Concerns About Summer Reliability in Texas and California Persist

Higher-than-average temperatures forecast for much of the U.S. this summer won’t affect reliability in most regions, though concerns remain for Texas and Southern California, according to the Federal Energy Regulatory Commission (FERC).

Presenting the “Summer 2018 Energy Market and Reliability Assessment,” on May 17,  FERC staff said that most entities that are part of the North American Electric Reliability Corp. (NERC) will likely be able to meet reference margin levels. That’s despite forecasts from the National Oceanic and Atmospheric Administration that project higher temperatures than average for most of the country, especially in New England and along a band running from West Texas through the Pacific Northwest.

Summer peak demand hasn’t grown compared to last year, owing largely to higher implementation of demand response and an increase in behind-the-meter distributed energy resources. While more than 25 GW of new generating capacity will be added to the grid through the end of the summer period, most will come from natural gas and renewables, staff said.

That will offset about 14 GW of generating capacity that has been retired since May 2017—10.8 GW that was coal-fired and 2.3 GW that was natural gas. Major coal plants that retired within the past six months include the 1.2-GW Big Brown plant, the 2-GW Monticello plant, and the 1.3-GW Sandow plant—all in Texas—as well as the 1.4-GW St. Johns River Power Park plant in Florida.

Texas and California Preparing for Tight Supply Scenarios

The retirements will weigh heavily on the Electric Reliability Council of Texas (ERCOT), which warned on April 30 that its reserve margin will hover at 11%, falling below its reference margin of 13.75%. ERCOT retired 4.5 GW of coal capacity in January and February 2018 alone. In late 2017, it also retired 806 MW of gas-fired capacity and suffered a delay in construction of new resources totaling about 2.1 GW. FERC staff noted that ERCOT expects to have “sufficient operational tools to manage tight reserves and maintain system reliability.” Those tools include deploying ERCOT-contracted load resources and emergency response services, using a previously mothballed unit expected to return to service in May 2018, requesting power across the existing DC ties, calling on generating resources that can switch between the Eastern Interconnection and ERCOT, and block-load transfers with the Southwest Power Pool (SPP) and the Midcontinent Independent System Operator (MISO).

While MISO also retired several large units since last summer, it has added new capacity, and it expects a reserve margin of 19.1%, higher than the reference margin of 17.1%.

The California Independent System Operator (CAISO) also expects “adequate supply for normal load and supply forecasts.” However, the grid operator warned in its 2018 Summer Loads and Resources Assessment that it could experience tighter supply conditions if high-load and below-average hydroelectricity production conditions occur. For now, CAISO is banking on demand response and consumer conservation to alleviate possible tight supply conditions.

Southern California, in particular, expects lower-than-average hydropower generation, owing to well-below-normal snowpack and a faster melt. This may “create challenges” as natural gas–fired generation—which has replaced hydro shortfalls in past years—may be limited due to distribution level pipeline outages that may affect both gas supplied to power plants and movement of gas into storage. “Limited operations at Aliso Canyon natural gas storage facility, plus state rule changes reducing the rate at which natural gas may be injected and withdrawn from storage, may complicate pipeline operations,” staff added.

Near-Record Gas Demand for Power Anticipated

Significantly, FERC staff noted that natural gas demand for power generation this summer could climb to record highs. The Energy Information Administration forecasts that natural gas power burn will average 35.16 billion cubic feet per day (Bcf/d) through June, July, and August—0.3 Bcf/d less than the record gas burn set in the summer of 2016 and 3 Bcf/d higher than last year.

“The addition of over 16,000 MW of new capacity to the natural-gas fired generator fleet since the record highs in 2016 and relatively low natural gas prices contribute to expectations for strong natural gas generation this summer,” staff noted.

Still, a narrow coal-natural gas spread will likely ensure diverse generation this summer, it said. “Futures prices for Central Appalachian (CAPP) coal are less than $2.50/MMBtu, while the Henry Hub natural gas futures summer strip reaches as high as $2.87/MMBtu.”

However, natural gas storage inventories are 350 Bcf less than the five-year average, staff noted. “This is the largest deficit to the 5-year average at the start of an injection season since 2014.” But this is unlikely to last: Growing gas production in Appalachia, Texas, and elsewhere increased U.S. output to record highs, and continued production will both position the market to meet summer demand and restock storage inventories, it added. “Specifically, EIA forecasts that inventories will grow to about 3,800 Bcf by November, which is within the 5-year range.”

Performance Requirements Will Apply in PJM and ISO-NE

Staff also noted that this summer both PJM and ISO New England (ISO-NE) will mark new directions for their three-year forward capacity markets in an effort to enhance reliability through market incentives. On June 1, ISO-NE’s pay-for-performance program will apply to all capacity resources, and PJM will continue phasing in its capacity performance program, which now encompasses 80% of the total capacity requirement. After another transition year—in delivery year 2020–2021—all the grid entity’s resources must meet capacity performance rules.

The programs essentially alter capacity markets to compensate or penalize capacity suppliers based on how well they perform when called upon during shortage conditions. Resources that fail to perform will be penalized by having compensation subtracted from capacity revenues, and those that over-perform, providing energy and revenues, will receive additional compensation. So far, no shortage conditions have triggered an assessment of penalties or rewards, FERC staff said.

Reliability will also be boosted by increased electric battery storage deployments across the U.S. As of January 2018, 720 MW of battery storage capacity was in operation nationwide—a 30% increase from the previous year. An additional 63 MW is expected by this summer.


—Sonal Patel is a POWER associate editor (@sonalcpatel, @POWERmagazine)

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