Grid officials and market watchers tell federal officials they expect to reliably meet winter demand this coming season, though some challenges remain, the weather is unknowable and areas with limited natural gas capacity could struggle.
In California, gas shortages due to the Aliso Canyon leak will affect dozens of plants and more than 20 GW of capacity. For New England, which gets almost half its power from gas generators, the grid operator can marshal up to 10% of its capacity in the form of demand response and alternative generation. New York and adjacent markets have worked to better coordinate scheduling, and PJM will implement its enhanced capacity performance product, with stricter generator penalties.
On whole, gas prices are expected to be higher. And given weak heating demand during the last mild winter, gas consumption is expected to rise. Much of this is cyclical — lower gas prices resulted in lower production — but the market also has plentiful storage, the possibility to import liquefied natural gas, and a better-connected pipeline network, to help it cope.
The weather is generally expected to be average, which will lead to a bump in consumption after warm weather a year ago. Total gas demand could be 5 billion cubic feet per day (Bcf/d) more than last year, which will elevate prices. But the electric generation sector could actually see a 2 Bcf/d decrease in gas demand, with less fuel switching taking place due to higher prices.
Organized markets from New England to California recently presented to the Federal Energy Regulatory Commission their plans for meeting demand this summer, each taking unique steps. Combined with a strong natural gas supply base and new coordination strategies, here's a glimpse at the challenges five of them face in keeping the lights on.
First, the broad gas supply situation
As of last month, the U.S. Energy Information Administration said working gas in storage had topped 3,900 Bcf, almost 200 Bcf above the five-year average.
"The market is likely to remain well supplied throughout this winter," FERC staff told the commission. "Natural gas and power markets are well supplied going into the winter, with plentiful storage, a better-connected pipeline system, and the ability to draw greater imports from Canada through pipelines and higher imports of LNG into New England."
The warm summer and a small drop in gas production have raised gas prices at the Henry Hub, a liquid trading point used for price formation, from below $2/MMBtu to more than $3/MMBtu this month. The staff's report shows an increase in the futures curves for both power and natural gas mirrors cash markets. The strongest gains are in the Midwest and on the West Coast.
In Southern California, FERC staff said gas futures at the SoCal Border trading point for January and February are a third higher than a year before, causing power prices at SP-15 to rise 22%. But there are exceptions to the trend. In New England, gas prices are 20% lower at the Algonquin hub, due in part to new gas pipeline capacity. Constraints running into the New York City area will keep gas prices elevated.
In the event a cold snap, the country can possibly turn to imports from Canada or LNG imports in the Northeast.
Gas imports from Canada have been declining in recent years, but year-to-date cross-border flows are rising, according to staff's report. Canadian gas fields are on pace to reach 15 Bcf/d, the highest rate in almost a decade.
"A high level of pipeline connectivity between Canada and the U.S. provides adequate potential to tap into this supply if conditions warrant," staff said.
And last winter LNG terminals along the East Coast received 19 cargoes totaling more than 37 Bcf. The bulk of those came into the rising Everett and Northeast Gateway facilities serving New England. "With global LNG prices significantly lower than in previous years, more spot cargoes could find their way to U.S. terminals should the need arise and prices allow," according to the assessment.
ISO New England pipes at capacity
In New England, the grid operator has taken extensive steps to bolster its gas monitoring programs, and shifted day-ahead markets to align power and gas days. The ISO runs three winter reliability programs, and also has increased information sharing between the sectors.
The region has limited natural gas pipeline infrastructure, and according to ISO Vice President of Operations Peter Brandien, "and these pipes have reached their maximum capacity, especially during the winter months when demand for natural gas to heat homes is at its highest."
The New England system includes about 350 generators with capacity of 31,000 MW. Last year, about half the region's power was generated from natural gas, up from 15% in 2000 — the rapid rise and tight market means gas sets the wholesale power price about 70% of the time.
"Consequently, availability of natural gas for power generation has a profound impact on grid reliability and production costs in New England," Brandien said.
The ISO turns to a Gas Usage Tool, a monitoring program that allows it to estimate the amount of natural gas available for electric generation. To do that, the grid operator's program estimates the demand for gas by industrial and local gas distribution companies’ customers, as well as gas-fired generators, compared to the capability of the natural gas pipeline system, including LNG injections into the regional gas pipelines.
The system assumes a certain outage rate, but in the event cold weather takes more gas generators offline it has a series of actions, including calling on demand response programs and importing power, that can provide about 3,000 MW of relief.
"With the winter reliability program in place, ISO New England expects to have adequate electricity supplies to meet consumer demand this winter," Brandien said.
Gas constraints are a concern, but the region is actually better situated this winter. Increased pipeline capacity resulting from Spectra Energy’s Algonquin Incremental Market project is expected to be online next month, adding about 340,000 dekatherms of natural gas per day. But that relief will be temporary, as non-gas resources retire and gas-fired generation takes their place.
ISO New England expects more than 1,500 MW of non-gas units, including the coal-fired Brayton Point Power Station in Massachusetts, to retire by June.
New York ISO prepares to go short gas
Officials in New York say they expect to have sufficient capacity to meet all demand this winter, but much like in New England the grid operator is focused on better monitoring and coordination. New York City faces the highest gas prices in the nation, according to FERC staff, and so enhanced coordination has been critical, as well as looking to other options.
"Seasonal generator fuel surveys indicate sufficient winter starting oil inventories along with arrangements for replacement fuel oil for oil-burning units," the ISO told FERC in its presentation. The grid operator also uses a web-based, fuel survey “portal” to give generator fuel information to the operators, operates a gas-electric support control room, and monitors a map of the regions pipeline operations.
Earlier this summer, the ISO enhanced scarcity pricing for demand response was activated, and last year it increased the Total Operating Reserve Requirement from 1965 MW to 2620 MW in the day ahead market and real time dispatch.
But gas availability will be a challenge, especially in cold weather as residential heating load has transportation priority. And tighter environmental restrictions could be an issue for units forced to burn oil.
"A communications protocol is in place with NY state agencies to improve the speed and efficiency of generator requests to state agencies for emissions waivers if needed for reliability," the ISO said.
PJM implementing lessons learned
Gas is more than 30% of generation in the PJM Interconnection, and the market is still building on the lessons learned during the Polar vortex of 2014. Two years ago, cold weather forced up to 20% of the grid's generation offline, leading PJM to develop more stringent penalties and rewards for performance.
This is the first year the new capacity performance market design will be in effect, though not all capacity will face the new requirements. Beginning in June, 60% of all resources that cleared the auction are capacity performance resources that must be available when called on, or else face significant penalties that could exceed capacity revenues.
Those rules are still being hammered out: several advocacy groups have filed a lawsuit arguing the new requirements will disadvantage demand response, which is typically a summer resource.
PJM is forecasting peak load of 135,500 MW, and it has installed capacity of about 183,600 MW. The grid operator believes almost all pipelines will be operating next month, but said local opposition is holding up a pipeline project that could five it even more cushion.
"Buildout of these pipeline projects would expand capacity and supply options and improve grid reliability," PJM told FERC.
MISO implements market, operational enhancements
Much like PJM, the Midcontinent ISO's efforts to harden the grid after the Polar vortex are maturing, the operator said.
MISO anticipates 2016 total available capacity of 140.8 GW, with a projected reserve margin between 28.4% to 37.5%. Peak forecast is 104 GW, well below all-time winter peak demand of 109.3 GW.
The winter load curve complicates operations in the Midcontinent, because it has a steeper second ramp-up than summer. The steeper load increase means the grid has to dispatch short-lead resources, which are most prone to the shortages which lead to price spikes. To counter that, MISO instituted a Ramp Capability Product that addresses the increasing system ramping needs.
The ramping product "provides transparent price signals to help manage ramp constraints that could lead to short-term reserve scarcity events," and emergency pricing signals "and prevent uneconomic price suppression during emergencies."
MISO has also increased transfer limits from 1,000 MW bi-directionally to 3,000 MW for North-to-South flows and 2,500 MW for South-to-North, helping to "increase system efficiency and diversity," according to its presentation.
California still struggling with Aliso Canyon
The California ISO is predicting a warmer than normal winter, and lower load as a result. The system has full transfer capability and there no reductions on major paths; in addition, a new 500 kV line is boosting transfer capability into the L.A. Basin.
The ISO is also using a flexible ramping product to secure secure ramping capability in the fifteen-minute
market for real-time dispatch. The result should be more transparent and less-volatile pricing signals, and will better address the higher cost of ramping capacity.
That means the story of West Coast reliability remains at Aliso Canyon, where last year it was discovered a leak had drained the facility down to less than 20% capacity.
The facility remains closed today, and activists in California are pushing for permanent shuttering. All told, the leak directly impacts 17 gas-fired plants generating about 9,800 MW. But there are broader implications for 48 plants generating more than 20,000 MW, the ISO told FERC.
The staffs of the California ISO, California Public Utilities Commission and California Energy Commission developed a winter reliability plan to deal with the possibility of gas curtailments, including extending tighter gas balancing rules for non-core customers into the winter, setting advance limits on gas consumption by generators on winter peak days, and creating demand response programs to reward lower natural gas use.
Core gas users make up 60% of demand, and the ISO says non-core generators are "first curtailed to meet core
The California agencies have also pushed utilities to step up storage purchases, with SCE and SDG&E both planning to bring on battery projects in the coming months that will be among the largest in the world.
Demand response has been a key to avoiding curtailments so far. Preliminary estimates in the winter reliability plan related to Aliso Canyon indicate Southern California investor owned utilities dispatched 630 MW of demand response in June, and another 400 MW in July.