SPP Markets and Operations Policy Committee Briefs: July 11-12, 2017

DENVER — SPP’s Z2 Task Force will likely soon be a relic of the past, but the issues with financial credits and obligations for sponsored transmission upgrades that spurred the creation of the group aren’t going away.

The Markets and Operations Policy Committee last week endorsed the task force’s request to conclude its work. Minutes later, SPP staff told the committee the RTO would have to resettle nine years of historical Z2 credits and obligations because of billing disputes, “minor” software defects and problems in calculating the present value of creditable balances.

z2 task force spp mopc — SPP’s Markets and Policy Operations committee underway | © *RTO Insider*

SPP last fall identified about $200 million in revenue credits to be collected for transmission upgrades under its Tariff’s Attachment Z2, which details how to reimburse sponsors of network upgrades. The bills covered eight years of credits and obligations for 2008-2016, when staff failed to apply credits, complicating the task of trying to accurately compensate project sponsors and claw back money from members with debts for the upgrades. (See Preliminary Z2 Bills Released; Task Force Develops Options for Waiver Requests.)

SPP’s Charles Locke said the resettlement results will be similar to last year’s processing and stressed they will not produce duplicate or additional charges.

“What you pay or owe is only the difference between the original settlement and the resettlement,” he said.

However, Locke could provide few details beyond that. “Generally, the amounts will be small. I’m reluctant to say how small,” he said.

That drew pushback from members, some of whom could recall early staff estimates of $50 million for creditable transmission upgrade projects, which eventually ballooned to nearly $850 million in assigned costs. (See SPP MOPC Recommends 5-Year Timetable for Resolving $849M Z2 Bill.)

“Is there a number by what you mean by small?” asked ITC Holdings’ Marguerite Wagner. “It’s hard for me to understand what that actually means.”

“SPP assured us for years the amounts for Z2 were small, until they actually did the billing,” said Southwest Public Service’s Bill Grant. “I don’t get a lot of comfort when you say the amounts will be small. I do understand the reason, but it still tends to create regulatory issues for your members when they go back [to their commissions] and say, ‘Whoops! The calculations weren’t correct, so we’ll have to adjust it either up or down.’ It’s starting to get really painful.”

SPP COO Carl Monroe suggested that members focus on the difference between last year’s invoices and this year’s.

“What’s more important is the deltas,” he said. “We won’t know the deltas until we know the details of the resettlement. We won’t know the details until we go through the actual resettlement.”

Locke said staff intends to provide preliminary resettlement results in September, so members “at least have some indication of the numbers.” Staff will in September begin reprocessing data from March 2008, adding the months through July 2017. It hopes to post updated invoices in October to keep up with a timeline approved last year.

While chairing the Strategic Planning Committee on July 13, Golden Spread Electric Cooperative’s Mike Wise asked Locke whether the resettlement would be SPP’s last.

“We’re certainly hoping so,” Locke responded. “The last resettlement of historic data.”

In accepting the Z2 Task Force’s recommendation to let its charter expire, the MOPC also approved two recommendations from the group, with nine “no” votes (out of a potential 95 votes) and two abstentions. The first eliminated credits for non-capacity upgrades, such as substation facilities, while the second disposed of credits for short-term transmission service of less than a year.

The task force also reviewed the use of incremental long-term congestion rights (ILTCRs) as a substitute for Z2 credits — a practice by other RTOs — but was unable to reach consensus. The group said “significant concern” was expressed over SPP’s existing congestion rights processes and the “perceived lack of hedging.”

“Existing customers may prefer the risk of waiting on cash recovery versus getting ILTCR’s, which may have limited value in the future,” according to the task force’s recommendation to the MOPC.

The task force was formed last year to find “a more rounded solution” to Z2 credits. (See Board Approves Z2 Timeline Extension, Creates Task Force for Further Study.)

SPP z2 task force mopc — AEP’s Richard Ross | © *RTO Insider*

“We feel like at this point in time, the task force has done what it can about whether or not there is something else we can do to reduce the burden of Z2 and replace it with something else,” the task force’s chair, Kansas City Power & Light’s Denise Buffington, told the MOPC. “After many, many, many meetings, we could not get to a decision on the underlying policy or whether to socialize those costs. Unfortunately, we are where we are.”

American Electric Power’s Richard Ross, who likes to hand out gold stars to his fellow stakeholders, said he was awarding Buffington a “Richard Ross Gold Star for Cat Herder of the Year.”

MOPC Suggests 1-MW Threshold for Network Load

It came down to a single vote, but the MOPC offered direction to the Regional Tariff Working Group on how to address “inconsistency and uncertainty” over which behind-the-meter generation qualifies as network load.

The committee directed the RTWG to use a 1-MW threshold for reporting network load and to develop a list of inclusions and exclusions. In a roll-call vote, the last member to record its vote pushed approval of the motion from 65% to 66.2% — just above the 66% necessary for passage.

For customers taking network service, SPP currently follows FERC policy that sets all load at discrete delivery points as network load, which effectively sets the threshold at 0 MW for load served by BTM resources.

“At least this gives some guidance to MOPC,” Monroe said, alluding to the difficulties the RTWG has had in tackling the issue.

“If so, then make every member of the MOPC charter members of the [RTWG’s] Billing Determinants Task Force, because that is what we spent two and a half years discussing,” said Oklahoma Gas & Electric’s David Kays, who chairs the RTWG. “If 10 members were in the room, we had 10 different exceptions. If 15 members were in the room, then we had 15 different exceptions.”

The RTWG, through the BDTF, has been working on the problem since 2014 and has haggled over two revision requests (RR158 and RR 232). The task force developed the first and defined network load to include load served by certain BTM generators at discrete delivery points, while excluding load served by other BTM generators where load is shed automatically. The second revision request was developed with input from the SPC and excluded load served by a BTM generator or group of generators totaling 1 MW or less.

Members were never able to reach consensus on the proposed Tariff language. The RTWG in June rejected RR158 and RR232.

“We spent significant time on RR232 trying to cover as many issues related to behind-the-meter generation as possible,” said BDTF Chair Heather Starnes, legal counsel for the Missouri Joint Municipal Electric Utility Commission. “Different people interpret the Tariff provisions related to network load … differently. Maybe it’s not so straightforward to some folks.”

The RTWG will bring back its list of exclusions and inclusions to the October governance meetings. Assuming clarity and approval of the network load list, Starnes said, the RTWG will then develop Tariff language once again subject to the stakeholder process.

“This is a need, an immediate need,” Wise said. “I think there may be some cross-subsidization going on because of the way the network load is actually reported. I want to make sure we have consistency across the entire footprint and where the whole load gets reported accurately, because we do have substantial costs paid by the network load. All these loads need to pay their fair share of those costs.”

Staff to Review AECI Joint Project After Cost Increase

David Kelley, SPP’s director of interregional relations, told members he would spend this week reviewing an alternative to a previously approved transmission project that recently saw a 50% cost increase.

The joint project with Associated Electric Cooperative Inc., originally estimated at $9.2 million, was endorsed by the MOPC and SPP Board of Directors in January and included in the RTO’s 2017 Integrated Transmission Planning 10-year assessment. It involves installing a new 345/161-kV transformer at AECI’s Morgan substation and an uprate of a related 161-kV line, both near Springfield, Mo.

“As luck would have it,” Kelley said, AECI notified him July 7 that it raised the project’s cost estimate to “just shy of $14 million.” Because the costs increased more than 20%, the parties can revisit the initial cost-sharing agreement.

“We had another alternative that wasn’t a seams project. It provided comparable benefits but, at the time, significantly more expenses,” Kelley said. “I’d like to spend the next few days making sure we’re still making the right decision.”

Kelley said if his revised analysis is not ready for the July 25 board meeting, he will present it during the October governance meetings.

The Morgan project would be regionally funded, as it solves congestion issues on SPP’s side of the seam, and is contingent on reaching an agreement for compensating AECI. SPP was to assume responsibility of $8.7 million of the original cost estimate. AECI will own the project and be responsible for its construction, operations and maintenance.

MWG to take Another Shot at MWP Manipulation

Members remanded back to the Market Working Group a previously rejected revision request (RR221) that addressed potential manipulation of make-whole payments (MWPs) related to mitigated energy offers and no-load offers for resources with a three-day minimum run time or greater.

RR221 would have added language that establishes a permissible percentage threshold above the mitigated offer at the time of the original commitment. Ross, the MWG’s chair, said that as structured, RR221 would force SPP to report to FERC’s Office of Enforcement deviations as little as a penny.

“Monitoring is not always clear and concise,” Ross said. “We have concerns with moving forward with that request. There’s no room for error when updating offers for fuel-price changes, and the burden of implementation is on the market participants to run the calculations. You could be one penny over the line because of a rounding error. You could violate the Tariff without any impact to the market.”

Keith Collins, the Market Monitoring Unit’s newly installed executive director, agreed with Ross. (See SPP Names CAISO’s Collins to Lead MMU.)

“There has to be a bright line. Yes, it’s a violation, but let’s exercise some judgment first,” he said. “It’s been my experience with manuals and protocols that … they’re nice guidance, but if you get to a circumstance where [they have] to be enforced, they don’t carry the same weight.”

Staff and members, in agreeing to send RR221 back to the MWG, said the issue was more of a market design problem.

“Let the market design experts take another shot at this,” said Midwest Energy’s Bill Dowling. “I’d prefer to see them deal with this issue one more time. Maybe there’s a way to navigate this.”

Wind Integration Study’s Recommendations Move On

The MOPC unanimously approved staff study recommendations for how much wind energy the SPP system can reliably absorb. The RTO has routinely broken the 50% penetration level for wind and has said it can go even higher. (See SPP Eyes 75% Wind Penetration Levels.)

SPP set a record for North American RTOs in April when wind energy served 54.47% of its load — 58.67% with the addition of solar and hydro. The RTO had 15.7 GW of installed wind capacity when the study began last year and currently projects 17.2 GW by the end of 2017.

Casey Cathey, SPP’s manager of operations analysis and support, said wind has exceeded 50% penetration several times and exceeded that mark for hours at a time.

“We’re meeting all NERC standards, but there are things out there we can continually improve on,” he said.

Last year’s Variable Generation Integration Study (VIS) stressed the transmission system to a point of instability, identifying reliability impacts during high-wind and low-load scenarios. Staff analyzed 45% and 60% wind penetration levels and examined transient stability, frequency response, voltage stability and a targeted five-minute ramping.

The VIS recommends seven solutions and improvements to increase reliability, including the installation of online transient-stability and voltage-stability analysis tools. Staff has estimated the software will cost a combined $3.2 million.

Members OK Re-baselining Out-of-Bandwidth Projects

Members unanimously approved re-baselining four out-of-bandwidth projects, three of which were a combined $95.5 million less than original estimates once project owners lowered material, engineering and construction costs through more accurate data.

One estimate, an OG&E 500/161-kV transformer project, went from $15.1 million to $25.6 million because of an increase in internal costs, unforeseen site work and the need to keep the 161-kV lines energized throughout the project.

All four projects were regionally funded, with operating voltages of greater than 100 kV and cost estimates of more than $20 million. (The OG&E project was a legacy project.) They became eligible for re-baselining when their updated cost estimates exceeded the +/-20% variance bandwidth after receiving notifications to construct.

MOPC Approves 9 Revision Requests

The MOPC approved a modified two-year-old revision request (RR82) that ensures combined cycle units do not lose eligibility for start-up cost MWPs because of a physical or environmental limitation, avoiding outage deviation penalties in the process.

RR82 adds a previously discussed increase in the MWPs’ grace period for commitments from one hour to two. The revision’s implementation date was scheduled for this August to allow SPP to complete development of software that allows market participants to register and submit separate offers for combined cycle units’ multiple configurations.

Final approval of the revision request is contingent upon the Regional Tariff Working Group’s endorsement of Tariff language changes. RR82 was approved by the MOPC and board in October 2015, but staff identified the additional changes while developing the FERC filing letter.

The committee approved eight other revision requests as part of its consent agenda, which passed unanimously:

MWG-RR185: Clarifies which SPP criteria document (Planning Criteria or Operating Criteria) is referenced when used in the market protocols and the Tariff’s Attachment AE, and correctly directs users to the specific document.
MWG –RR210: Changes the process for testing a contingency reserve deployment (CRD) by adding a deployment test instruction issued in conjunction with the out-of-merit energy dispatch, allowing sufficient time to review test results and provide accurate data. Also changes SPP’s communication of the CRD’s test results from 60 minutes to within one business day. Should a resource retest be requested, SPP agrees to complete the test within two business days, subject to its assessment of system stability.
MWG-RR222: Includes a multiconfiguration combined cycle resource’s (MCR) committed and actual configuration for each interval in a bill determinant report, allowing MCRs to shadow the configuration SPP is using to settle these resources.
MWG-RR225: Cleans up confusing and misleading Tariff language on incremental long-term congestion rights (ILTCRs) that could construe ILTCRs as load-serving entities or non-LSEs.
MWG –RR 226: Changes settlement location pairs that have potential for unconstrained flow to electrically equivalent settlement locations during the auction revenue rights process, to comply with a FERC order (ER17-310). SPP will post the settlement locations before the annual ARR allocation process, along with the system topology and other data.
MWG-RR 229: Satisfies FERC Order 831’s requirements on energy offer caps by using actual costs for make-whole payments on offers above $1,000/MWh. According to the order, costs underlying a resource’s cost-based incremental energy offer above $1,000/MWh must be verified before that offer can be used to calculate LMPs.
ORWG-RR 228: Clarifies existing planning criteria language for system operating limits to reduce the potential of misinterpretation by entities complying with NERC reliability standards.
RTWG-RR233: Ensures that eligible network customers will not be billed twice for the same delivery. Customers will also not be assessed charges against a specific use of a single owner’s facilities that do not receive the benefit those charges provide to other transmission owners under the Tariff. The Southwestern Power Administration (SPA) and SPP have entered into a contract (Attachment AD) that provides for SPP to offer transmission service on SPA’s facilities, including network integration transmission service (NITS), and allows SPA to participate in the RTO’s transmission planning. SPA also voluntarily contributes to Schedule 11 representative of the grandfathered transmission service agreements (GFAs) it has in place for non-federal uses of its transmission facilities. SPA and SPP are transitioning customers with GFAs to NITS under the Tariff, creating implications for new customers who also receive federal hydropower deliveries.

The consent agenda also included:

Modifications to the revamped revision process, adding the Integrated Transmission Planning Manual and certain technical documents to the approval process. (See “Changes Proposed for Revision Process,” SPP Markets and Operations Policy Committee Briefs.)
The scope for the expedited re-evaluation of the Kummer Ridge-Roundup 345-kV line. (See “MOPC Endorses Re-evaluation of Basin Electric Project,” SPP Markets and Operations Policy Committee Briefs.)
A waiver request to FERC restating settlement prices for transmission congestion rights (TCRs) at Omaha Public Power District’s Fort Calhoun nuclear plant site. The plant was retired Dec. 1, 2016, but incorrect modeling of shift factors from Dec. 1 to Dec. 14, 2016, resulted in the marginal congestion component being overstated and the TCR settlements sourcing at the location being understated.

— Tom Kleckner

July 18, 2017

MISO Members: Court Rebuff May Reduce External Zone Chances

By Amanda Durish Cook

MISO last week presented stakeholders with a proposal to tighten rules on capacity imports amid uncertainty over whether a recent appellate court ruling will impact FERC’s ability to approve the changes.

In early July, the D.C. Circuit Court of Appeals eliminated portions of PJM’s minimum offer price rule that have been in place since 2013, ruling that FERC overstepped its authority when it suggested changes to a PJM proposal that resulted from a compromise among stakeholders. The court said although FERC can make minor changes to Tariff filings, it cannot substitute its own plan and must approve or reject an RTO proposal as is. (See PJM MOPR Order Reversed; FERC Overstepped, Court Says.)

MISO’s proposal — which would integrate external resources zones into the Planning Resource Auction using a single clearing price for each external balancing authority — has been met with a mixed stakeholder response. As a result, some stakeholders think the RTO should hit pause on a proposed September FERC filing and continue working for a proposal that has broad support.

FERC’s Power Diminished?

MISO Assistant General Counsel Michael Kessler said that the appellate ruling means FERC’s power may be diminished when it regains its quorum. (See related story, Trump Names Energy Lawyer McIntyre as FERC Chair.)

“It’s sort of a new package of standards. As it stands now, it’s a definite limitation on the commission’s authority to accept changes on a Section 205 filing,” Kessler said during a July 12 Resource Adequacy Subcommittee meeting.

Kessler said there is some ambiguity in the ruling on the distinction between significant changes that FERC is prohibited from suggesting and minor changes the commission can order.

“This isn’t just a PJM, MISO issue; it’s an industry issue. Any filing party will have to consider what FERC can and can’t do now since the back-and-forth that we’ve gotten used to [since the 1990s]. That route is not going to be available anymore. The whole industry will be carefully reviewing this to see the implications on filings going forward,” Kessler said. He added that all pending appeals of FERC-ordered changes could be up for reinterpretation.

Stakeholders said that with FERC expressly prohibited from ordering changes to RTO proposals, chances of the commission approving the contentious locational proposal may be smaller.

Customized Energy Solutions’ David Sapper, representing MISO’s Load-Serving Entity Coalition, said the ruling may signal to MISO that it’s time to only pursue filings with majority stakeholder support.

Last month, Sapper and the coalition made a motion to delay the locational proposal in favor of a capacity transfer rights proposal that would treat long-term supply arrangements involving external resources the same as internal planning resources. (See Changing Course, MISO Adopts IMM External Resource Zone Plan.) Stakeholders later passed the motion in an email vote 34-11 with three abstentions.

MISO Executive Director of Strategy Shawn McFarlane reminded stakeholders that the motion is only treated as advice and is not binding. He said the motion signals to the RTO that more discussion with stakeholders is needed.

“So, we think we need some follow-up conversations,” he said. “We’ll be reaching out to stakeholders over the next few weeks. … We think some one-on-ones is going to be appropriate.”

McFarlane added that MISO will be making sure that the stakeholders that voted in favor of the motion understand the locational proposal; he said it would look for some possible modifications as well.

Asked if FERC would reject the filing without consensus among MISO and its stakeholders, McFarlane said it was too early for speculation and that the RTO still has time to alter its proposal.

Combined Filing Likely

Indianapolis Power and Light’s Ted Leffler asked if MISO has considered filing the locational proposal separately from hedging rules so the external location zone filing is not rejected based on its proposed approach on allocating excess auction revenues.

MISO has proposed that auction revenues be first handed to resources with historical commitments, with pre-RTO formation capacity arrangements and pre-locational capacity arrangements given first consideration for funding. External resources with contracts to MISO load affected by the proposal are next in line before the RTO doles out revenues as usual using an existing zonal deliverability benefit assessment.

McFarlane said MISO has considered separate filings but is still leaning toward a combined filing.

Leffler asked how many external capacity resources will become unmarketable because of a low clearing price and the lack of a historic capacity agreement.

“I think it’s important that we understand how much is at risk here,” Leffler said. “The auction clearing prices are very sensitive to changes in supply and demand.”

“We don’t feel like we have a choice but to address the potential reliability issue from our current approach here,” McFarlane said. He added that MISO is eyeing a “reasonable” approach that can win FERC approval.

Some stakeholders are still asking MISO for more details on how external resources are treated based on geographic distance from the RTO’s footprint. They asked that prices be based on a resource’s proximity to loads inside MISO instead of a uniform external balancing authority price.

Laura Rauch, MISO manager of resource adequacy coordination, said that except for resources near a border, the RTO sees no difference in deliverability in resources situated “150 miles away from MISO or 300 miles from MISO.” Its concern is whether a resource in Chicago or New Jersey can deliver against Lower Michigan’s clearing requirement “as well as a Detroit resource,” she said.

July 18, 2017

PJM PC/TEAC Briefs: July 13, 2017

PJM Maintaining Separate Load Peaks in Model

VALLEY FORGE, Pa. — The Planning Committee last week approved PJM’s recommendation to use 10-year historical data from 2003 to 2012 and to change the “world” peak week in its 2017 reserve requirement study.

transmission expansion advisory committee pjm — Rocha-Garrido | © *RTO Insider*

PJM’s Patricio Rocha-Garrido told stakeholders the RTO decided to separate its peak load from that of the “rest of world” because of software limitations. Coincident peak distributions from the PJM load forecast cannot be used directly in its PRISM (probabilistic reliability index study model) software, which handles model uncertainty by week rather than day-by-day.

“The world” comprises of neighbors MISO, New York, the Tennessee Valley Authority and SERC Reliability’s VACAR region in Virginia and the Carolinas — areas from which the RTO would seek to import generation if it runs short.

(See “ISO-NE out of this ‘World,’ According to PJM Reserve Requirement Study,” PJM Planning Committee/TEAC Briefs.)

“When we have PJM and ‘the world’ peaking on the same week, effectively we’re having PJM and ‘the world’ peaking on the same day,” Rocha-Garrido said.

However, over the past 18 years, PJM and “the world” have peaked simultaneously eight times, while they have not peaked together 10 times.

In response, PJM moved the world peak to Week 11 in the summer and retained its peak on Week 10 to match the “historical diversity” in peaks.

Rocha-Garrido said the 2003-2012 load model, which was also used in last year’s study, was “a close second place” to the top-ranked 2004-2012 time period but had the advantage of an extra year of data.

“We do not see evidence to change that this year,” he said.

The recommendation was endorsed by acclamation, with no objections or abstentions.

RTEP Cycle Revisions Approved

The committee approved revisions to the rules for the Regional Transmission Expansion Plan, agreeing to extend the cycle from one year to 18 months.

PJM’s Amanda Long said the planning cycle will begin in September and run through February of the following calendar year. A new cycle will begin every September, overlapping the previous cycle. (See PJM Making Cost Consciousness a Focus for RTEP Redesign.)

The committee also approved Operating Agreement changes to extend the 30-day competitive proposal window for short-term projects to 60 days beginning about June annually. The long-term proposal window will remain at 120 days.

The proposal was endorsed by acclamation, with no objections or abstentions.

Resilience to Become Planning Driver

PJM’s Mark Sims explained how the RTO’s recent focus on resilience will impact its planning processes.

NERC’s standards require PJM to consider in its planning critical “stressed” conditions so it can manage the system regardless of actual conditions on any day. In addition, NERC requires the RTO to conduct a system assessment and explore potential solutions of low-probability “extreme” events.

As a result, Sims said, PJM will seek to identify “worst offenders,” such as circuits that frequently are involved in low-probability events. (See “PJM Reconsidering Planning Assumptions,” PJM Planning & Tx Expansion Advisory Committees Briefs.)

“It’s not involved in one low-probability event; it’s involved in many. So in my opinion, it’s no longer low-probability,” Sims said, adding that it “might” make sense to fix these issues.

John Farber of the Delaware Public Service Commission reiterated his concerns from a similar conversation during the Operating Committee meeting earlier in the week.

“There are major issues with implementing resilience as a standalone driver in the RTEP,” he said. “Achieving a sufficient level of objectivity to justify its inclusion as a standalone driver in the RTEP is just a difficult challenge to deal with.”

He said it will be difficult to develop objective cost and benefits criteria to justify millions in spending, especially when individual states may have different viewpoints on spending the money.

Greg Poulos of the Consumer Advocates of the PJM States agreed. Developing appropriate metrics will be important to determine how goals will be achieved, he said. The timeline is another issue, he said.

“There’s a lot of concern about things adding up,” he said. “I certainly agree it’s an evolution, but the consumer advocates are concerned it’s a slippery slope. Where does it begin and where does it end?”

Sims assured stakeholders it would be a “very deterministic” process. “I think this paradigm is going to be a little bit of a shift,” he said.

Winter Evaluation

PJM’s Tom Falin provided an update on the RTO’s analysis of winter resource adequacy and capacity requirements, the subject of an issue charge approved by stakeholders last year. The details highlighted the differences across the RTO. (See “Winter Resource Adequacy Analysis Raises Questions,” PJM Planning & Transmission Expansion Advisory Committee Briefs.)

An analysis of the ratio between the winter and summer peaks in each locational deliverability area (LDA) found that the East Kentucky Power Cooperative was the heaviest winter peaking LDA in the RTO, with a winter-summer ratio at about 1.3. The RTO itself is mostly summer peaking with a ratio of .87, and Rockland Electric is the heaviest summer-peaking LDA with a ratio of about .59.

“The heaviest summer-peaking LDAs are basically [in] New Jersey,” Falin said.

The loss-of-load expectation analysis results found that, even including the outliers from the winter of 2014-15 that included the polar vortex effects, and assuming historical forced outages and the maximum historical planned outages, the LOLE was .02 days/year. Falin noted that these numbers only included generator forced outages and that transmission outages would need to be considered as well.

Going forward, Falin said PJM will compute summer and winter reliability requirements for the RTO and selected LDAs while continuing to investigate a winter load forecast model.

Solar Capacity Factors Class Averages

PJM has updated its capacity factors for wind and solar based on actual summer data from 2014-2016.

PJM’s Jerry Bell said the analysis found that wind turbines have a capacity factor of 14.7% in mountainous terrain during peak summer hours between 3 and 6 p.m. and 17.6% in open, flat terrain during the same period. Solar capacity factors ranged from 60% for ground-mounted arrays that track the sun, to 42% for fixed ground-mounted panels, to 38% for all panel types other than ground-mounted.

The capacity factor affects generators’ capacity revenues and a project’s entitlement to capacity injection rights.

Renewable developers can request higher capacity factors for their projects if they can provide evidence to prove their generators operate at higher levels.

The study hasn’t yet considered how capacity factors are affected by degradation of the equipment over time, but Bell said it will be added in the future. Several stations were removed from the analysis because they displayed obvious degradation over time, he said. Degradation is, however, factored into CIRs for stations, he said.

Transmission Expansion Advisory Committee

Transmission Proposal Window Opens

PJM opened a 45-day window last week seeking proposed transmission projects to fix reliability criteria violations on 43 flowgates. The window will close on Aug. 25.

The flowgates were identified in the 2022 analysis: 34 in PJM’s Western Region, six in the Southern Region and three in the Mid-Atlantic Region. The remaining 161 flowgates from the analysis were excluded from the window as either immediate-need projects or under 200 kV, which is PJM’s threshold for opening projects to competitive bidding. The RTO has found that projects under 200 kV tend to be upgrades handled by the incumbent transmission owner.

Updates to AI Analysis

Staff have updated PJM’s beneficiary analysis for the Artificial Island project to address issues raised by stakeholders at the June 9 special Transmission Expansion Advisory Committee meeting. Among the additions was a list of transmission facilities that could compose a stability interface.

Most of the $280 million bill for the project would shift from Delaware to New Jersey and Pennsylvania under two alternative methodologies outlined in the analysis. But it will be up to PJM’s TOs to petition FERC to adopt a new methodology for the project. “PJM does not have the authority to devise or file allocation methodologies as federal law makes clear that the Section 205 filing rights over rates and cost allocation in this area rests with the PJM transmission owners,” the report says.

The project, PJM’s first foray into competitive bidding under FERC Order 1000, has been bogged down in stakeholder infighting for years. In April, PJM’s Board of Managers lifted a suspension on the project and re-awarded it to LS Power. (See PJM: AI Costs Would Shift to NJ, PA Under New Allocations.)

— Rory D. Sweeney

July 18, 2017January 15, 2024

SPP Strategic Planning Committee Briefs: July 13, 2017

DENVER — The SPP Strategic Planning Committee last week directed RTO staff to move forward with a high-priority congestion study that earlier failed to gain traction in the Markets and Operations Policy Committee.

SPP Board Chair Jim Eckelberger suggested that staff incorporate suggestions from American Electric Power’s Richard Ross, who presented the MOPC with a new approach to determining why customers participating in the congestion-hedging market are not being allocated their full auction revenue rights and long-term congestion rights (LTCRs).

Under the AEP plan, staff would study the last cycle of hedge requests, identify unfulfilled requests, determine the effects of counterflow not requested in the ARR process and determine upgrades necessary to allow awarding of those unfulfilled requests.

“There’s significant congestion restricting service,” Ross said. “Members played by the rules, sought out firm service, paid for upgrades on the system, paid for Z2 credits, but still find themselves in a situation where they are paying for congestion because TCRs are not feasible.”

Ross’ approach would focus on the first round of the annual auction, where market participants seek the congestion paths most important to them.

“We use that information to figure out what upgrades are needed,” he said. “We need to go through this process to determine the bottlenecks and how to solve them. The motivation of the [market-clearing] engine is to maximize the clearing of those ARRs or TCRs. What happens is transmission requests or ARRs with small amounts end up eroding away the congestion hedges.”

Ross’ alternative approach was rejected by the MOPC, as was staff’s hybrid approach using some of AEP’s suggestions. Staff was directed to undertake the study addressing congestion in the Texas Panhandle and western Oklahoma during April’s Board of Directors meeting, when directors and members canceled a major 345-kV Southwestern Public Service project near Amarillo. (See SPP Board Cancels Panhandle Line, Seeks New Congestion Study.)

SPP staff are to report back to the board next week with their study assumptions and scope. The study is to be completed no later than April 2018.

During the MOPC meeting, members pushed back against the idea of another one-off study because SPP’s first assessment of future needs — part of its revamped transmission planning process — is due in October 2019.

Eckelberger said, “Let’s ask the staff to bring us back in two weeks its best proposals on how we can swing through this process, learn something and get us a product we can execute in the April time frame of next year, as opposed to waiting until October ’19.

“I’d say it’s pretty easy,” he said. “Don’t put anything in [that study] that’s speculative, like oncoming wind and solar. Use today’s gas prices, because we’re talking about something that works between now and a different approach in 2019.”

Eckelberger suggested to staff and the SPC that any assumption of new wind capacity above 4 to 5 GW with signed interconnection agreements is speculative.

“I don’t consider [the 4-5 GW] speculative,” he said. “I consider it real. It’s going to come by 2019 or 2020. Where it happens remains to be seen.”

The chairman received support from members. Westar Energy’s John Olsen said the congestion study’s April deadline would mesh well with SPP’s transmission planning and help the Economic Studies Working Group in preparing scenarios to be analyzed.

“That’s about the same time we go into heavy data gathering of the [planning study],” Olsen said. “It will be a great help to the ESWG as it determines the next round of futures. It’ll be a great way for them to have a head start on what the futures might look like, and where we need to go.”

SPC Approves Zonal Placement Process Document

The SPC approved minor edits to a process document that lays out the steps SPP must follow in making transmission zonal placement decisions, although the document does little to quell stakeholder objections about cost shifts within the process. (See Divide Evident Between SPP Tx Owners, Users.)

The Transmission Owner Zonal Placement Process document addresses the growth of transmission zones in SPP’s footprint and concerns expressed over the process in FERC proceedings. Since 2004, the RTO has gone from 15 pricing zones and 15 separate zonal annual transmission revenue requirement (ATRR) amounts to 18 pricing zones and 47 ATRR amounts.

“It’s a first step. Denise’s proposal was a first step,” said SPS’s Bill Grant, referring to Denise Buffington of Kansas City Power & Light, who submitted a revision request that was rejected by the MOPC. “There’s still a lot of work to do in this area. If we vote this and move it forward and think our work is done … it’s not even close to being done.”

“This is as good as we’re going to get,” SPP’s Michael Desselle said, noting the SPC had already decided it had done all it could with the zonal-placement issue. (See SPP Advances KCP&L Cost Shift Proposal.)

The process document spells out the following four steps:

1. 1. The applicant transmission owner (ATO) notifies SPP of its intent to transfer functional control of existing facilities to SPP and to file with FERC to recover the ATRR.
  2. SPP requests project information from the ATO upon notification.
  3. SPP performs integration analysis following a preliminary review of the ATO’s information. This step includes the RTO notifying TOs and network customers in zones into which the ATO could be integrated and providing them evaluation of cost shifts within 45 days after receiving the necessary information.
  4. Negotiation between the affected parties to discuss the zonal placement decision, potential cost shifts and any other resulting issues. The discussion period is limited to 45 days, with SPP available to facilitate if requested.

“I remain concerned because it doesn’t satisfy my concerns about lack of notice,” Buffington said, noting SPP gave an ATO entering KCP&L’s zone several alternatives before contacting the utility. “I understand SPP makes decisions on which zone to place someone, but when you talked to [the ATO], you showed them different options.”

“I’d really like your mindset to be looking out for your members and coordinating with your members,” Ross told SPP staff. “Don’t even look at it as ‘mother-may-I’ with someone who isn’t even part of system. Members who might be impacted should be your first thought, not your second.”

In the end, Grant and Nebraska Public Power District’s Traci Bender were the only members of the 14-person committee to vote against the motion. (Buffington is not a member of the SPC.) Kansas Electric Power Cooperative’s Les Evans abstained.

“I think this is a really good step forward,” said SPC Chair Mike Wise, of Golden Spread Electric Cooperative. “This gives a firm sense of the communication process.”

July 18, 2017

California Lawmakers Extend Cap-and-Trade

By Jason Fordney and Robert Mullin

California’s landmark program to combat climate change has received a new lease on life — 10 years, to be exact.

california greenhouse gas cap-and-trade — Brown | *State if California*

Both houses of the California State Legislature voted late Monday to extend the state’s greenhouse gas (GHG) cap-and-trade program until 2030 (AB-398). The bill now advances to the desk of Gov. Jerry Brown, a key supporter of the legislation.

“Tonight, California stood tall and, once again, boldly confronted the existential threat of our time,” Brown said in a statement. “Republicans and Democrats set aside their differences, came together and took courageous action. That’s what good government looks like.”

The outcome is a major victory in Brown’s efforts to ensure that California remains at the forefront of global environmental policy despite President Trump’s moves to roll back the previous administration’s measures to reduce carbon emissions.

Even better for Brown: Both the Senate and Assembly passed the legislation with more than two-thirds of members voting in favor. That margin should protect the bill from challengers who have argued that cap-and-trade constitutes a tax that requires supermajority approval under state law.

The state’s Supreme Court recently declined to review a court challenge by business groups. (See California High Court Upholds Cap-and-Trade.)

The cap-and-trade extension passed the state Senate 28-12, a single vote above the threshold needed to obtain a supermajority. Just one Republican — Sen. Tom Berryhill of Modesto — crossed the aisle to join Democrats who voted unanimously in favor of the measure. Assemblymembers voted 55-21 in favor, with seven Republicans and all but six Democrats — three no votes, two abstentions and one absence — in support.

The bill also mandates that large industrial facilities such as oil refineries upgrade emissions equipment by December 2023, and it increases penalties for pollution. It also requires emission reductions from mobile and stationary sources.

“Californians overwhelmingly support our efforts to tackle climate change; they know it’s an urgent threat and they want us to continue to lead. That’s exactly what we’re doing by extending cap-and-trade,” Senate President pro Tempore Kevin de Leòn said.

The cap-and-trade program will help the state meet its goal of reducing GHG emissions to 40% below 1990 levels by 2030, Brown’s office said last week in drumming up support for the bill.

The measure “extends the program by 10 years in the most cost-effective way possible,” according to Brown. It will ensure that carbon pollution decreases as the emissions cap declines and use of out-of-state carbon offsets is reduced; free carbon allowances will be reduced by more than 40% by 2030, he said.

Lawmakers on Monday also passed AB-617, a bill that provides for neighborhood air monitoring — an attempt to placate environmental justice groups that have been skeptical of cap-and-trade because it doesn’t directly address local pollution in low-income areas.

“The passage of AB-398 and AB-617 builds upon the momentum set forth by last year’s landmark climate change polices; establishing a comprehensive, statewide program that will allow us to achieve our ambitious climate goals, while ensuring the market stability necessary to retain industry jobs and address vital public health and air quality issues,” said Assembly member Eduardo Garcia, a sponsor of both bills.

The legislative package was “the product of weeks of discussions between the administration and legislative leaders with Republican and Democratic legislators, environmental justice advocates, environmental groups, utilities, industry and labor representatives, economists, agricultural and business organizations, faith leaders and local government officials,” Brown’s office said.

Under the cap-and-trade program, large GHG emitters must purchase emissions credits at the California Air Resource Board’s quarterly auctions to cover emissions not accounted for with free credits. Extending the program will keep auction proceeds flowing to environmental initiatives around the state, the governor’s office said.

“To date, these investments have preserved and restored tens of thousands of acres of open space, helped plant thousands of new trees, funded 30,000 energy-efficiency improvements in homes, expanded affordable housing, boosted public transit and helped over 100,000 Californians purchase zero-emission vehicles,” the office said.

Brown said he will continue to pursue climate change policies despite Trump’s pledge to withdraw from the Paris Agreement on climate change, which the president says is unfair to the U.S. Brown recently announced that California will host global leaders in September 2018 for a Global Climate Action Summit to support the agreement.

Brown last week also announced the “America’s Pledge” program with businessman and former New York City Mayor Michael Bloomberg. The governor’s office described the program as “a new initiative to compile and quantify the actions of states, cities and businesses in the United States to drive down their greenhouse gas emissions consistent with the goals of the Paris Agreement.” The initiative will produce a report on aggregate climate change commitments by states, cities, business and educational institutions, and a “roadmap for future climate change ambition.”

(See related story California Zero-Carbon Power Bill Advances.)

July 17, 2017

Trump Names Energy Lawyer McIntyre as FERC Chair

By Michael Brooks

The White House on Thursday announced that President Trump intends to nominate lawyer Kevin McIntyre as chairman of FERC.

The coleader of Jones Day’s energy practice in D.C., McIntyre has represented energy companies in litigation, compliance and enforcement matters and corporate transactions.

McIntyre, who has been rumored for months as Trump’s choice for the chair, would join more than a dozen other Jones Day alumni in the administration, including White House Counsel Don McGahn, a former Jones Day partner. Trump’s campaign reportedly has paid the firm $3.3 million in legal fees since 2015.

The White House said Trump will ask the Senate to confirm McIntyre for the remainder of former Chair Norman Bay’s term, which ends in 2018, and a full term ending in 2023.

McIntyre’s naming would fill the third Republican vacancy on the five-member commission, which could soon be restored to full strength.

Pennsylvania Public Utility Commissioner Robert Powelson and Neil Chatterjee, energy adviser to Senate Majority Leader Mitch McConnell (R-Ky.), both Republicans, have already advanced out of the Senate Energy and Natural Resources Committee and are awaiting confirmation votes by the full Senate. Trump has also said he intends to nominate Richard Glick, general counsel for the Democrats on the committee. (See Trump Taps Senate Aide, Former Lobbyist for FERC.)

Trump has yet to officially nominate Glick, however. And Chatterjee and Powelson are on a list of 44 others awaiting a confirmation vote.

The Senate has been mired in its effort to repeal the Affordable Care Act. McConnell on July 11 announced he would delay the chamber’s usual August recess for two weeks to ensure more time to complete action on legislation and nominations.

FERC has been down to one commissioner — acting Chair Cheryl LaFleur — since the departure of Commissioner Colette Honorable at the end of last month. It has been without the necessary three-person quorum since Bay left in February.

ferc trump kevin mcintyre — Acting FERC Chair Cheryl LaFleur (second from right) will be joined by four new members if Democrat Richard Glick (far right) and Republicans Kevin McIntyre (center), Robert Powelson (far left) and Neil Chatterjee win Senate confirmation.

The Natural Gas Supply Association and the Center for Liquefied Natural Gas released a joint statement praising McIntyre’s nomination but lamenting the amount of time it is taking to restore FERC’s quorum.

“Billions of dollars of investment and thousands of job opportunities in the U.S. continue to be sidelined by a lack of a quorum at FERC,” NGSA CEO Dena Wiggins said. “It is essential that the nominees be given the opportunity to be approved as quickly as possible.”

CLNG Executive Director Charlie Riedl added: “Restoring a quorum at FERC is essential to the LNG approval process, and we hope that Kevin McIntyre and the rest of the nominees will have their floor vote as soon as possible.”

July 17, 2017

EIM Leaders Endorse CAISO Gas Constraint Measure

By Jason Fordney

FOLSOM, Calif. — Western Energy Imbalance Market (EIM) leaders last week endorsed a CAISO proposal that would allow the ISO to constrain output from natural gas-fired plants across the EIM in response to potential restrictions on gas deliveries.

The five-member EIM Governing Body voted unanimously to approve applying to the entire EIM footprint the gas constraint developed by CAISO in the Aliso Canyon Gas-Electric Coordination Phase 3 straw proposal. That vote and other advisory decisions will go before the ISO’s Board of Governors later this month.

CAISO originally created the mechanism — which gives the grid operator authority to curtail output from plants in gas-constrained areas — to address reliability worries stemming from the outage at the Aliso Canyon gas storage facility. The latest proposal would extend that authority throughout the footprints of both the ISO and the EIM.

The EIM Governing Body Unanimously Approved Gas Constraints | © *RTO Insider*

Restrictions on gas withdrawals from the 86-Bcf facility near Los Angeles have created supply concerns for power plants, and there are efforts underway to shut the facility down for good as residents still complain of health problems from the massive gas leak discovered there in October 2015. The California Public Utilities Commission is exploring closing the facility completely. (See Study to Weigh Aliso Canyon Shutdown.)

If FERC approves the plan sanctioned by the EIM body, the market tool will not expire in November as previously planned. CAISO said the tools will be in effect until it completes development of a set of commitment cost and default energy bid enhancements.

Greg Cook, CAISO’s director of market and infrastructure policy, told the body that there are continuing operational risks from the outage at Aliso Canyon. The constraints will address situations in which EIM gas-fired plants have limitations on the amount of gas they can burn in excess of what is scheduled, as well as when generators have limited firm pipeline capacity and additional capacity is not available when gas demand is high.

caiso eim natural gas — Howe | © *RTO Insider*

Governing Body Chair Douglas Howe questioned whether the program could create opportunities for market abuse and whether CAISO’s Department of Market Monitoring supported the measure. The department recently commented that the ISO had not fully justified the plan. (See Qualified Support for CAISO Gas Constraint Plan.)

“How convinced can we be that we won’t be opening up the door to market abuse in the EIM portion” outside CAISO? Howe asked.

There will be a well-vetted market process to make sure there is a legitimate physical constraint and opportunities are not created for market abuse or other unintended consequences, CAISO Vice President of Market and Infrastructure Development Keith Casey told Howe. The tools would only be used to manage physical supply problems on the system, not for economic purposes.

CAISO said it plans to follow a recommendation from the Monitor that it automate the process by which transmission paths are deemed uncompetitive, which triggers the mitigation measures.

The board yesterday also unanimously approved a proposal to include additional gas price indices to be used as a price threshold in the net benefits test, and changes to the board’s charter regarding its interaction with the Regional Issues Forum.

July 17, 2017

MISO Ponders Reserve Scheduling Fix

By Amanda Durish Cook

MISO is considering the possibility of factoring transmission constraints into its reserve requirement modeling to help prevent occurrences of scarcity pricing.

Staff are evaluating changing the algorithm underpinning the minimum zonal reserve requirement to reflect energy flow constraints. Under current practice, MISO calculates reserve requirements for a single operating day three days in advance using an offline study to produce results to be posted in time for the day-ahead market.

But actual operating conditions can change from original study assumptions, said MISO Senior Manager of Transmission Security Planning Mike Mattox, adding that the three-day modeling timeline has been in place for about 10 years.

Dhiman Chatterjee, director of market evaluation and design, said a reserve model that does not capture constraints in the interim can unnecessarily create scarcity pricing for reserves.

MISO staff began taking notice of the issue after events occurring April 1, when an offline study predicted an 84-MW minimum contingency reserve requirement for Zone 6, which encompasses Indiana and a slice of Kentucky. In reality, more reserves were needed to compensate for generation and transmission outages in southeast Louisiana, including the shutdown of the Waterford 3 nuclear unit. As a result, Zone 6 experienced an outflow of energy to the south, triggering operating reserve scarcity conditions for 152 five-minute intervals during the day, with spinning and supplemental reserves clearing at about $200/MWh during 131 intervals and $1,100/MWh during 21 intervals.

“We’re really focusing on the event in April. We saw some relatively high prices for the reserves. … In this case, we saw it was bit counterintuitive so we dug into that,” said Chatterjee during a July 13 Market Subcommittee meeting.

MISO Principal Advisor of Market Development and Analysis Yonghong Chen said the constraints can be accounted for in the day-ahead modeling process to address reserve deliverability. Chen said that had the modeling more explicitly accounted for constraints, there would have been more inexpensive prices and a reduction in post-reserve deployment congestion.

“There is really no need to go into scarcity pricing,” Chen said.

Chatterjee said MISO is in the early stages of analyzing an additional modeling step that it could implement by the end of this year or early next year. He said staff would return to the subcommittee next month to update stakeholders on the feasibility of the change.

July 17, 2017

CAISO Monitor Says EIM Bid Limits No Longer Needed

By Jason Fordney

FOLSOM, Calif. — Energy transfer capacity in the Western Energy Imbalance Market (EIM) footprint is now sufficient to justify removing bid limits that are in effect for members PacifiCorp, NV Energy and Arizona Public Service, CAISO’s internal Market Monitor said last week.

EIM transfer capacity caiso monitor — Hildebrandt | © *RTO Insider*

Analysis by the Department of Market Monitoring found that EIM areas are structurally competitive during almost all intervals, Director of Market Monitoring Eric Hildebrandt said July 13 in a briefing to the EIM Governing Body at CAISO headquarters.

The power sellers are now limited to submitting EIM energy bids at or below cost-based default energy bids at all hours. They must get permission for the change from FERC, which requires companies joining the EIM to file for authority to charge market-based rates. PacifiCorp and NVE are both subsidiaries of Warren Buffett’s Berkshire Hathaway Energy.

“We are prepared to submit comments in support of the filing” to lift the restrictions, Hildebrandt said, noting that the Berkshire companies are potentially pivotal in a very small portion of intervals. Automated bid mitigation procedures effectively mitigate market power when imbalance demand is greater than transfer capacity, he said.

Under-mitigation in the 15-minute market, when congestion occurred but bid limits were not triggered as they should have, fell to 1.5% of intervals in the first half of 2017, compared with 17% a year earlier, he said. CAISO’s rules effectively limit the companies’ market power when EIM areas are not competitive.

The companies have been trying to get the mitigation measures lifted. They had argued that the measures imposed by FERC are out of proportion to the market power risks from imbalance energy, because of the small amount of load served by imbalance. They also said they have no incentive to exercise market power because they are large consumers of imbalance energy and would lose money if prices are too high.

But FERC cited market power concerns in May 2016 when it denied a request by NVE and PacifiCorp to rehear a previous decision that prohibited the two companies’ generating units from offering energy into the EIM at prices above default energy bids. (See Berkshire Denied Rehearing on EIM Market Power.)

Growth in EIM Transfer Capacity Has Increased Market Competitiveness, Monitor Says | *CAISO Department of Market Monitoring*

An economist with the Market Monitor said late last year that increased transfer capacity in the EIM is limiting congestion and reducing participants’ ability to use market power in their balancing authority areas. (See Increased Transfer Capacity Reducing EIM Congestion.)

FERC late last year also denied a request by NVE, PacifiCorp and 19 other Berkshire affiliates to rehear a decision prohibiting the companies from offering power at market-based rates in four neighboring balancing areas in the West, including the PacifiCorp East (PACE), PacifiCorp West (PACW), Idaho Power and NorthWestern Energy areas. The commission rebuffed the companies’ contention that an earlier ruling had denied them due process because it failed to notify them of “newly announced standards” for determining market power. (See FERC Upholds Berkshire Market-Based Rate Ruling.)

The EIM already includes the PACE and PACW areas, while Idaho Power is slated to join the market in April 2018.

July 17, 2017

NYPSC Extends Con Ed Demand Program

By Michael Kuser

ALBANY, N.Y. — The New York Public Service Commission last week approved an indefinite extension for Consolidated Edison’s demand management program in New York City’s Brooklyn and Queens boroughs, which aims to defer an estimated $1 billion in local infrastructure spending.

The commission’s July 13 order retains the original Brooklyn-Queens Demand Management (BQDM) program’s $200 million budget but caps expenditures on utility-side non-traditional solutions — such as storage batteries — at $50 million, including what the company has spent to date.

NYPSC Commissioners (Left to right) Burman, Rhodes, Sayre and Alesi | © *RTO Insider*

Con Ed has so far spent $46.56 million on the program, according to the most recent BQDM quarterly report.

The program allots Con Ed $200 million to procure market-based, distributed energy resource solutions such as energy efficiency, energy storage, distributed generation and demand response to achieve load reductions on the sub-transmission feeders supplying the company’s Brownsville No. 1 and No. 2 substations. The program aims at achieving 41 MW of customer-side DER and load reduction, as well as 11 MW of non-traditional utility-side solutions by summer 2018.

“In the absence of the BQDM program to meet the anticipated load growth in that area, Con Edison would have to construct a new distribution substation, a new switching station and substation feeders between the two,” Marco Padula, deputy director for market structure at the state’s Department of Public Service, told the commission. “This major project collectively was projected to cost approximately $1 billion.”

According to Padula, the program has provided Con Ed the flexibility to plan several infrastructure projects to be in service by summer 2019 and further delay the need for the new substation to 2026.

“Specifically, the additional solutions include the installation of capacitor banks, transformers and a 60-MW load transfer to the Glendale network,” Padula said. “With the extension, the company will have the opportunity to procure more DER that will allow it to delay the new substation and defer the need for the Glendale project and also enable possible future deferral for other traditional infrastructure projects.”

A New Normal

NYPSC demand management con ed — Rhodes | © *RTO Insider*

Newly appointed commission Chair John B. Rhodes lauded the successful concept design and Con Ed’s successful performance to date in meeting its implementation checkpoints on time and under budget.

“The BQDM program has also provided for important learning opportunities for other utilities, for stakeholders and for the commission, as non-wire alternatives have become part of New York state utilities’ standard business practices,” said Rhodes. “What was new has now become a normal.”

New York City supported the proposed extension in comments filed in April but wanted Con Ed to provide more detail on the cost-effectiveness of non-wire alternatives compared to traditional infrastructure investments. The city raised the possibility of doubling the utility’s incentives for some of the work performed under the program, specifically the Glendale project.

In response, the commission ordered that deferral of the Glendale project must be considered part of the BQDM program — and not as a separate non-wire alternative — that “shall not be eligible for further shareholder incentives beyond what has already been authorized.”

The commission also ordered Con Ed to continue filing quarterly reports and semi-annual cost-benefit analyses on the program, as well as an updated implementation and outreach plan reflecting the new realities inherent in the program’s extension.

The New York Battery & Energy Storage Technology Consortium also filed comments in support of the program, particularly its aspect of broadening the market for DER.

New York-based consultancy Peak Power, however, opposed it, as well as Con Ed’s methodology, load forecasting and auction procurement mechanism. Con Ed replied to all the parties’ comments in May and refuted Peak Power’s criticisms.

The extension order said the commission “does not agree with Peak Power’s characterization of Con Edison’s reporting on the BQDM program as being not transparent or that this proceeding lacks a record to support the company’s proposal.”

Commissioner Diane Burman alluded to criticism of the program but said that “reliability is paramount” and that it’s important to extend the program to avoid losing “the value that we see BQDM is providing.”

“We are seeing more of these [programs] from other utilities looking for similar non-wires alternatives and we’re even starting to see some non-pipes alternatives on the gas side,” Commissioner Greg Sayre added. “We make sure that each program that’s brought to us provides the benefit to ratepayers, compared to the traditional network investment, so we end up with a benefit to ratepayers, to the company and to the environment.”

Central Hudson Recovers REV Costs

The PSC also issued an order last week approving Central Hudson Gas & Electric’s deferral accounting authority and recovery of incremental costs associated with the state’s Reforming the Energy Vision (REV), which requires the state’s utilities to generate 50% of their energy from renewable resources by 2030. The commission’s order authorizes CHG&E to recover more than $1.8 million for incremental external labor costs associated with developing its distributed system implementation plan and related grid modernization efforts.

Michael Worden, DPS director of electric, gas and water, testified that the company incurred the costs as a direct result of commission orders for utilities to integrate DER into their systems and to develop interconnection portals to help facilitate DG interconnection.

“The utilities were also directed by the commission to develop hosting capacity analyses that are intended to identify more technically feasible locations on the distribution system where distributed generation projects could interconnect,” Worden said.

He pointed out that much, if not all, of the work represented in the order would have taken place through the natural process of grid modernization occurring prior to the REV proceeding.

“All of these efforts can be correlated to the increase in distributed resources that’s not only being seen in New York state, but nationally as well,” Worden said.

Burman said she understood “the need for Central Hudson to have regulatory certainty and clarity,” but she noted “that it is potentially cloudy in what it means, what is deemed reasonable and how they will be able to have cost recovery. … I don’t want this to be seen as there’s an unending pot of money for external labor.”