, which it distributed to the Board and Members Committee and posted online last week. The RTO once again used a single word as the report’s title: “Forward.”
“That’s a good word to reflect on all that occurred in 2016,” SPP CEO Nick Brown told directors and members.
The report harkens back to the organization’s 75th anniversary and celebrates the many wind generation records SPP set last year, reaching the Integrated Marketplace’s $1 billion mark for total savings and lowering its planning reserve margin from 13.6% to 12%.
“Given such a banner year, we could all be forgiven for wanting to rest on our laurels or to indulge a bit longer in nostalgia,” Brown and Eckelberger write. “As SPP crosses the threshold into the next quarter century of our existence, then, we look not back but forward. We believe … the facts and figures presented here do more than chronicle a year of our company’s ongoing story: They point ahead to the next chapter.”
In a special members meeting, the board and members approved the nomination of three new representatives to the Members Committee and bylaw changes related to the Regional Entity.
Brent Baker (Empire District Electric), Kevin Noblet (Kansas City Power & Light) and Aundrea Williams (NextEra Energy Resources) will join the committee. They replace Kelly Walters (Empire) and Scott Heidtbrink (KCP&L), who retired, and Mark Tourangeau, who recently left NextEra.
Stakeholders also approved changing RE General Manager Ron Ciesiel’s title to president, and adding a vice chair position to the RE’s trustees. According to the Corporate Governance Committee’s recommendation supporting the changes, the RE said Ciesiel’s title change was “more appropriate and indicative of the position,” and that the vice chair would ensure a “more consistent transition” should the chair be unable to complete his or her duties.
Board, Members Honor Skilton’s Service
SPP’s directors, the Members Committee, staff and other stakeholders honored long-time Director Harry Skilton with a standing ovation before adjourning the board meeting, his last as vice chair. Skilton, who remains on the board, stepped down after 13 years as the board’s vice chair, a position in which he has been Eckelberger’s steady right-hand man.
“For the last 13 years, Harry has been my sidekick,” Eckelberger said, turning to Skilton. “I’d like to acknowledge my personal appreciation for what you have done.”
Eckelberger and Skilton both joined the SPP board in 2000. The board has added three new members in the last year and is working to bring in the new blood.
Larry Altenbaumer, who joined the board in 2005, has replaced Skilton as vice chair and chair of the Finance Committee.
The board approved revisions to the Seams Projects Policy Paper and the 2017 ITP Near-Term assessment’s portfolios. Both had been endorsed by the MOPC two weeks earlier.
The revised seams policy expands the definition of seams projects to include 100-kV and above solutions involving a tie line between SPP and its neighbor or transmission projects that do not cross regional boundaries. It also documents cost allocation policy decisions previously approved by the Regional State Committee and board in 2014.
ITC-Great Plains opposed the motion, saying the revisions did not clarify “the interaction between SPP’s Order 1000 processes and the proposed Seams Transmission Project process.” NextEra Energy Resources and Dogwood Energy abstained.
The board unanimously approved the 2017 ITPNT portfolio, which also passed the MOPC and the Transmission Working Group without opposition. The final portfolio included 15 new reliability projects and one modified project that solve 108 thermal and voltage needs, at a total cost of $60.3 million.
The board also unanimously approved a consent agenda that included a number of proposals previously approved by the MOPC:
Bylaw changes for the nomination and selection of organizational group chairs and vice chairs, and their staggered term lengths. (See “Org Chairs also may See Changes,” SPP Markets and Operations Policy Committee Briefs.)
Staff’s expedited re-evaluation of the need date for Basin Electric’s Roundup-Kummer Ridge 345-kV project, to reflect lower load growth forecasts. (See “MOPC Endorses Re-evaluation of Basin Electric Project,” SPP Markets and Operations Policy Committee Briefs.)
A 50-MVAR reactor at the City Utilities of Springfield, Mo.’s 345-kV Brookline substation. The project was identified last year in a joint study with Associated Electric Cooperative Inc. (AECI).
Regional funding for a new 345/161-kV transformer at AECI’s Morgan substation and an uprate of a connecting 161-kV line at an estimated $9.2 million. The project is contingent on reaching an agreement for compensating AECI, which would not see reliability benefits from the project even though it sits within its service area.
The consent agenda also included 15 revision requests.
CPWG-RR218: Adopts a $50 million unsecured credit allowance, a raise from $25 million, to reduce the costs of capital for utilities. SPP is the last RTO to adopt a $50 million limit.
MWG-RR200: Removes bilateral settlement schedules at hubs and generation settlement locations from the over-collected losses (OCL) distribution calculation. Only schedules at a withdrawal point would be included in the OCL calculation.
MWG-RR203: Adds a “last-chance” second set of auction revenue rights nominations in the monthly ARR process, where any source-sink path can be nominated.
MWG-RR205: Allows the implementation of jointly owned units (JOU) registered under the combined-resource option to include the minimum regulation-capacity operating limit in its offers, and adds resource offer parameters that can be changed daily for a JOU’s minimum physical capacity and physical-regulation capacity operating limits.
MWG-RR216: Reinstates Tariff language omitted from RR173 related to eligibility of multiconfiguration resources for regulation-up or regulation-down service.
MWG-RR217: Removes Tariff language related to violation relaxation limits to make the section consistent with a compliance filing in response to FERC’s Order 825 on shortage pricing.
MWG-RR219: Ensures language in SPP’s Tariff meets FERC requirements for enhanced combined cycle units.
ORWG-RR213: Creates a new appendix to the operating criteria that defines how the SPP reliability coordinator will operate voltage stability limited system constraints, as recommended by the Wind Integration Study.
RTWG-RR202: Responds to FERC guidance on SPP’s disparate treatment of point-to-point and network integration transmission service (NITS) during redispatch. NITS would be eligible for ARRs during limited times of the year and only for the service not subject to redispatch, but would not be eligible for long-term congestion rights. (See SPP Hopes Congestion Rights Rule Change Wins FERC OK.)
RTWG-RR208: Implements the Transmission Planning Improvement Task Force’s white paper for new regional planning processes by replacing current planning schedules with an annual transmission expansion plan; creating a standardized scope; establishing a common planning model for use across the various planning processes; and creating a staff/stakeholder accountability program. (See “SPC, MOPC Approve Improvements to SPP’s Tx Planning Process,” SPP Strategic Planning Committee Briefs.)
RTWG-RR211: Establishes a $3 million minimum cost threshold for competitive projects.
TRR223: Revises the Tariff to extend the timeline for conducting regional cost allocation reviews from three years to six.
TWG-RR224: Aligns the existing criteria with NERC’s new definition of “special protection schemes” as “remedial action schemes.” Also cleans up planning criteria language coinciding with changes made to the operating-horizon system operating limits methodology.
Executives from PJM, NYISO and ISO-NE will gather with stakeholders, state officials and others at FERC this week to seek ways to incorporate state policies on greenhouse gases into wholesale markets.
FERC scheduled the two-day technical conference out of concern that the RTO/ISO energy and capacity markets could lose relevance — or have their pricing signals undermined — because of state plans to procure out-of-market renewable power and prop up nuclear generators (AD17-11).
The conference will build on the grid operators’ initiatives, including white papers and the New England Power Pool’s Integrating Markets and Public Policy (IMAPP). It also comes as FERC has pending before it challenges to zero-emission credits for nuclear generators in NYISO and PJM.
FERC staff indicated the high stakes posed by increasing tensions between state policies and RTO/ISO resource adequacy efforts, asking witnesses to consider whether there will be “a diminished role for the RTO/ISO.”
The first day of the conference devotes two panel sessions to each of the three grid operators, with one session for state officials to offer their perspectives and one for stakeholders and RTO/ISO officials. The second day will include one panel dominated by state regulators and generating company executives; a second featuring economists and consultants; and a final one giving RTO/ISO officials an opportunity to respond to what they’ve heard.
Below, based on interviews and a review of filed testimony by the witnesses, is a preview of the issues to be discussed.
Incorporating Carbon Costs
Changing the energy resource mix is complex and often controversial, said the Brattle Group’s Judy Chang, an energy economist with a background in electrical engineering, whose clients include NYISO. “Anytime you change the rules, someone is not going to be happy, because rule changes affect revenue,” she said in an interview. An energy economist with a background in electrical engineering, Chang advises clients, including NYISO, on transmission, resource and strategic planning.
ISO-NE Chief Economist Matthew White said New England states are more focused than most others on subsidizing new renewables to meet environmental goals.
“To date, stakeholders and ISO-NE have only identified one solution that would help the states ‘achieve’ their goals while simultaneously preserving the benefits of competitive markets — a carbon cap-and-trade system,” White said in his prepared comments.
Carbon pricing could efficiently price the environmental attributes sought by the states, providing a market framework to select resources based on the least cost. White said that despite the potential advantages of carbon pricing, “there are significant jurisdictional and political issues regarding the implementation of such a carbon pricing mechanism.”
NYISO CEO Brad Jones focused on the ISO’s search for a method “to incorporate the social cost of carbon into generation offers and reflect that cost in energy clearing prices.”
“A generating unit that may appear uneconomic based on its electricity market revenues alone may nevertheless be viable if it could capture the economic value of its environmental attributes,” Jones said. “The problem we face is that current wholesale market designs function well to send economically efficient market signals needed to maintain reliability, but they do not value externalities such as environmental attributes [that] are at the heart of certain state policies.”
Energy and Capacity Markets Implicated
RTO Insider asked Chang whether FERC and the RTOs have the same agenda for the technical conference. “That’s a really good question,” she responded. “The commission wants to ensure that the market functions properly. If FERC is smart, and they are, they’ll recognize that these things cannot stay static. There’s a lot of change going on these days. Policymakers, to succeed, need the market to shift with policy, to improve and adapt.”
Susanne DesRoches, deputy director of infrastructure policy for New York City, said that energy market changes provide only part of the solution. “Changes also are needed to the capacity markets to ensure that developers of renewable resources are able to recover their non-operating costs. At present, the capital costs of many renewable technologies are greater than the cost of a gas-fired plant, but the installed capacity demand curves are not designed to take into account such costs.”
Indian Point Nuclear Plant
Improvements need to take place because the wholesale electricity markets are only about a decade old, at a time when coal-fired generation dominated in many regions and renewables had little market share. “The designers had no conception of what the world would look like 15 or 20 years later,” Chang said. (See EBA Panel: States Acting on CO2 Because Markets Can’t.)
NEPOOL Chairman Thomas W. Kaslow referred the commission in his prepared comments to a new paper issued by ISO-NE, “Competitive Auctions with Subsidized Policy Resources,” which proposes coordinating the entry of subsidized new resources with the exit of unsubsidized existing capacity resources. Under the proposal, ISO-NE would use a two-stage, two-settlement process in its Forward Capacity Auctions to provide “financial incentives for existing, high-cost capacity resources to transfer their capacity obligations to subsidized new resources and to permanently exit the capacity market.”
PJM Looks to Value Resiliency
Reducing carbon emissions is the major driver for New York and the New England states, all members of the Regional Greenhouse Gas Initiative.
That’s not the case in PJM. Although most of the RTO’s 13 states have renewable portfolio standards, only two — Maryland and Delaware — are in RGGI.
In Ohio, state initiatives have been focused not on reducing emissions but on preserving coal-fired generation.
In March, PJM released a study, “PJM’s Evolving Resource Mix and System Reliability,” in response to stakeholder concerns that the system is losing too many traditional baseload resources as coal plants retire and nuclear assets struggle to remain profitable. The study concluded the RTO can maintain reliability with a generation fleet almost entirely composed of natural gas units, but that a capacity mix of more than 20% of solar would unacceptably increase the risk of loss-of-load events. (See PJM: Increased Gas Won’t Hurt Reliability, Too Much Solar Will.)
Seeking 90% from the Markets
Chang said the states aren’t seeking a confrontation with the RTOs.
“It’s not one or the other, not who has the upper hand,” she said. “It would not be in the state’s interest to always work outside a competitive, centralized marketplace. And it’s not in the grid’s interest to maintain the status quo. We want to get to the point where state policymakers can rely on the market to accomplish 90% of what they want. Coordination is key; otherwise, ratepayers could end up paying for something twice. You let some resources retire just because they’re not efficient, and at the same time you set price incentives to encourage development of clean energy. They have to go hand in hand.”
Jeffrey Bentz, director of analysis for the New England States Committee on Electricity, in his prepared remarks referred the commission to a recent NESCOE study on IMAPP. Not only does NESCOE not support an additional carbon-pricing mechanism to be run by ISO-NE and regulated by FERC, but the member states are concerned about the risks of a FERC-jurisdictional tariff reflecting carbon pricing.
Specifically, New England states are concerned that such a tariff poses “risks to states’ ability to make their own determination regarding the implementation of their carbon-reduction laws,” Bentz said. “For example, as illustrated in recent years, a few market participants with an appetite and budget to litigate matters could seek to disrupt a design over which ISO-NE, NESCOE and NEPOOL find agreement. FERC could also seek to direct changes on its own initiative.”
Absence of Federal Leadership
Will people be wasting their time changing capacity or energy markets to accommodate state clean energy policies after President Trump earlier this month ordered EPA to begin unwinding its Clean Energy Plan? On Friday, the D.C. Circuit Court of Appeals granted the Trump administration’s requests to hold in abeyance lawsuits challenging the CPP and EPA’s Mercury and Air Toxics Standards. (See DC Circuit Puts Hold on CPP, MATS Challenges.)
Chang said no. “New York and the New England states are going to push through their policies no matter what. Holding back on a FERC-approved action will not stop states from adopting cost-effective measures to meet their policy objectives. One could argue that the states are going to push harder in the absence of federal leadership.” (See RTOs Unfazed by Trump Climate Order.)
Californians who receive their electricity service from one of the state’s growing number of community choice aggregators (CCAs) could face higher costs under a plan being proposed by the state’s three investor-owned utilities.
The proposal — filed jointly by Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — calls for the California Public Utilities Commission to adopt a new approach to apportioning the utilities’ costs for energy contracts among the departing and remaining customers.
Utility customers departing for CCAs and direct access arrangements “are not paying their full share of costs associated with the long-term contracts [for renewables], forcing other customers to pay more,” PG&E said in a statement. California’s direct access program allows nonresidential retail customers to purchase power from independent electricity suppliers.
The new plan would replace the PUC’s current formula for calculating those costs — the power charge indifference adjustment (PCIA) — with a new system the utilities call the portfolio allocation methodology (PAM).
The PCIA acts as an exit fee, requiring customers departing for CCA to pay for their estimated share of the contracts IOUs signed to meet California’s energy policy mandates, such as the renewable portfolio standard and energy storage requirements. The fees are assessed until the termination of the contracts. Departing customers also pay a competition transition charge (CTC) that represents their share of a utility’s costs for older fossil fuel generation.
‘Financially Indifferent’
The fees are designed to keep the IOUs’ remaining bundled service customers “financially indifferent” to the departure of CCA customers, the PUC has said.
The PCIA’s calculation relies on an estimate of “above-market” costs incurred by the IOUs for procuring or building policy-driven resources.
But the utilities see a problem with that approach. The PUC bases its “above-market” cost assessment on administratively defined benchmarks developed during a time when prices for renewable energy credits and resource adequacy were higher than they are today. That makes the IOUs’ portfolios appear cheaper than they actually are, the utilities contend.
“This directly translates into departing load customers paying PCIA and CTC rates that do not fully pay for their share of the actual above-market costs of the portfolios, which is contrary to law,” the utilities said.
Under the utilities’ PAM proposal, departing customers would be charged based on the “actual” costs for the contracts procured on their behalf. On the flip side, those customers would also be allocated the “actual value” of contract portfolios, including RECs, capacity credits and revenues generated from providing ancillary services.
Under the new methodology, rates for the contracts would be regularly trued-up in the same manner as those charged to the IOUs’ remaining bundled customers, although the utilities note that most of the agreements in question are fixed-cost.
The IOUs are proposing to implement PAM on a “vintaged-portfolio” basis that depends on the customer’s departure date, “ensuring that all customers are only assigned the costs and benefits of resources actually procured or built on their behalf.”
“We can achieve the state’s clean energy goals while also supporting customer choice and treating all customers fairly and equally,” said Steve Malnight, PG&E’s senior vice president of strategy and policy.
Consumer Protections Needed
Woody Hastings, renewable energy implementation manager for the Santa Rosa-based Center for Climate Protection, told RTO Insider his support for the proposal would in part depend on whether it contains adequate consumer protections. “We have long held that the PCIA is broken,” he said.
Hastings said that while his organization agrees with the concept of bundled ratepayer indifference, his assessment of the plan would come down to exactly what expenses the utilities would roll into the new methodology.
“We need some kind of assurance that avoidable costs are being avoided,” Hastings said. “A third-party audit should happen [in order] to show that the numbers being presented are valid.”
In their filing, the utilities said they will seek approval to develop a formal process to provide load-serving entities with access to portfolio and contract data as part of the PAM.
“PAM is transparent, objective and fully consistent with California law … and should be expeditiously adopted by the commission,” the utilities wrote.
FERC staff wants more details on MISO’s proposed pro forma pseudo-tie agreement, which the RTO hopes to begin enforcing in June. On Friday, staff issued a deficiency letter posing 10 questions to the RTO — some of which echoed concerns stakeholders raised in December. (See MISO Stakeholders Narrowly Support New Pseudo-Tie Rules.)
The proposal would allow proposed pseudo-ties to be rejected and existing ones revoked if a market-to-market flowgate is not within 2% of MISO and the neighboring market’s calculated generator-to-load distribution factor.
The rules also require market participants to agree to a congestion management plan with both RTOs prior to pseudo-tie implementation and to maintain long-term firm transmission service requests from source to sink for the life of the pseudo-tie. New transmission service requests would have to be submitted a year in advance. The agreement also opens approved pseudo-ties up for restudies when changes to the source or sink occur.
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FERC’s questions asked for details in particular about the generator-to-load distribution factor threshold, the transmission service request requirement and MISO’s attempts to coordinate with PJM before filing the proposal in February.
Coordination with PJM
FERC staff asked “the extent to which MISO worked with neighboring balancing authorities” ― in this case, PJM ― in developing the protocol, including the right to terminate pseudo-ties and the requirements for firm transmission. They asked MISO to list which issues were discussed and which were still unresolved at the time of its filing, and to describe any efforts to include the agreement in the RTOs’ joint operating agreement.
PJM filed a protest to the proposed pro forma, complaining that it had not been given input in MISO’s rulemaking process.
“Please explain why the proposal includes only one balancing authority (i.e., MISO) as a signatory to the agreement, when both the native and attaining balancing authorities are impacted entities in a pseudo-tie arrangement,” staff asked. “How does such proposal adequately address the concerns of other entities involved in the pseudo-tie arrangement related to the agreement?”
Stakeholders asked MISO late last year if the RTO would attempt to memorialize a version of its agreement in the JOA, but staff said at the time that there was no need to do so. MISO Senior Director of Regional Operations David Zwergel said in April that the two RTOs were considering adding coordinated pseudo-tie policies to their JOA.
Termination Process
Staff want to know more about MISO’s process for terminating a pseudo-tie. They asked what notification or coordination MISO would use with the involved balancing authority and also asked if terminating the agreement would have the same results as terminating the pseudo-tie, as MISO used both phrases in the agreement.
Distribution Factor
MISO’s explanation of its 2% generator-to-load distribution factor threshold seemed too vague for FERC staff. They asked how the RTO would account for modeling differences between balancing authorities and how it decided the 2% figure was appropriate. In the agreement, MISO proposed comparing its generator-to-load distribution factor to either an interchange distribution calculator or the other balancing authority’s generator-to-load distribution factor, and FERC staff asked how MISO would decide which one to use.
Application to Existing Pseudo-Ties
Staff want clarification on whether the new rules will apply to existing pseudo-ties, pointing out that MISO contradicted itself in the agreement language by saying that existing pseudo-ties could be revoked if the generator-to-load distribution factor doesn’t line up within the 2% while writing, “MISO proposes that the requirements outlined in the agreement will not be retroactively applied to existing pseudo-ties.”
“Does MISO’s proposal intend to apply … to existing pseudo-ties that were implemented prior to the effective date that the pro forma agreement was added to the Tariff?” staff asked.
In previous stakeholder meetings, MISO staff have said that while the RTO doesn’t envision having to revoke any existing pseudo-ties based on the 2% threshold, it wants the right to rescind existing pseudo-ties in case an attaining RTO drastically changes its model and large discrepancies between models occur.
Firm Transmission
The firm transmission requirement is also a source of ambiguity, FERC staff said. They asked if pseudo-ties would be de facto cut off if a transmission service request (TSR) expires, and if pseudo-ties would be suspended in the time it takes to transition an old TSR to a new one. What happens, they asked, to pseudo-ties granted approval before the new pro forma but not yet holding TSRs, or pseudo-ties without TSRs that have cleared the capacity auction?
Restudies
MISO must provide FERC proposed conditions for the restudy of pseudo-ties, with more detail around “circumstances under which changes to the source or sink data could occur that would require a restudy of the TSR,” FERC said.
The RTO also has to establish who will be responsible for the cost of network upgrades if a restudy shows they are needed.
Staff also asked that MISO describe the operational and dispatch data it receives from pseudo-tied generators and how often it gets such data.
The RTO has 45 days to respond to the commission’s questions.
Future of Pseudo-Ties
FERC’s questions come as the future of pseudo-ties themselves is threatened. MISO Market Monitor David Patton filed a Section 206 complaint April 6, claiming that the increasing use of pseudo-ties degrades reliability, hampers efficient dispatch and raises costs. He asked FERC to eliminate PJM’s existing pseudo-tie definition (EL17-62). (See Pseudo-Tie Feud Rises as Patton, NYISO Protest PJM Proposal.)
MISO has predicted that about 2,800 MW of its generation will pseudo-tie into PJM in the 2017/18 planning year beginning June 1.
RENSSELAER, N.Y. — NYISO achieved a wind energy record of 1,574 MW at around noon on March 2, representing 9% of the state’s power generation, COO Rick Gonzales told the Management Committee on Wednesday. The record production came six days before powerful storms lashed Rochester and other parts of western New York. Rochester Gas & Electric reported four wind gusts on March 8 that were in the top 10 ever recorded in Rochester.
Workers clean up after the wind storm | Office of Governor Andrew Cuomo
The high wind storm event led to multiple transmission line outages, prompting NYISO to reduce both West Zone generation and Ontario imports to manage system reliability. More than 30,000 households were left without power for days.
In his operating performance report, Gonzales also said that NYISO had reduced production costs by $5.5 million so far this year through congestion coordination with PJM under the ISO’s Broader Regional Markets initiative.
LBMP up Almost 70% over March 2016
Locational-based marginal prices (LBMP) averaged $34.97/MWh in March, an almost 70% increase over the $20.66/MWh a year earlier and a $4 increase over February.
The year-to-date average through March was $37.81/MWh, a 23% increase from $30.68/MWh a year ago.
The rise in power prices was less dramatic than that in natural gas. Prices at Transco Z6 NY averaged $3.49/MMBtu in March, up 169% over the prior year.
Con Ed Black Start Testing Increased
The Management Committee voted to increase testing for black start generating units in Consolidated Edison’s service territory.
Under Tariff changes approved by the committee, all Con Ed black start units must fully test every year, rather than every other year. The units will be required to energize a transmission bus. Synchronization testing and partial testing of steam units are eliminated under the new procedures. Post-test supplemental resource evaluation running of the steam units is also eliminated, as it would necessitate synchronization.
ConEd plant on the East River at 15th Street in Manhattan, New York City
The change will bring the Con Ed territory into compliance with NERC reliability standard EOP-005 for black start testing, David Mahlmann, the ISO’s operations manager, said at the meeting on April 26.
Con Ed registered as a NERC transmission operator in July 2016. Previously, the utility had been operating only under the black start rules of the New York State Reliability Council. The council has updated its testing requirements to comply with the NERC rule and directed the ISO to change its rules.
The motion approved by the committee recommends that the NYISO Board of Directors authorize a FERC filing of the Tariff changes reflecting the new testing requirements, which were also incorporated in the ISO’s system restoration manual.
Liam Baker of Eastern Generation expressed concern about incremental costs resulting from the increased testing. “Do I have to file a [Section] 205 at FERC every time I make a capital improvement?” he said. “It might not be millions of dollars but tens of thousands, and it gets ridiculous when you have to hire counsel for a small amount.”
NYISO Assistant General Counsel Carl Patka said that incremental unit cost compensation is outlined in the Tariff, which “says that the generator will submit to the ISO its actual costs incurred, and the ISO together with FERC has 30 days to respond.”
Customer Satisfaction High
Market participants and customers are generally happy with their interactions with NYISO, according to the grid operator’s biannual customer satisfaction survey, conducted by the Siena College Research Institute (SRI).
SRI Director Don Levy told the Management Committee the ISO received a 98.8% “customer inquiry satisfaction” score on the survey, which had a response rate of 31%. The respondents were those who had made inquiries of the ISO on any subject, whether concerning an invoice or a Tariff detail.
The ISO’s rating on market participant satisfaction was lower, at 78% on a response rate of 23%. The 354 participants included end users, generation owners, other suppliers, public power and environmental entities, and transmission owners. There was brief debate at the meeting as to whether the lower score qualified as a B- or a C+.
Levy said the two surveys resulted in a combined score of 88.5%.
The surveys identified several areas in which NYISO could improve, according to Levy:
Tariff, legal and regulatory webpages;
ISO manuals, technical bulletins and user’s guides;
Market mitigation and analysis interactions;
Transparency of operations; and
Increasing the consideration of stakeholder input.
Respondents said the ISO’s strengths included accurate customer settlement invoices; timely responses to credit department inquiries; staff’s professionalism; fair handling of all interactions; and the communications department.
NYISO Switching to NAESB Digital Certificate May 1
Beginning May 1, NYISO will no longer accept its own certificates for Market Information System (MIS) applications, instead requiring a valid North American Energy Standards Board (NAESB) digital certificate, Stakeholder Services Team Lead Diana Ortiz said.
“As we speak, we are updating the wildcard SSL server certificates for all MIS production applications,” Ortiz said. The ISO has been transitioning to the new system since last year to be fully compliant with FERC Order 676-H by May 15. (See FERC Backs NERC, NAESB Standards.)
NYISO stopped issuing its own certificates for MIS applications on March 1, and about 85% of market participants have already completed the transition process. A significant portion of those who have not made the switch no longer need access to MIS applications, Ortiz said. Anyone in doubt as to their status can contact Stakeholder Services for assistance by calling 518-356-6060, sending an email to stakeholder_services@nyiso.com or using the live chat feature on www.nyiso.com.
