Transmission planners are considering additional changes to their light-load studies based on a reevaluation of three years of data that showed coal- and natural gas-fired generation are operating at higher capacity factors than previously assumed. Planners already had concluded that maximum wind capacity factors should be increased in the studies.
The analysis showed that capacity factors for coal generators during light-load periods — 1 to 5 a.m. from Nov. 1 through April 30 — have been trending up, in large part because retiring units are leaving more electricity to be generated by those remaining.
Planners are considering increasing the maximum ramping of coal plants 500 MW and larger above the current 60% and boosting the assumptions for coal plants below 500 MW above the current 45% maximum. PJM also is weighing an increase in assumptions for natural gas plants; planners currently assume they are not dispatched at all during light-load periods.
The analysis found large plants operated above the 60% capacity factor in about two-thirds of light-load hours RTO-wide during delivery year 2013-14, with the APS and AEP zones above that level about 80% of the time. Smaller coal units operated above their assumed capacity factor in about half of the hours RTO-wide. In APS, small coal ramped above the assumption in all light-load hours for the year, Mark Sims, manager of transmission planning, told the Planning Committee last week.
“A significant amount of coal has retired. What’s left is running more often because it’s more efficient and competitive,” Sims said.
Capacity factors also have been increasing during light-load hours for natural gas combined-cycle units as the fuel has become cheaper. RTO-wide, they operated in about one-quarter of light-load hours, with units in the AEP zone running in 86% of hours. When they are operating, they are generally doing so at capacity factors of 80% or higher.
No changes in assumptions are proposed for oil (assumed at 0%) and nuclear units (assumed at 100%).
PJM last month announced its intention to increase the maximum wind capacity factor from 80% to 100%, consistent with the modeling in MISO. (See Changes Proposed for Light Load, Wind Modeling.)
Sims said staff will conduct sensitivity analyses after finalizing their recommended changes and report back to the PC.
PJM Looks to Tweak Peak Load Forecast
PJM plans to recommend changes to improve its peak load forecasts by the end of June, officials told the PC. The revised model is an effort to better reflect customer usage, energy efficiency, weather and the impacts of “behind the meter” solar generation. (See PJM Seeking Improved Load Forecasts.)
PJM’s John Reynolds said efficiency in heating is continuing to climb, though not as dramatically in recent years. Meanwhile, cooling efficiency has leveled off and overall energy usage for cooling is expected to begin increasing by 2020.
PJM also is investigating the impact of distributed solar energy on demand. More than 1,700 MW of photovoltaic solar generation not registered as capacity resources is now receiving solar renewable energy credits in the PJM region, up from zero in 2005. Reynolds said most of the generation is in New Jersey, which has generous solar subsidies.
Planners expect to identify improvements to the model by the end of the second quarter, with revised manual language brought to stakeholders for endorsement by the end of the third quarter. Any changes would be implemented in the 2016 load forecast.
Long-Term Firm Transmission Study Endorsed
Members unanimously endorsed creating a Planning Committee sub-group to consider changes in how it studies long-term firm transmission service requests. The effort, initiated with a problem statement approved in March, is intended to ensure that individual requesters share in the cost of transmission upgrades required to serve them. (See Change Would Shift Baseline Upgrades to Network Customers.)
“PJM’s process, tools and thresholds have been established based around a local generation or transmission injection projects’ impacts and not around remote origination of energy,” according to the issue charge approved by members.
The group is expected to complete its deliberations by the end of the third quarter.
Committee Endorses Reserve Requirement Study
The PC approved revised assumptions for the 2015 PJM reserve requirement study that are expected to have a minor impact.
The study will determine the installed reserve margin, forecast pool requirement and demand resource factor for future delivery years and will look at the period from June 1, 2015, through May 31, 2026.
The two changes of note regard the computation of demand response and PJM’s proposed Capacity Performance product.
The study will use PJM’s new method of modeling demand response, which takes the average of the final amount of committed DR for the most recent three years. Previously, forecasters used the amount that cleared the last Base Residual Auction. (See Members Endorse Change to Demand Response Modeling.)
And, because the RTO’s Capacity Performance plan is in limbo as it awaits a ruling from the Federal Energy Regulatory Commission, the study will report using two sets of parameters — one with the CP product and one under the status quo. The forecast pool requirement values that ultimately will be applied will depend on whether FERC approves PJM’s plan. (See related story, PJM Responds to FERC Queries on Capacity Performance, Requests Approval.)
Order 1000 Problem Statement Approved
The PC approved a problem statement formalizing its work on process improvements as a result of Order 1000 “lessons learned.”
Although PJM already has begun incorporating the lessons — for example, introducing an improved method for receiving document submissions from transmission developers — officials said they decided a problem statement was needed because the issue would be a “standing agenda item” for the committee in the future.
PJM’s first project under the order, soliciting a fix for stability issues at New Jersey’s Artificial Island nuclear complex, has been beset by numerous delays and controversy. Planners expect to recommend a proposal to the Board of Managers next month — more than two years after the competitive window opened. (See related story, Planners Set April 28 for Artificial Island Recommendation.)
— Suzanne Herel