Page 1133 – RTO Insider

June 26, 2018

Counterflow: Pigs are not Flying

By Steve Huntoon

ICF Nuclear Energy Institute PJM — Huntoon

As you may have read, the nuclear industry is promoting a new “study” by the consultancy ICF, purporting to show that failure to bail out nuclear plants would cause widespread blackouts in the Mid-Atlantic region of PJM.^[1]

There are glaring fatal flaws. Let me offer just 10 (please email me with stuff I missed):

The Nuclear Energy Institute — not ICF — came up with the study assumptions, thus giving us the classic GIGO — garbage in, garbage out — problem. The study admits this: “NEI specified the scenarios for the analysis and the key assumptions for those scenarios” (page 1). So when you read below about all the unrealistic scenarios and assumptions, please keep in mind that they are the self-serving creations of the nuclear industry.
The study assumes that all the nuclear units (13 GW) in the PJM Mid-Atlantic region will retire if not bailed out (see App. A). No analysis supports this assumption. It is directly contradicted by PJM’s Independent Market Monitor, which has demonstrated, using NEI’s own cost data, that all these nuclear units except one cover their going-forward costs.^[2] In other words, instead of 13 GW retiring, 1 GW retires.
The study assumes that retiring nuclear capacity is not fully replaced by other capacity resources, such that PJM overall suffers a capacity reduction of 10 GW (page 36, going from 152 GW to 142 GW). No analysis supports this assumption. It is directly contradicted by experience with PJM’s capacity market, which is designed to, and does, replace retiring capacity with new, more reliable capacity. In the last capacity auction, 67 GW cleared in the PJM Mid-Atlantic region, and there were another 6 GW that offered but didn’t clear — meaning they are available at a higher price if, for example, more nuclear units were to retire (which they won’t, as discussed in #2 above).^[3]
The study assumes two gas pipeline incidents happen to occur at the same time, happen to occur during the highest winter demands in history and happen to affect only gas-fired generation (no other pipeline customers), causing the sudden loss of 13 GW of generation, and the outage persists for 60 days. Please note how absurd this scenario is: (a) two incredibly rare incidents happen at the same time; (b) during the highest winter demands in history; (c) only gas-fired generation is curtailed (despite the study’s premise that this curtailment is causing power blackouts); and (d) nothing is restored for 60 days (again, despite the study’s premise that there are blackouts). There is no legitimate basis for these wild assumptions, or for cobbling them together.
The study assumes that all demand response resources fail to perform. No analysis supports this assumption. It is simply buried in a footnote (fn. 22) questioning whether DR would perform, despite enormous penalties for failure to do so.
The study assumes that no oil inventories at dual-fuel gas generators could be restocked over a 60-day period. There is a half-hearted effort to support this assumption with statements about how difficult it might be (page 33). Given enormous penalties for failure to perform, generators would move heaven and earth to resume gas delivery and to restock oil inventories. And, of course, if oil inventory levels are problematic, adding a few more oil tanks would be an infinitesimal cost relative to the subsidies demanded by the nuclear industry.
The study assumes no gas pipeline expansion projects are built, despite the many projects underway like Transco’s Atlantic Sunrise project (1.7 Bcfd) and the PennEast Pipeline (1.1 Bcfd).^[4] The study makes an argument that increased pipeline capacity somehow doesn’t increase pipeline capacity (pages 34-35).
The study implicitly assumes zero capability to transmit electric generation from the western and southern regions of PJM into the Mid-Atlantic region. There are 4 GW of such capability in the summer, and more in the winter when circuit ratings are higher because of lower temperatures.
The study implicitly assumes PJM has no tools to mitigate a temporary generation shortfall other than customer outages. No analysis supports this assumption. In a potential emergency, PJM has tools like maximum emergency generation, load management, imports, voluntary conservation and voltage reduction.^[5]
I saved the best for last. The nuclear industry is claiming that without a bailout there will be hundreds of hours of blackouts. You would think that if this claim had a shred of credibility that customers facing this prospect would be screaming for a nuclear bailout. Instead, customers are diametrically opposed.^[6] Why? Maybe it’s #1 through 9, above.

Let me give you a realistic take on the PJM Mid-Atlantic region. Seventy-three gigawatts offered in the last capacity auction, and there is a conservative 4 GW of transfer capability from western and southern regions of PJM, for a total of 77 GW of resources. The PJM Monitor says 1 GW of nuclear is expected to retire, for 76 GW of resources. Now let’s take the totally unrealistic scenario (see #4 above) of suddenly losing 13 GW of gas-fired generation at the worst possible time. That would leave us with 63 GW, 13 GW more than ICF’s historic peak-hour demand of 50 GW depicted on Figure 6.4 of its study. And that’s before considering pipeline expansion projects, PJM’s emergency tools, etc.

ICF FERC PJM Nuclear Energy Institute — Case specifications and findings for an ICF study commissioned by the Nuclear Energy Institute. The study warns that major gas pipeline outages could result in extended blackouts in PJM if the region continues to lose nuclear generation. Columnist Steve Huntoon says the study’s assumptions are unrealistic. | *ICF, Nuclear Energy Institute*

There are plenty of things in this world to worry about. Blackouts from not bailing out nuclear plants? No, those pigs aren’t flying.

https://www.nei.org/CorporateSite/media/filefolder/resources/reports-and-briefs/icf-study-fuel-security-grid-resilience-201806.pdf. ↑
http://monitoringanalytics.com/reports/PJM_State_of_the_Market/2018/2018q1-som-pjm-sec7.pdf (page 324) (Please note that of the four plants shown as uneconomic, Oyster Creek is committed to retire and is no longer included as a potential resource, and the Davis-Besse and Perry plants are not in the PJM Mid-Atlantic region.) ↑
http://www.pjm.com/-/media/markets-ops/rpm/rpm-auction-info/2021-2022/2021-2022-base-residual-auction-report.ashx?la=en (page 15). ↑
A complete list of FERC-approved pipeline expansion projects is here, https://www.ferc.gov/industries/gas/indus-act/pipelines/approved-projects.asp. ↑
See PJM Manual 13, http://pjm.com/-/media/documents/manuals/m13.ashx. ↑
e.g., https://elcon.org/letter-congressman-greg-walden-seeking-oversight-hearing-doe-nopr-grid-resiliency-pricing/; https://states.aarp.org/dont-bamboozled-just-say-no-special-nuclear-subsidies-higher-electric-bills/; https://www.standunited.org/petition/no-nuclear-bailout-for-pennsylvania-nuclear-companies. ↑

June 26, 2018

FERC Partially OKs CAISO Commitment Cost Enhancements

By Michael Brooks

Use-limited resources will be allowed to attach opportunity cost adders to their bids in CAISO’s energy market under a proposal approved by FERC on Thursday.

The change was the only significant part of a package of Tariff changes — proposed in March in phase 3 of CAISO’s Commitment Costs Enhancements initiative — that the commission approved (ER18-1169). FERC rejected the ISO’s proposals to alter the information generators are required to submit to its Master File (a database of all resources participating in its markets and their characteristics) and to remove all ramp rates as components of daily bids.

The initiative is separate from, but related to, CAISO’s Commitment Costs and Default Energy Bid Enhancements; both involve better reflecting resources’ costs in their offers, thus improving market efficiency.

Use-limited resources are those that have limits on the number of start-ups and runtime hours, or on energy output, over a certain period. Small hydro facilities, for example, are automatically classified as use-limited resources by CAISO, while other resources must submit a request that includes certain data to be classified.

use-limited resources caiso ferc commitment costs — The 3-MW New Hogan Dam in Calaveras County, Calif. Small hydro facilities such as Hogan are automatically classified by CAISO as use-limited resources. | *U.S. Army Corps of Engineers*

But because the ISO’s market optimization software makes unit commitment decisions only one day ahead, it cannot take into account that dispatching a use-limited resource may hinder its ability to run later. As a result, the resources’ opportunity costs are not reflected in their offers.

CAISO said the changes are necessary because of the increase of variable energy resources on its system, making supply more unpredictable and use-limited resources necessary at any given time.

The opportunity cost adder that FERC approved “will capture the value of a use-limited resource’s limited availability so that the use limitation is not reached until the end of the monthly or annual use limitation period and the resource may be dispatched when it is valued most,” it said.

As part of the changes, effective Nov. 1, CAISO will all but eliminate one of the two methodologies under which use-limited resources are able to bid — the registered cost method. Under that approach, resources can elect to submit fixed commitment costs on a 30-day basis. CAISO told the commission that most use-limited resources use this method because it better reflects their opportunity costs and limitations, but because the costs are fixed, it cannot reflect variables such as the daily fluctuations of natural gas prices.

Use-limited resources will be required to use the proxy cost method, in which resources submit bids based on their start-up, minimum load and transition costs at a 125% cap. Resources less than a year old may still employ registered costs because, CAISO said, it needs a sufficient price history to calculate the adder.

“We find that the proposal is an improvement over the existing commitment cost recovery mechanism because the market optimization tool will be able to dispatch use-limited resources when they are most needed,” FERC said.

However, FERC agreed with NRG Energy’s protest of CAISO’s method for calculating opportunity costs. The commission ordered CAISO to submit within 30 days more details on its calculations as part of its Tariff revisions; the ISO had proposed to include them in its business practice manual.

The Master File

FERC rejected CAISO’s proposal to replace resources’ listed physical characteristics in the Master File with “design capability values,” information that reflects their capabilities when operating at maximum sustainable performance over a minimum run time. The ISO also proposed to allow scheduling coordinators to register “market values,” such as maximum daily start-ups, maximum daily number of transitions, operational ramp rates, operating reserve ramp rates and regulation ramp rates. CAISO said this would allow the market to consider, for example, that “a resource may be designed to start up five times a day, but starting it up more than twice a day could dramatically increase wear and tear and increase the probability of catastrophic failure.”

“We are concerned that, outside of exceptional dispatch, CAISO’s proposal does not include a mechanism to ensure that market values cannot be used to undermine the market’s economic resource dispatch when transmission constraints or other supply limitations create opportunities for the exercise of market power,” FERC said.

Using the market values instead of the design capability values may reduce available capacity, the commission said. “Permitting market participants to make less capacity available to the market raises the potential for physical withholding, which can affect dispatch and increase energy and ancillary service prices that may benefit the market participants’ affiliated resources. At times of tight supply conditions, it is more likely that withholding capacity could be a profitable action.” FERC also noted that CAISO proposed no new market mitigation measures to address this concern, and that its existing measures would be insufficient to handle the change.

Because CAISO predicated its proposal to remove ramp rates from daily bids on the changes to the Master File, FERC summarily rejected this as well. “If we were to accept the ramp rate proposal and reject the Master File proposal, scheduling coordinators would lose the flexibility currently afforded to them by the existing daily bid-in ramp rate functionality,” it said.

June 26, 2018

PJM: MISO Monitor Lacks Standing in Pseudo-tie Complaint

By Amanda Durish Cook

PJM has again moved to dismiss Potomac Economics’ complaint against its pseudo-tie construct, citing a recent court ruling that describes a limited role of RTO/ISO market monitors in legal proceedings.

Pseudo-tie MISO PJM Potomac Economics — Patton | © *RTO Insider*

MISO’s Independent Market Monitor filed a Section 206 complaint in April 2017 asking FERC to eliminate PJM’s existing pseudo-tie definition, claiming that the increasing use of pseudo-ties degrades reliability, hampers efficient dispatch and raises costs. (See Pseudo-Tie Feud Rises as Patton, NYISO Protest PJM Proposal.)

PJM is pointing to a June 15 D.C. Circuit Court of Appeals ruling that confirms FERC’s 2017 decision that Old Dominion Electric Cooperative cannot recover its operating costs incurred in excess of its filed rate during 2014’s polar vortex. The commission said such a move would constitute retroactive ratemaking (16-1111).

In its June 19 filing in the pseudo-tie complaint (EL17-62), PJM said the ODEC decision importantly included a denial of its own Independent Market Monitor’s motion to intervene. PJM said the court’s opinion shows that “a market monitor does not have standing to intervene in a proceeding on judicial review of commission orders” and that the case is “instructive” in its motion to dismiss the MISO Monitor’s complaint. PJM asked FERC to consider the precedent in its upcoming decision.

The court said that the PJM Monitor “has no legally cognizable interest” in the ODEC case and denied its motion to intervene.

The Monitor’s role, the court said, “is much in the nature of an auditor — it is largely confined to observing the market’s operations and then offering recommendations to PJM. The Monitor has no authority to enforce or to interpret the PJM [Operating] Agreement or Tariff, to direct changes in the market’s operations, to alter market rules or to police individual members’ compliance.”

The court added that “other than making some regulatory filings,” the Monitor is confined to informing FERC, other government agencies and RTO participating members “if it disagrees with PJM’s implementation of the market rules or operation of the PJM market.”

“Beyond its contractually assigned tasks, the Monitor has no independent legal interest of its own in the PJM markets,” the court determined. It characterized the PJM Monitor as “an outside observer hired to study and report objectively on the market’s operations … not a creature of statute, and operates under no affirmative duty imposed by public law.”

PJM originally asked FERC to dismiss the complaint last May on the grounds that Potomac “lacks the capacity by statute, order, contract or tariff to bring such a complaint in its role as an independent market monitor against PJM.”

June 26, 2018

CPUC Denies Pipeline, Inquires About Others

By Jason Fordney

The California Public Utilities Commission on Thursday denied a request to build a new natural gas pipeline after questioning Southern California Gas about why other major pipelines have been sitting out of service.

CPUC SDG&E SoCalGas — The CPUC denied a request by San Diego Gas & Electric and Southern California Gas to build a new pipeline | © *RTO Insider*

The commission rejected an application by San Diego Gas & Electric and SoCalGas to build a $639 million pipeline that would have stretched from Rainbow Station to Miramar, replacing the current Line 1600 built in 1949.

“The CPUC determined that the utilities’ most recent natural gas supply forecast and the CPUC’s reliability standard for gas planning do not demonstrate that there is a need for the proposed pipeline,” the commission said as it approved its proposed decision.

The commission directed SDG&E and SoCalGas to pursue other supply options for smaller amounts and for shorter periods of time than would have been provided by the proposed pipeline near San Diego. It also directed the utilities to ensure the safe continuing operation of Line 1600.

The applicants had said the sole purpose of the line was not to meet any short-term supply deficits but for emergency situations such as unplanned outages on Line 3010 or at the Moreno substation. They had also proposed derating Line 1600 from transmission service to distribution service.

The commission last week asked SoCalGas why it had not restored to service two pipelines, Line 3000 and Line 235-2. Line 3000 went out of service on July 29, 2016, and Line 235-2 ruptured and exploded on Oct. 1, 2017.

“Though such outages are to be expected periodically, the significant volumes associated with these facilities and the fact they have been out for lengthy periods during peak demand periods — nearly two years for one and over eight months for another — are causes for concern,” CPUC Energy Division Director Edward Randolph told SoCalGas President Bret Lane in a June 18 letter. Randolph questioned whether rates should be reduced if the lines are not providing benefits to ratepayers.

The Energy Division also issued a new report that cited the pipeline outages as a main reason it is recommending an increase in the allowed storage level at the Aliso Canyon facility from 24.6 Bcf to 34 Bcf. Comments on the proposal were due Monday.

Last month, the commission allowed SoCalGas to increase gas injections into Aliso Canyon but denied a request to increase the allowable capacity. (See CPUC OKs Temporary Increase in Aliso Canyon Injections.)

June 26, 2018

SPP: No Need for Joint Study with AECI in 2018

SPP staff told stakeholders last week that the RTO will not conduct a joint transmission planning study with Associated Electric Cooperative Inc. this year, saying they were unable to find any “reasonable projects on either side of line.”

spp aeci joint transmission planning study — Savoy | © *RTO Insider*

“The next shot will be in 2020,” said SPP’s Clint Savoy during a June 21 conference call of the SPP-AECI Interregional Planning Stakeholder Advisory Committee. “We will have plenty of time to get our hands around what we want to look at in the next study.”

A needs assessment along the seams identified more than 200 violations, but most were eliminated through model corrections or system adjustments, or because they were invalid contingencies. Most AECI violations were voltage issues, SPP said.

The RTO is proposing that one identified project, a 161-kV transmission line, be included in its 2018 near-term assessment.

A final report will be published at the end of July.

SPP and AECI have been performing joint studies every other year since 2010, as outlined in their joint operating agreement. Their only success was in 2016, when their study identified two projects near Springfield, Mo.: a new 345/161-kV transformer at AECI’s Morgan Substation and uprate to an existing 161-kV Morgan-to-Brookline transmission line, and installation of a new 345-kV 50-MVAR reactor at City Utilities of Springfield’s existing Brookline substation.

SPP would have been responsible for $17.1 million of the projects’ estimated $18.75 million cost, but FERC last year rejected the proposed cost allocation for both projects. The Brookline reactor project is now being addressed through the RTO’s regional planning process as part of the 2018 near-term assessment, and the Morgan transformer project is being prepared for another filing at FERC.

AECI, based in Springfield, is owned by and provides wholesale power to six regional generation and transmission cooperatives.

— Tom Kleckner

June 26, 2018

NYISO Business Issues Committee Briefs: June 20, 2018

RENSSELAER, N.Y. — NYISO power prices dropped in May but are up 37% year-to-date, Nicole Bouchez, ISO principal economist, told the Business Issues Committee on Wednesday.

Prices averaged $28.78/MWh in May, lower than $35/MWh in April and $31.74/MWh the same month a year ago.

Year-to-date monthly energy prices averaged $50.20/MWh through May, up from $36.54/MWh a year earlier. May’s average sendout was 397 GWh/day, compared with 390 GWh/day in April and 383 GWh/day a year earlier.

Transco Z6 hub natural gas prices averaged $2.55/MMBtu for the month, down 9.4% compared with last month and 8.8% year-over-year.

Distillate prices gained 6.4% compared to the previous month but were up 49.7% year-over-year. Jet Kerosene Gulf Coast and Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $15.96/MMBtu and $15.92/MMBtu, respectively.

nyiso fixed price transmission congestion contracts — | *NYISO*

Total uplift costs and uplift per megawatt-hour rose from April with the ISO’s local reliability share 22 cents/MWh in May, up from 12 cents/MWh the previous month, while the statewide share climbed from -57 cents/MWh to -17 cents/MWh.

ISO Reviewing Rules on PJM Imports

Reviewing the Broader Regional Markets report, Bouchez described the ISO’s work on item 26, an effort to clarify the minimum deliverability requirements for capacity from PJM, the subject of three joint meetings of the Installed Capacity (ICAP) Working Group and Market Issues Working Group since February.

The ISO has prepared a detailed overview of the supplemental resource evaluation (SRE) process for external resources, the existing nonperformance penalties for external ICAP suppliers, and a draft proposal regarding SRE process improvements for external capacity resources.

Bouchez also reviewed item 28, a complaint filed with FERC in December by the New Jersey Board of Public Utilities challenging PJM’s and NYISO’s implementation of the mutual benefits provisions of their joint operating agreement and requesting amendments to the JOA.

FERC rejected the complaint on May 24 (EL18-54). The commission found that because the Bergen-Linden Corridor Project was planned by PJM, and without a voluntary commitment to share cost responsibility by NYISO, “it is just and reasonable for the costs of the project to be allocated solely within PJM.” (See PSE&G on the Hook for Bergen-Linden Costs.)

Proposal to Extend TCCs Advances

The BIC voted to recommend that the Management Committee approve Tariff revisions to provide extensions of historic fixed-price transmission congestion contracts (HFPTCCs), following a presentation by Gregory R. Williams, manager for TCC market operations.

FERC Order 681 requires that long-term firm transmission rights be made available to allow load-serving entities to support long-term power supply arrangements.

The HFPTCCs initiated by NYISO in 2008 allow LSEs to obtain such contracts for up to 10 years, with some service grandfathered for up to 12 years; 1,748 MW of HFPTCCs are currently active. Those offered in 2008 are now approaching the end of their 10-year term and will expire after Oct. 31.

As part of developing the HFPTCCs, the ISO had committed to explore an option to renew the contracts after the initial term.

Contract extensions would be made available to LSEs that convert existing transmission agreements to HFPTCCs and continued to purchase them throughout the entire 10- or 12-year term.

The ISO is required to make all transmission capacity not used to support existing TCCs available for sale in its centralized TCC auctions. The bidding and offering period for the first round of the fall 2018 centralized TCC auction is expected to begin in mid-August.

Assuming the current proposal is accepted by FERC, the ISO would need to seek a waiver for permission to reserve 256 MW of transmission capacity from the upcoming auction to support the potential award of HFPTCC extensions that would begin on Nov. 1, 2018, and ensure feasibility issues do not arise from offering such extensions to qualifying LSEs.

— Michael Kuser

June 26, 2018

CORRECTED: FERC Seeks More Info on CPV Plant’s Ownership

By Rory D. Sweeney

Competitive Power Ventures must provide additional information to prove it adequately mitigated market power to continue making market-based sales at its newly opened Towantic Energy Center, FERC ruled Thursday (ER13-343-008, et al.).

FERC’s ruling came in response to CPV’s triennial market power update, which it filed on June 30, 2017, for Towantic, a 785-MW generator in Oxford, Ct., and three other gas-fired plants in CPV’s Northeast region.

CPV FERC pension funds — CPV Towantic Energy Center in early May, with construction nearly complete. | *CPV*

The commission’s market-based rate rules require applicants to provide information regarding affiliates and upstream ownership. It considers as affiliates any entity that owns at least 10% of the outstanding voting securities of the applicant.

Two pension funds indirectly own more than 10% of Towantic, but CPV argued that they are only allowed to vote 9% of their shares in an upstream entity. FERC said that doesn’t account for their entire ownership.

“Because the pension funds are included among the stockholders whose votes determine how the votes of the excess shares will be allocated, the sum of votes by the pension funds of their 9% of the shares plus the proportional vote of their excess shares gives the pension funds an effective vote greater than 10%,” the commission said.

It instructed the applicants to update their horizontal and vertical market power analysis with their affiliates’ generation and transmission assets and inputs to electric power production. FERC gave them 30 days to comply.

The updated market power analysis included Towantic and the 680-MW CPV Valley in Wawayanda, N.Y., both of which began operating this year and were granted market-based rate authority (MBRA) in March 2016 (ER16-700, ER16-701). (See CPV: Subsidies, not Gas Fears, Challenge for New Plants.)

The other plants are the 725-MW CPV Woodbridge Energy Center in Keasbey, N.J., and the 725-MW CPV St. Charles Energy Center in Waldorf, Md., which were granted MBRA in February 2013 (ER13-342, ER13-343).

[Editor’s Note: An earlier version of this story incorrectly stated that FERC was questioning the ownership of all four CPV plants and that they did not already have MBRA.]

June 26, 2018January 24, 2024

FERC Broadens Challenge to TOs’ Tax Calculations

By Amanda Durish Cook

FERC on Thursday identified 13 additional transmission owners it said should change accounting practices that could inflate rates by underestimating tax credits.

The commission ordered a Section 206 proceeding investigating the companies’ use of a double averaging formula to calculate accumulated deferred income taxes (ADIT) (EL18-155, et al.). The utilities include two Ameren subsidiaries, American Transmission Co., GridLiance West Transco, ITC Midwest, Northern States Power, Public Service Company of Colorado, Southern California Edison, TransCanyon DCR, Southwestern Public Service and Virginia Electric and Power Co.

In April, FERC opened a similar investigation of five MISO TOs after rejecting proposed formula rate template revisions that would have applied the two-step averaging methodology in annual true-up calculations of ADIT balances.

The commission signaled it would probe whether the practice makes deferred income tax credits appear lower than they should be, possibly raising rates (ER18-224, EL18-138). The filers were ALLETE, Montana-Dakota Utilities, Northern Indiana Public Service Co., Otter Tail Power and Southern Indiana Gas and Electric Co.

The commission said that the TOs’ practice of averaging the prorated ADIT value for the year with the beginning-of-year ADIT balance “produces a result that is disproportionately skewed towards the beginning-of-year balance.”

“Because most companies tend to continuously make investments in plant[s], which in turn generates ADIT, plant and ADIT balances typically increase throughout the year,” the commission said.

MISO TOs Offer New Formula

On June 4, the five MISO TOs submitted revisions to remove the proposed double averaging and instead apply the IRS’ proration methodology in calculating the annual transmission formula rate true-up.

In last week’s order, FERC suggested that the 13 newly identified utilities would need to similarly revise their rates.

“Upon initial review, the concerns we identify might be addressed by revising respondents’ transmission formula rates to eliminate the use of the two-step averaging methodology to determine ADIT balances,” FERC said. “In particular, respondents could modify their transmission formula rates to apply the first step of the two-step averaging methodology to generate a prorated ADIT value for the year, without taking the second step of averaging the prorated value for the year with the beginning-of-year balance.”

Change of Heart

FERC noted that, in previous proceedings, it had allowed TOs to use the two-step methodology “based on the understanding that this methodology was necessary to comply” with the IRS’ normalization rules, an accounting system the Department of Treasury uses for regulated public utilities to reconcile accelerated depreciation of their public utility assets or investment tax credits with regulatory treatment.

However, FERC said in April that its opinion on the matter has since changed, guided by private letter rulings from the IRS. FERC said it now interprets updated IRS rules to “not require that any averaging convention applied to other elements of rate base also apply to taxpayer’s prorated [ADIT] balance.”

“We conclude that if the IRS’ proration methodology is applied to calculate ADIT balances in forward-looking formula rates — such as the Attachment O formula rate templates of certain MISO TOs — then the additional averaging step need not also be applied in order to comply,” FERC said.

June 26, 2018

NYISO BIC Backs AC Tx Projects; Losing Bidders Protest

By Michael Kuser

RENSSELAER, N.Y. — NYISO stakeholders last week backed joint proposals by North America Transmission (NAT) and the New York Power Authority to build two 345-kV transmission projects while several losing bidders cried foul.

In an advisory vote, the Business Issues Committee urged the Management Committee on Wednesday to recommend the Board of Directors approve the ISO’s draft AC Transmission Public Policy Transmission Planning Report. Dawei Fan, manager for public policy and interregional planning, said the report contains analysis of seven proposals to address persistent transmission congestion at the Central East (Segment A) electrical interface and six proposals for the Upstate New York/Southeast New York (UPNY/SENY, or Segment B) interface.

NYISO BIC North American Transmission NYPA — NYISO staff analyzed seven proposals to address persistent transmission congestion at the Central East (Segment A) electrical interface, and six proposals for the Upstate New York/Southeast New York (UPNY/SENY, or Segment B) interface. | *NY PSC*

Advised by consultant Substation Engineering Co. (SECO), ISO staff recommended two 345-kV transmission projects proposed jointly by NAT and NYPA. The BIC voted 76.33% in favor of the report and its recommendations.

Project T027 is a double-circuit 345-kV line from Edic to New Scotland for Segment A. Project T029 for Segment B is a standard 345-kV line from Knickerbocker to Pleasant Valley.

NYISO’s analysis was driven by a December 2015 order by the New York Public Service Commission on “Finding Transmission Needs Driven by Public Policy Requirements.”

T027 had higher costs than other Segment A proposals, but staff determined them warranted by benefits provided by the double-circuit design, including “significant increase in Central East voltage transfer capability, increased production cost savings, and excellent operability and expandability.”

T029 provides similar transfer incremental and production cost savings with the second-lowest cost, and demonstrates excellent operability, staff said. More important, the report said, “T029 poses the lowest siting risk due to the low structure height increase and more than 50% of its new structures with reduced height.”

Staff also said that T027 and T029 would result in cost savings when being built by the same developer simultaneously.

The ISO estimated T027 will cost $577 million to $750 million, the higher figure including a 30% contingency. T029 is estimated at $324 million to $422 million. Staff projected the in-service date for the selected projects in April 2023, “assuming the developer will start the Article VII preparation immediately following the approval of this report by the NYISO board.”

Challenges to Planning Process

Stakeholders abstaining or opposing the motion June 20 included utilities, transmission owners and other developers whose proposals were not selected for recommendation. Several of them submitted comments to the BIC or read statements.

John Borchert, senior director of energy policy and transmission development for Central Hudson Gas & Electric, which abstained, said his company wanted the benefits of improved transmission capability for its service area but was “dissatisfied with the NYISO’s work and its project evaluation.”

He said “the lack of transparency, the way that the aspects of the projects were treated during the evaluation, effectively disqualified projects, and the way that the local TO upgrades were handled during the process have led to frustration and confusion for both those developing projects and for those interconnecting transmission owners.”

Consolidated Edison and its subsidiary Orange and Rockland Utilities voted against the motion, and O&R submitted written comments.

“We don’t feel confident that the recommended selection for Segment B is in the customer’s best interest due to a lack of transparency in the selection process, and deficiencies in evaluation,” said Jane Quin, director of Con Ed’s energy markets policy group. “We are concerned that … NYISO has not considered the full costs associated with the proposed Middletown upgrades, which are local upgrades on the Orange and Rockland system … and could cost as much as 20% of the Segment B project cost.”

The ISO “failed to make clear the technologies and project attributes it would or would not consider, and the reasons for such decisions, and it did not consider stakeholder input on the matter,” Quin said.

Fan responded that the Middletown transformer “is just one of the distinguishing factors for Segment B projects … [for which] the major drivers are the magnitude of the power delivery and the structure design.” He said SECO had included $16 million for the Middletown transformer costs, which it deemed adequate.

Fan said the ISO had already had two meetings with developers and six meetings with the Electric System Planning Working Group and Transmission Planning Advisory Subcommittee to consider comments from stakeholders.

Looking for Fatal Flaws

Zach Smith, NYISO vice president for system and resource planning, noted that “any project recommended for selection does go through our interconnection process … there has been a system impact study that’s been done that’s up at [the Operations Committee] tomorrow for consideration.”

The next step after that is a facilities study, and “what’s key here to our evaluation is to understand whether there are any fatal flaws in our assessment,” Smith said.

Borchert said, “There was no reason why an interconnecting transmission owner should not be consulted if these solutions are talking about equipment that’s going to be installed in their service territory. And the process needs to be done if it’s part of the overall selection and it has an impact on the selection, and it needs to be done prior to the selection being made.”

Carl Patka, the ISO’s assistant general counsel, said, “When we designed the overall planning process, we did not require, and FERC did not approve requiring, a complete interconnection-level analysis for proposed projects. That was proposed during the Order 1000 process, it was proposed during the stakeholder process, and it was rejected. And the reason for that is people did not want to create a barrier to entry and proposal of new projects based upon information that competing developers could not have from the incumbent utility.”

Brian Duncan of NextEra Energy Transmission NY (NEETNY) made a presentation arguing that NYISO was picking winners for a $1 billion project “despite a virtual tie on project benefits” among competing projects, which included NEETNY’s T022 in Segment B.

The ISO “did not provide analysis on cost-contained pricing … and three other project combinations that are virtually identical, provide all the quantifiable and quantitative benefits [and] are within 1 to 5% of the cost estimate using SECO’s numbers,” Duncan said. He also questioned why NYISO made tower height a big issue in its selection when its solicitation made no mention of the factor.

Patka said the PSC order did not mandate the ISO to use cost-contained pricing but required developers to provide two sets of costs, “one based on raw construction costs and one on 80%/20% cost overrun/cost underrun language. … They said they hoped that FERC will adopt cost containment when they address the rate issue, but their words were exactly, ‘The NYISO should evaluate the costs based on raw construction costs.’”

Patka also said that tower heights were considered by NYISO as a risk of project delay and to project completion, as visual impact is a key environmental impact of transmission, and that the ISO had reviewed its analysis with New York Department of Public Service staff.

Duncan also took issue with the concrete pole installation cost estimates, saying that SECO used a metric of dollars per pound on the weight of the pole rather than a more logical figure of total costs, including labor. He also said the ISO’s estimate of 5% in synergy savings on the combined projects by one developer was “overstated.”

“If those issues are addressed, project T022 would be the lowest-cost project by millions of dollars, probably tens of millions of dollars,” Duncan said.

SECO Vice President Joe Allen said he agreed “there would be no synergy” between the two upgrades.

Smith said NYISO could “take that back, but it won’t affect the ranking at all.”

Kathleen Carrigan, New York Transco general counsel, read comments the company jointly submitted with National Grid.

The two companies submitted proposal T019 for Segment B, including “a basic controllable series compensation element to preserve the proposed 345-kV transmission line physical designs that the commission deemed the most environmentally and siting friendly in the underlying AC transmission proceedings.”

Carrigan said series compensation technology is widely used across the U.S., and she submitted a study showing no detrimental system impacts from it. NYISO and SECO “considered proposal T019 as too risky due to the inclusion of the series compensation, despite no technical analysis in support of their conclusion,” she said.

Smith said that while the ISO does not oppose the use of series compensation as a technology, it did see potential problems with its application in the National Grid/NY Transco project. In a FAQ document posted with the BIC meeting materials, the ISO cited potential subsynchronous resonance and damage to generators as the major risk of series compensation technology.

Carrigan said NYISO’s own metrics show the National Grid/NY Transco proposal paired with T029 produces consistently better performance results than the ISO’s favored project.

For example, when combined, T027 and T019 increase voltage transfer across Central East by 875 MW and UPNY/SENY by 2,100 MW. “This is a far greater increase than the combination of T027 and T029, which only increases transfer capability along Central East by 825 MW and UPNY/SENY by 1,325,” she told RTO Insider after the meeting.

“Projects T027 + T019 have the highest Central East N-1-1 voltage transfer capability of any studied project combination and far surpass combination T027 and T029 with respect to the incremental UPNY/SENY N-1-1 thermal transfer capability. The baseline 20-year incremental energy produced by projects T027 and T019 nearly doubles that of projects T027 and T029 (40,089 GWh vs. 27,524 GWh); and finally, T027 and T019 produce the highest production cost savings than any other Segment B combination,” Carrigan said.

June 26, 2018

Monitor Garza Offers Glimpse of ERCOT in 2018

By Tom Kleckner

HOUSTON — While sharing her organization’s report on the state of the ERCOT market in 2017 last week, Potomac Economics’ Beth Garza was naturally asked her forecast of this summer’s energy prices.

ercot market monitor beth garza — Garza | © *RTO Insider*

“My title is not market predictor. It’s market monitor,” Garza, director of ERCOT’s Independent Market Monitor, reminded her luncheon audience June 21. “I get to watch and opine. I’m sorry to disappoint you.”

Speaking to those gathered at the Gulf Coast Power Association’s lunch in Houston, Garza shared highlights from the State of the Market report. Energy insiders listened attentively as she reviewed 2017 data — and even more so on the rare occasions Garza looked ahead to 2018.

Garza said reserve margins will be tighter this summer than last year, primarily because of the retirement of 4.2 GW of coal generation over the last 12 months. That dropped ERCOT’s planning reserve margin from 18.9% to 9.3% — since increased to 11% — and raised fears of potential shortages during a long, hot summer. (See ERCOT Gains Additional Capacity to Meet Summer Demand.) On Friday, as the system flirted with June’s demand record of 67.8 GW, the ISO still had more than 3.5 GW of operating reserves.

“We had an interesting test of the system in May,” Garza said, referring to the multiple demand records ERCOT set for the month in the face of above-normal temperatures. “But as others have said, a hot May does not necessarily portend a hot summer.”

Statewide temperatures have dropped since then, thanks to recent torrential rains. That has also dampened forward prices, which have settled at about $150/MWh after soaring above $250/MWh in May.

“Is that a reaction to the rain and the temperatures?” Garza asked. “We got through May, but the rest of June has not been severe.”

Garza allowed herself some prognostication in addressing the forward prices.

“I can look at future prices and infer an estimate of how many hours of real-time prices at the 9,000/MWh cap we’ll see,” she said, noting ERCOT saw only 3.5 hours of prices above $1,000/MWh last year. Garza recalled a straw poll of attendees at the recent GCPA spring conference, with expectations of five to 10 hours at the $9,000/MWh cap this year.

“That’s what the future pricing seems to indicate, but that’s based on a $200 price. I haven’t done the math on $150 prices,” Garza said. “If we have 2 GW of wind generation on peak, it’ll be a high-priced day. If we have 10 GW of wind generation on peak, it’ll be a moderately priced day.”

Garza also put in a plug for the addition of real-time co-optimization in the market, one of six recommendations the Monitor has made in each of its last few reports and one of several market improvements being considered by the Public Utility Commission of Texas. (See “Monitor Says Wholesale Market ‘Performed Competitively’ in 2017,” ERCOT Briefs.)

“It’s the key missing link in our market,” she said. “Our market is dependent on pricing during significant scarcity intervals. My fear is that as we get to where we see tight reserve margins, the likelihood of scarcity events and high prices increase, because of the ineffective allocation of reserves. If they were allocated differently [through real-time co-optimization], we wouldn’t see those high prices.”