The Office of Electric Reliability and the Office of Enforcement at the Federal Energy Regulatory Commission on May 14 presented to the commission their 2015 Summer Seasonal Assessment.
This is staff’s annual opportunity to share its summer outlook on the electricity and natural gas markets and reliability matters to better inform the commission’s understanding of current and future trends.
“Market conditions going into the summer will reflect the continued low natural gas prices that have resulted from robust production, as well as the recovery of fuel stockpiles at coal-fired power plants,” said the report. “Regional electric system reserve margins are adequate, despite modest growth in load, which is primarily attributable to increased industrial activity. The historic drought in California and the West has entered its fourth year and is an area of particular concern. This may lead to elevated energy prices; however, both the NERC and the California ISO have concluded that the current situation is not a threat to reliability.
“Weather conditions are among the most important, yet difficult to predict, factors affecting the energy markets. NOAA is forecasting potentially warmer than normal temperatures across the West and the Southeast, with the greatest likelihood along the West Coast. Below normal temperatures are forecasted for portions of Texas and eastern New Mexico.
“Citing the likely development of a moderate to strong El Niño pattern, forecasters are predicting a below average hurricane season for the Atlantic basin, with only three hurricanes forecasted. By comparison, seven hurricanes is considered normal for a season. Generally speaking, hurricanes do not have the same level of impact on the US energy markets as they did several years ago, due to the substantial shift in natural gas production from the Gulf of Mexico to onshore shale production.
“The Energy Information Administration reported that power plant coal stockpiles have been recovering since summer 2014; however, the forecasted stockpile levels are expected to remain modest throughout 2015. In some regions, localized issues have resulted in limited rebuilding of these stockpiles. If natural gas prices were to rise during the summer, increased coal-fired generator output may result in coal supply issues to reemerge in the Midwest. The ongoing drought conditions in California and the West will limit the availability of hydroelectric generation over the summer. We will discuss the drought in greater detail later in this presentation. In late August, [ISO New England] may experience some impacts to the region’s natural gas-fired generating fleet when Spectra Energy begins maintenance and expansion of the Algonquin pipeline.
“EIA has forecast a 2.9 percent increase in electric demand from 2014, reflecting an expected return to more typical conditions from last year’s unusually mild weather. This compares to a weather adjusted increase of approximately 1 percent over last year’s forecast. This growth is driven primarily by the commercial and industrial sectors, as opposed to the residential sector, which is a reversal from the past few years.”
Coal retirements push down capacity totals
“[T]he total generating capacity in the U.S. has decreased by about 3 percent, primarily because of increased coal generator retirements,” said the report. “This is a continuation of the trend that was seen last year. In contrast to coal, NERC forecasts an increase of approximately 3.5 GW in wind generation capacity over last year, or approximately 6 percent and brings the national wind total to approximately 65 GW. NERC is also projecting a net increase of approximately 2 GW of installed utility-scale solar capacity for this summer, though more solar generation is planned to come online this summer.
“Data from NERC’s Summer Assessment indicates that reserve margins will be adequate for all assessment areas this summer. … Resource adequacy is forecast to improve this summer in MISO, ERCOT and New York. In ERCOT, a new load forecasting methodology that has resulted in higher available wind capacity, coupled with new natural gas-fired capacity, have increased the reserve margin from 15 to 15.6 percent. In New York, margins have also improved because of repowered generation capacity and lower forecast demand.
“The available generator capacity in WECC has increased by approximately 5 GW since last summer, with approximately 6 GW of additions and 1 GW of retirements. These additions include over 2 GW of solar and approximately 1 GW of wind resources. In ERCOT, approximately 2 GW of natural gas and 2 GW of wind capacity have entered commercial service since the last summer assessment. This includes the Panda Temple 2 natural gas combined cycle project and the Goldsmith peaker project with a combined summer capacity of approximately 1 GW.
“Notably, in the Eastern Interconnection, the 615 MW Vermont Yankee Nuclear Power Plant retired in late December 2014. This brings the total to five nuclear power plants that have been decommissioned since 2012. While the loss of Vermont Yankee leaves New England even more dependent upon natural gas, 178 MW of new energy efficiency projects are expected to be in place this summer. Despite the loss of Vermont Yankee, the grid operator forecasts adequate resources to meet demand.”
MATS, low natural gas prices to put a damper on coal
The FERC staff report added: “The Mercury and Air Toxics Standards (MATS) rules took effect in April and require advanced pollution controls on coal and oil-fired units larger than 25 MW. This has caused units in MISO and PJM to make capital-intensive pollution control retrofits to comply with the rule. While SPP has not published statistics that are similar to these regions, a recent Boston Pacific report, commissioned by the SPP Board of Directors, indicated that 1.1 GW of generation was expected to be retired as a result of EPA regulations.
“Adding pollution controls increases the non-fuel operating and maintenance costs of coal plants, but provides added flexibility to burn lower-cost, higher sulfur coal. Many plants have elected to install pollution controls with comparatively lower capital costs and higher variable O&M costs. This can increase total plant operating costs by up to one-third, which is typically reflected in higher energy market offers or directly incorporated in the retail rates of vertically integrated utilities. In a low natural gas price and load growth environment, the MATS related costs were uneconomic for many older and less efficient coal plants and many of these units were retired. The closures have exceeded conventional generation replacements and may result in lower reserve margins and increased transmission congestion in the near-term, as well as a greater dependence upon natural gas for generation.
“Forward prices [for natural gas] are not a predictor of actual prices, but reflect the cost of hedging market risk and can help us understand market dynamics. Going into the summer, the average Nymex futures price for June through August is $2.89/MMBtu, which is 40 percent lower than in 2014. This is consistent across the country, with the Boston area’s Algonquin Citygate showing the largest differential, at 46 percent below last year, and averaging $2.96/MMBtu for the summer. This can be attributed to a 5.7 percent year-on-year increase in natural gas production and storage inventories that are 71 percent higher than in 2014, or 4 percent below the 5-year average.
“With summer futures prices below $3.00/MMBtu in most regions, natural gas is expected to be competitive with coal on a $/MMBtu basis, when adjusted for the relative efficiency of natural gas versus coal-fired electric generation units. The only region where summer futures are above $3.00/MMBtu is Northern California; however, since the region has no coal-fired plants, it will not experience any coal-to-gas switching. Any further downward price pressure would give natural gas an even greater advantage in the supply stack and is comparable to 2012, when the Henry Hub price dropped to the lowest level in over ten years, averaging $2.65/MMBtu. According to industry estimates, this resulted in 5.1 Bcfd coal-to-gas fuel switching. Estimates for this summer indicate that a $2.50/MMBtu natural gas price could result in 4-5 Bcfd of incremental natural gas demand from power generators.”