Trial staff at the Federal Energy Regulatory Commission has recommended approval of a settlement that would reduce transmission owner Niagara Mohawk Power’s return on equity to 10.03% from the current 11.5%.
Niagara Mohawk, a unit of National Grid, reached the agreement with the Municipal Electric Utilities Association of New York, the New York Association of Public Power and the Allegheny Electric Cooperative.
NYISO last week defended its proposed redesign of voltage support compensation, telling the Federal Energy Regulatory Commission it should reject calls by generators for additional inflation adjustments (ER15-1042).
On Feb. 13, NYISO proposed paying voltage support service (VSS) providers $2,592/MVAr for both leading and lagging capability, with annual increases based on the consumer price index (CPI). MVAr is the unit of measurement for reactive power capability.
The current rate is $3,919/MVAr annually based on lagging reactive power capability alone. Although the new rate is lower, the inclusion of both leading and lagging capabilities in the calculation is expected to result in total compensation about equal in the first year to how it has been in past years.
The proposal, the result of more than a year of discussions, won support of almost 80% of stakeholders, including more than half of the generation owners that voted, at the Nov. 20, 2014, Management Committee meeting, the ISO said.
On March 6, however, the Independent Power Producers of New York and Dynegy Marketing and Trade filed separate protests asking FERC to order the ISO to increase the compensation rate to reflect inflation since the existing rate was set in 2002.
IPPNY said it agrees with the ISO in using the CPI to escalate future payments. “If this reasoning serves to justify the use of the CPI to track inflation of costs from this point forward, the commission should apply the same reasoning retroactively to the escalation of costs over the last decade,” the group said.
NYISO said the proposal to include an inflation adjustment in the compensation proposal “was one of the most contentious issues addressed in the stakeholder process.” The ISO’s initial proposal in September 2013 did not include any escalation for past or future inflation. The ISO added a going-forward inflator to its revised proposal to stakeholders in December 2013.
“Although a majority of stakeholders supported increasing the annual VSS compensation rate, they considered, and rejected, a proposal to escalate the proposed starting point for the 2014 VSS compensation rate by applying the annual CPI for each year from 2002 through the present,” the ISO told FERC. “Neither did any NYISO market participant present any evidence during the stakeholder process to indicate that the existing compensation rate, as approved in 2002, was unreasonably low.”
NYISO said it proposed the compensation changes due to the increased need for leading reactive power support. Since 2010, the number of requests for leading reactive power support has increased due to higher off-peak transmission voltages, the ISO said. More than 90% of the ISO’s reactive power support requests since 2010 have been for leading reactive power; before 2010, more than 90% of the requests were for lagging reactive power support.
Generation owners will be exempted from federal open access transmission rules, allowing them to reserve excess capacity on their tie lines for the first five years of operation, under an order approved by regulators last week.
The Federal Energy Regulatory Commission, which has been studying the issue since a 2011 technical conference, said it will grant a blanket waiver from Open Access Transmission Tariff (OATT) requirements for “interconnection customer’s interconnection facilities,” or tie lines (RM14-11).
Under previous policy, a tie line owner must make excess capacity available to third parties unless it can justify its planned future use of the line. The new rule creates a five-year “safe harbor” period during which a tie line owner is assumed to have plans to use the excess capacity on its facilities.
The order eliminates the need for generation owners to seek OATT waivers, a requirement that the commission said created an undue burden. “While the commission has processed scores of requests for transmission tariff waivers in recent years, a third party has requested service, and thus required the interconnection customer to file a tariff, in only four instances total,” commission staff said in a presentation on the new rule.
Third parties seeking to obtain access to tie lines can do so through the procedures applicable to requests for interconnection and transmission service under sections 210, 211 and 212 of the Federal Power Act, which allow tie line owners to negotiate access with third parties.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:30)
Members will be asked to endorse the following manual changes:
A. Manual 11: Energy & Ancillary Services Market Operations — Adds a method for screening of demand bids by load-serving entities. Bids would be limited to the LSE’s calculated zonal peak demand reference point for the day plus whichever value is more, 30% of the reference point or 10 MW. PJM said the need for such limits was illustrated by the default of a retail provider in January 2014. Due to an input error, the company entered a demand bid about 100 times the retailer’s actual load. (See MIC Briefs.)
PJM requires resources to provide symmetrical regulation from their set points.
B. Manual 12: Balancing Operations — Revisions describe the required regulation range, specifying that resources are required to symmetrically provide the total amount of regulation assigned. The changes also detail how performance evaluations are conducted and further define the basepoint around which the resource will be regulating.
3. FTR REVISIONS (9:30-9:45)
Members will be asked to approve non-substantive revisions regarding financial transmission rights. The changes concern clearing deadlines, bilateral trades and Tariff references.
4. ENERGY MARKET UPLIFT SR. TASK FORCE (9:45-10:15)
Members will be asked to endorse revisions to rules regarding treatment of combustion turbine lost opportunity costs and a proposal that uplift be treated as an input to the Regional Transmission Expansion Plan. Under the new CT rules, PJM would use the generator’s energy schedule to calculate opportunity costs except for self-scheduled units, for which the lesser of the available cost- or price-based curves would apply.
5. DEMAND RESPONSE Forecast for Use in RTEP (10:15-10:30)
Members will be asked to OK a proposed change to demand response modeling assumptions used in load deliverability analyses. The new method would use the average of the last three years of committed DR for each zone. (See Change Proposed in PJM Demand Response Modeling.)
6. FERC Order 1000 (10:30-10:45)
Members will be asked to endorse a $30,000 non-refundable fee for studying proposed transmission improvements with estimated costs of $20 million or more. The fee would apply to both greenfield projects and upgrades by incumbent transmission operators. The Federal Energy Regulatory Commission last month rejected an earlier proposal to exempt transmission upgrades from the study fee. (See FERC Rejects Fee on Greenfield Transmission Projects.)
Members Committee
CONSENT AGENDA (1:20-1:25)
B. Members will be asked to approve Tariff and Operating Agreement revisions to implement Coordinated Transaction Scheduling (CTS) with MISO. The objective is to improve interchange scheduling efficiency by aligning energy scheduling with interface prices and adding the option for market participants to schedule energy transactions using an interface bid. (See PJM, MISO Reach Agreement on New Interchange Product.)
ENDORSEMENTS (1:25-1:40)
1. FERC Order 1000: See MRC agenda item #6, above.
WASHINGTON — Natural gas demand and production both set records in 2014, while gas trading declined for the fourth straight year, the Federal Energy Regulatory Commission reported last week.
Natural gas developments dominated FERC’s annual State of the Markets presentation in a year that also saw higher electric prices.
Demand and Production
The coldest winter in more than a decade helped push natural gas demand to a record 70.7 Bcf/d, with residential and commercial demand up 3% and industrial demand increasing 2%. The record came despite a cooler-than-normal summer, which resulted in a 3% decline in gas demand for electricity generation.
Natural gas production grew 5% to an average of 68.4 Bcf/d, breaking the previous record from 2013. The Marcellus shale formation in Pennsylvania and the Eagle Ford shale play in Texas were responsible for more than one-third of the production increase.
Despite the crash in crude oil prices — from $115 per barrel in mid-June to $53 at the end of December — natural gas production has remained above 71 Bcf/d in 2015, above levels for the same time last year.
Following last winter, the U.S. had only 822 Bcf of natural gas in storage, the lowest level since 2003. But a record injection totaling almost 2.8 Tcf — almost 10% above the previous high — returned storage levels to 3,611 Bcf by Nov. 1, only 5% less than the five-year average.
New Pipelines
Almost 4 Bcf/d of new pipeline capacity entered service in the Marcellus and Utica shale regions in 2014, including 1.5 Bcf/d in gathering lines and about 2.5 Bcf/d to serve Northeast demand. Still, a lack of pipeline capacity resulted in prices below $2/MMBtu in parts of the Marcellus region. Future pipeline expansions are planned to deliver Northeast gas to markets in eastern Canada, the Midwest, the Southeast and the Gulf Coast.
The summer of 2014 resulted in several firsts, with the Northeast becoming a net gas exporter and New York and Boston recording gas prices below Henry Hub.
The commission said forward price curves indicate that natural gas, rather than coal, will be on the margin for the balance of 2015, as it was in 2012. That, commission staff said, could result in coal-fired generation displacing some gas generation this summer. “If oil prices remain at current levels, we could continue to see increased use of oil for power generation,” the commission added.
Gas and Renewables Continue to Displace Coal
The U.S. added 10.8 GW of electric generating capacity in 2014, after showing a net loss of 3 GW in 2013 due largely to coal and nuclear retirements.
Natural gas capacity rose by 7.7 GW, while wind capacity grew by 5 GW. Solar added almost 4 GW.
Financial Trading
RTOs increased their dominance of financial trading with 96% of electricity products traded outside ERCOT occurring at an RTO hub, up from 92% in 2013. Only NYISO and PJM saw increases in trading volumes for the year, with PJM increasing its market share to 73% of trading on Intercontinental Exchange, an increase from 68% in 2013.
Natural gas trading volumes on ICE dropped by more than one-quarter in 2014, the fourth decline in a row. “Less volatile prices hurt speculative trading profits; this caused companies, particularly large banks, to reduce or eliminate their trading exposure,” the commission said.
Electricity Prices
Despite essentially no increase in electricity demand, average spot prices rose across the country last year, largely due to high prices in the first quarter. The largest increase was in PJM, where average on-peak day-ahead prices at the Western Hub rose 38% to $63/MWh.
New York regulators last week delayed action on a financial lifeline for the R.E. Ginna nuclear plant in order to review its impact on ratepayers.
The approximately $200 million annual price tag for the reliability support services agreement prompted the New York Public Service Commission to open an inquiry, with initial filings due April 15 (14-E-0270).
The PSC’s March 18 order defers action on Rochester Gas & Electric’s request for approval of the agreement through July 29.
The RSSA, which is also pending before the Federal Energy Regulatory Commission, was supposed to be effective April 1. If approved, the agreement would be retroactive to April 1 and last until the end of September 2018.
RG&E and Exelon’s Constellation Energy Nuclear Group were ordered by the PSC to enter the agreement because the plant is deemed necessary to maintain system reliability in western New York until a transmission project goes online in late 2018.
RG&E has estimated that under the agreement, an average residential customer would see bills rise about 4.2%, while costs for large primary customers would increase 6%.
Interveners representing competitive suppliers, residential ratepayers and environmentalists have complained about the RSSA’s steep price, with industry and other large customers challenging RG&E’s estimates before FERC. (See New York Industrials Want Ginna Deal Tossed.)
“RG&E worked diligently in the best interests of our customers to reach an agreement with Ginna, recognizing the importance of ensuring reliable service on reasonable terms for all parties,” said Dan Hucko, a spokesman for RG&E.
“Given the important role of the proposed reliability support services agreement, we are working collaboratively with the PSC to accommodate the needed regulatory reviews in a timely fashion,” Exelon spokeswoman Maria Hudson said.
Connecticut’s Department of Energy and Environmental Protection issued its integrated resource plan last week, warning of natural gas pipeline constraints and stiffer competition for renewable resources.
Although energy efficiency is expected to flatten load growth, the blueprint for the 10-year period through 2024 predicts the New England region will need new resources to offset the retirement of more than 3,000 MW of generation.
Three new Connecticut generators cleared in ISO-NE’s Forward Capacity Auction for 2018-2019 in February: a 725-MW combined-cycle plant in Oxford and two 45-MW combustion turbines in Wallingford. (See Exelon, LS Power Join CPV in Adding New England Capacity.)
The outcome of the capacity auction, which ISO-NE officials hailed as a success for their new Pay-for-Performance rules, had been uncertain when Connecticut issued a draft of the IRP in December. (See Connecticut: Power Prices to Rise 63% by 2024.)
The IRP advocates a regional approach to expand natural gas infrastructure. DEEP says that at least 1 Bcf/d of natural gas transportation capacity or equivalent gas storage is needed for at least 30 days during the winter.
The final IRP also noted a tightening in the availability of renewable power, saying that as neighboring states try to reach their renewable energy goals, competition for the limited supply could cause a shortage by 2017.
Connecticut, Massachusetts and Rhode Island are joining together to procure new Class I Renewable Energy projects: wind, solar, small hydro, biomass and fuel cells of at least 20 MW and large-scale hydropower projects constructed after Jan. 1, 2003. (See New England States Combine on Clean Energy Procurement.)
The Federal Energy Regulatory Commission last week left intact most of its 2010 order meant to mitigate market power in the installed capacity market in New York City.
However, it clarified the previous order’s consideration of demand response programs that may benefit from state policies or subsidies.
The order accepted NYISO’s compliance filing with the exception of its proposal to grant a blanket exemption from offer floor calculations for all payments and other benefits to special case resources (SCR) under state programs. An SCR is a demand-side resource that participates as a supplier in NYISO’s capacity market.
“We clarify that our May 20, 2010, order did not intend for NYISO to rule on the legitimacy of particular state programs. However, neither did we intend to grant a blanket exemption for all state programs that subsidize demand response,” FERC wrote.
The order removes a requirement in the 2010 ruling that NYISO provide a list of criteria governing which payments are included in offer floor calculations. Instead, the commission will decide petitions for exemptions on a case-by-case basis.
The order granted rehearing on whether payments under Consolidated Edison’s distribution load relief program and the New York State Energy Research and Development Authority rebate program should be excluded from the SCR offer floor.
That shift resulted in a partial dissent from Commissioner Norman Bay.
“The commission announced five years ago that it did not intend ‘to interfere with state programs that further specific legitimate policy goals.’ Yet that is precisely what the majority does today by declaring the ConEd and NYSERDA programs to be presumptively improper exercises of market power,” Bay wrote.
The order denied rehearing on a challenge to the demand curve price used for calculating the default offer floor.
The Federal Energy Regulatory Commission last week rejected SPP’s proposal that the RTO review the information that transmission owners include in their initial revenue requirement filings after joining the RTO (ER15-859).
SPP filed the proposal with FERC in January as a result of a 2014 settlement reached with Southwestern Public Service Co. in a dispute over whether the transmission facilities of Tri-County Electric Cooperative were eligible to be included in SPP transmission rates (EL13-15, EL13-35).
SPP said the review process, which was unanimously approved by the SPP Members Committee, was intended to identify issues that might result in challenges to the initial rate filings. The RTO said it would have no authority to prevent a transmission owner from overriding SPP’s concerns in its filing with FERC.
The Missouri Joint Municipal Electric Utility Commission, the Kansas Power Pool and South Central MCN, a competitive transmission company that plans to partner with electric cooperatives and municipal utilities in SPP, filed protests in February.
The commission said the proposed review process, which could take as long as six months after a new transmission owner’s execution of the SPP membership agreement, was unreasonable.
“We agree with protesters that SPP’s proposed six-month review process could unjustly and unreasonably impair a new transmission owner’s ability to recover its costs,” the commission said.
The commission said it recognized that SPP was attempting to create a consensus solution based on the 2014 settlement. “However, we find that the review process SPP proposes to mandate here could unjustly and unreasonably impair a new transmission owner’s ability to recover its costs for transmission service it provides under the SPP Tariff.”
Faulted by some stakeholders for not approving cross-border transmission projects under terms of their joint operating agreement, MISO and PJM have identified what lower-voltage flowgate projects could be done quickly and cheaply on their own sides of the seam.
The RTOs have jointly identified more than two dozen flowgate projects that could relieve market-to-market congestion.
The list of upgrades includes at least 14 projects totaling more than $45 million on the PJM side and 12 totaling $59.5 million on the MISO side.
Eric Laverty, MISO’s director of sub-regional planning, told his RTO’s Planning Advisory Committee on March 18 that the projects were not identified as the result of complicated modeling but through simple analysis of congestion history during 2013 and 2014.
Flowgates that showed significant day-ahead and balancing congestion in 2013 and 2014, and M2M flowgates that caused auction revenue rights infeasibilities, were included. Solutions had to be completed and provide a payback on investment quickly. Greenfield projects were not considered.
“We didn’t run these through a full set of futures for market efficiency-type analysis,” Laverty said, sharing information from a recent PJM/MISO Interregional Planning Stakeholder Advisory Committee.
“Here’s the cost. Here’s what the congestion has been over the past couple years. Does this [upgrade] make sense?”
PJM engineers have been using production cost simulations to study issues on their side of the seam. Both RTOs modeled special transfer conditions, such as those resulting from high wind production and increased Michigan imports.
Smaller ‘Quick Hits’
(Click to zoom.)
Laverty said the upgrades didn’t amount to high-dollar projects, with the largest potential MISO project an $11.9 million upgrade at the Burnham-Sheffield 345-kV flowgate.
Also, “they’re not rising to a reliability project yet,” he said, but could grow more costly over time.
George Dawe, vice president of Duke-American Transmission Co., asked if the upgrades would be eligible for competitive solicitations if they were delayed and became reliability projects. Laverty said no. Later, referring to a potential southwest Michigan project, he added, “We don’t know yet.”
For now, PJM and MISO need “to get a pulse” of transmission owners to see if they have an appetite for making improvements. “It’s a matter of building the business case for these projects,” Laverty said.
These “quick hit” projects will be the subject of additional review at the April IPSAC meeting, with conclusions and recommendations likely in May.
The extent to which the projects improve conditions for utilities on the seams is yet to be seen.
Last December, Northern Indiana Public Service Co., a MISO member flanked by PJM in eastern Indiana and Illinois to the west, complained to the Federal Energy Regulatory Commission that the RTOs haven’t approved a single cross-border transmission upgrade project under the JOA (EL13-88). FERC ordered a technical conference on the issue.
Market Congestion Projects
MISO’s Planning Advisory Committee also received an update Wednesday on potential “high-benefits-to-cost” solutions involving 14 congested flowgates in four areas: southern Indiana, southern Illinois, northern Indiana/southeast Wisconsin and Iowa/Minnesota.
Seventeen transmission developers submitted 45 solutions, including 10 carried over from the 2014 market congestion planning study. Twelve of the 45 proposals passed the benefit-cost threshold.
The projects identified in southern Illinois and southern Indiana show particular promise as “those two areas have been hammered by congestion,” said Digaunto Chatterjee, senior manager of economic studies.
Chatterjee said MISO has been studying some areas of the grid “over and over and over” enough to know they stand out as particularly problematic.
“These are real problems with real market participants that have real pain,” he said.
