By Michael Kuser
New York energy markets performed competitively during the second quarter, with changes in fuel prices, demand and supply availability driving variations in wholesale prices, according to the NYISO Market Monitoring Unit’s second-quarter State of the Market report, released Monday.
Gas prices rose 20 to 60% in eastern New York and 65% in the western part of the state. But much of the impact on locational-based marginal prices (LBMPs) was offset by higher output of approximately 950 MW from nuclear, internal hydro and imports from Quebec and Ontario.
All-in prices averaged from $21/MWh in the North Zone to $57/MWh in New York City. The range was primarily because of congestion on power flowing from the North Zone to central New York, Central East congestion, and capacity price differences. Zone-level LBMPs increased in most regions by 7 to 25%.
Capacity costs were impacted by changes in net cost of new entry from the recent demand curve adjustment process. (See “ICAP Manual Changes for Demand Curve Reset Updates,” NYISO Business Issues Committee Briefs: Aug. 9, 2017.)
Congestion Management
Congestion costs from priced and unpriced constraints rose from 2016, with day-ahead congestion revenue up 24% from the same period a year ago to $117 million. Congestion increased into the city, across the Central East interface and along paths from western and northern New York, where priced congestion declined.
Unpriced congestion in the western and northern parts of the state became more prevalent because of improved hydro conditions within the state and low prices in the adjacent Canadian markets, as well as from transmission upgrades completed last year, which reduced priced congestion on 230-kV facilities in the west but shifted more flows onto parallel 115-kV circuits.
The Monitor found that “actions used to manage 115-kV congestion in western and northern New York led to import limitations from Ontario and Quebec as well as congestion on the 200-kV system in other parts of the state … management [which] could be performed more efficiently through the [day-ahead] and [real-time] market systems.”
PAR Operations with PJM
Real-time congestion costs for the Valley Stream load pocket on Long Island fell from a year ago because of improved modeling of lines between New York City and Long Island. Congestion increased through Millwood and into the city, but the ABC and JK lines were operated more efficiently.
The market-to-market phase angle regulator (PAR) coordination process with PJM expanded to include the ABC and JK lines in May after the 1,000-MW Con Ed-PSEG wheel expired. New coordinated flowgates were added mostly in New York City and the West Zone. For all PARs, actual flows typically exceeded their M2M targets toward New York, resulting in a small amount of M2M payments from PJM to NYISO in the second quarter.
The Monitor did find instances of efficient M2M coordination as PARs were moved in the correct direction to reduce overall congestion costs in a relatively timely manner. However, it cited “many instances” when PAR adjustments may have been available and would have reduced congestion but no adjustments were made.
“We observe that these PARs were often not utilized to help manage congestion, being adjusted only two to five times per day on average,” the report said.
PAR adjustments were not taken in some cases because of difficulty in predicting the effects of PAR movements under uncertain conditions or when adjustment would have pushed actual or post-contingent flows close to a line limit — or because of the transient nature of congestion or mechanical failures, such as stuck PARs.
The Ramapo PARs have provided significant benefits to NYISO in managing congestion on coordinated flowgates. Balancing congestion surpluses have resulted from relief of transmission paths from central to east New York, indicating that they reduced production costs and congestion.
“Nonetheless, comparable benefits have not been observed from the operation of ABC and JK PARs in the second quarter of 2017,” the report said. “We observed potential opportunities for increased utilization of M2M PARs.”
The normal limit for each PAR-controlled line was more than 500 MW, but flows were generally well below that level. On average, each PAR was adjusted two to five times per day, well below the operational limits of 20 taps/day and 400 taps/month. This was also below the average five to six 30-minute blocks of time per day when the congestion differential between PJM and NYISO exceeded $10/MWh across these PAR-controlled lines.
Reserve Market Performance
Day-ahead 30-minute reserve prices have been substantially elevated since a market rule change in November 2015, driven primarily by the new limitation on scheduling reserves on Long Island (down 250 to 300 MW), an increased 30-minute reserve requirement (up 655 MW) and higher reserve offer prices from some units.
The Monitor found that many units that offer above the standard competitive benchmark — or the estimated marginal cost — in part because of the difficulty in accurately estimating the marginal cost of providing operating reserves.
According to the Monitor, day-ahead offer prices may fall as suppliers gain more experience, which was evident in the second quarter as a large amount of reserve capacity reduced its offer prices from previous years, helping reduce price averages.
The Monitor will consider potential rule changes, including whether to modify the existing $5/MWh “safe harbor” for reserve offers in the market power mitigation measures.
Uplift and Revenue Shortfalls
Guarantee payments were $11.2 million during the quarter, comparable to a year earlier. Those payments rose in New York City and fell in Western New York because of higher gas prices that increased the commitment costs of gas-fired units and supplemental commitment for reliability in the city, and decreased out-of-merit dispatch and commitment of the AES Cayuga coal-fired units in the west.
Congestion shortfalls were $21 million in the day-ahead market and $11 million in the real-time, higher and lower, respectively, than in the same period in 2016.
Transmission outages accounted for roughly 80% of day-ahead market shortfalls in the second quarter, and $17 million were allocated to the responsible transmission owner.
Nearly all the real-time market shortfalls were associated with the North Zone lines, the West Zone lines and the Capital to Hudson Valley lines, with North Zone shortfalls accruing almost entirely because of transmission outages on two days in early April, totaling $4.6 million.
Capacity Market
Second-quarter capacity spot prices ranged from $1.99/kW-month in Rest-of-State to $8.02/kW-month in New York City. The average price includes one month of winter pricing (April) and two months of summer pricing (May and June).
Compared to the previous year, average spot prices fell 21 to 45% in New York City and the New York Control Area (NYCA) and rose 9% to 17% in the G-J Locality and Long Island.
Price changes in all regions were driven largely by changes to the installed reserve margin and net CONE of the proxy unit from the demand curve reset process. Net CONE values rose substantially in both the G-J Locality and on Long Island, while falling in the city and NYCA.
Additionally, import levels averaged 430 MW higher in the second quarter compared to 2016, with noticeably higher imports from PJM more than offsetting reduced imports from ISO-NE.