Short-Term Price Benchmark* Trends
ERC’s average price benchmark for commercial power in deregulated states edged up last week by .13 percent to a national average of $0.0803 per kilowatt-hour. This reverses a general decline in power prices over the past month. Price increases were most pronounced in Texas (+7.28 percent) and Illinois (+5.13 percent). In contrast, prices fell the furthest last week in New York (-3.08 percent), New Jersey (-2.67 percent) and Connecticut (-2.60 percent).
A number of suppliers currently have restricted pricing for longer term 48- and 60-month contracts. Many suppliers appear to be adjusting their pricing models as market conditions shift and we approach the end of the summer season.
Even though power prices increased slightly last week, prompt month natural gas futures dropped 14.4 cents on Thursday, finishing the week only 0.11 percent or $0.003/mmbtu higher than the previous week-end. Last Thursday represents the largest daily sell-off since last March and is likely based on modestly larger than expected net injection into inventory. As of mid-day Monday, gas futures are down another $.06 or, -2.28 percent from Friday.
Two drivers appear to be shaping the market for power prices going into September. On the one hand, NOAA weather forecasts are calling for warmer-than-normal temperatures (and more cooling demand) for all of the eastern and southern US. While this would normally curb storage injections and impact end-of-season natural gas inventories, production is at an all-time high in the Northeast. The market currently seems to be valuing strong production as opposed to warmer weather in pricing natural gas futures. This argues against a sustained increase in power prices over the immediate short term. Current year-over-year natural gas storage surplus is +22.5 percent.
Long-Term Price Benchmark Trends
There are a variety of factors that argue for both increasing and decreasing trends in power prices over the long term. Factors driving prices down include the following:
- Improved capacity to move natural gas afforded through a number of transmission projects such as the Algonquin Incremental Market project-pipeline expansion to the Northeast, and the Lake Erie Connector (starting construction in 2017).
- Increased drilling efficiency and high production volumes per dollars spent
- FERC order 1000 was upheld, and FERC ordered PJM to include demand response and energy efficiency in the upcoming transition auctions.
- 6.3 GW of new natural gas capacity is expected come on board in 2015.
Factors that may drive prices higher include:
- The EPA’s Clean Power Plan targeting carbon dioxide emissions reduction along with low natural gas prices are accelerating the conversion from coal to gas generation, adding capital conversion costs into power prices.
- Natural gas pipeline capacity limitations with approximately 8 GW of capacity planned to retire in 2015.
- Overall demand for natural gas is increasing at higher pace than production. For example, natural gas consumption in the power sector is projected to increase by 13.7 percent in 2015, and new chemical plants are expected to increase natural gas consumption by 4 percent in 2015.
Jim Moore, PhD, is president of the Energy Research Council. ERC manages a portfolio of primary research programs and databases that evaluate energy prices, procurement practices and management strategies.
Jim has been CEO of several research companies including TDC, a subsidiary of International Thomson; Highline Financial, a Thomson-Reuters company; and Mentis Corporation, which was acquired by Gartner Group. He has also served as executive director of The Global Futures Forum, an international think tank, and as managing director of Gartner Group’s Global Financial Services practice.
*The weekly average price benchmarks are derived from a standardized database of daily matrix prices issued by many electricity suppliers. The database is updated every business day and includes prices issued from September 2013 forward. The benchmarks are derived by aggregating individual supplier prices across the General Service tariff rate classes for each electric utility, and then averaging the utility price benchmarks together for a state level benchmark. Finally, these state level benchmarks are averaged across the five business days of each week to create the weekly average price benchmarks by state. These benchmarks reflect the average prices for General Service tariff rate classes by utility and state, based on next month’s start date. As mentioned, these benchmarks are based on matrix prices for commercial customers with an annual usage of up to 1 million kWh. While they are not a valid measure of pricing for larger C&I customers, the high level of correlation between matrix and custom pricing make the benchmarks a reliable measure of how prices are trending, as well as the direction and velocity at which prices are changing week-over-week and month-over-month. This is similar to how the S&P or Dow measures the rate and direction of change in stock market prices over time.