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ERC: Electricity Price Trends for the Week Ending September 11

September 16, 2015 By Jim Moore, PhD

Jim Moore, PhD

Short-Term Price Benchmark* Trends

  • After dipping to a low of $.0788 per kilowatt hour week ending August 28, 2015, ERC’s average power price benchmark has now increased two weeks in a row to an average of $.0793 $/kWh. The biggest increase was in Rhode Island (+1.59 percent) and Maine (+1.51percent). Only Massachusetts (-2.84 percent) and Texas (-0.92 percent) prices declined last week.
  • The average price benchmark for longer-term 48- and 60-month contracts were favorable last week across a number of states including Washington DC, Illinois, Maryland, New Jersey, Pennsylvania and Texas.
  • NOAA weather forecasts call for slightly higher temperatures and cooling demand compared to last week’s forecasts. This week, a larger portion of the country is expecting a warming trend. Warmer than normal temperatures are now forecast across most of the country through the end of September.
  • Natural gas production remains robust, averaging 0.17 percent higher than the previous week, and 4.14 percent more than this time last year.  Northeast production continues to set records. The Oct Nat Gas futures contract increased by 1.43 percent last week after a smaller than expected net injection into inventory. The market ended the week in the same technical trading range even as the latest short-term weather forecasts continue to call for above-normal temperatures through September.

ERC Avg Wkly Benchmarks 091115Long-Term Price Benchmark Trends

The retirement of outdated coal plants, an increase in natural gas dependency, and recent extreme weather (like the 2014 polar vortex) have raised concerns about power system reliability in the PJM region. PJM and federal regulators (FERC) have consequently put in place reforms to the capacity market model. The capacity performance model changes will become effective on June 1, 2016. The first auction that included PJM’s new Capacity Performance rules drove clearing prices up 37 percent in most of the territory. The prices cleared at $164/MW-day in most of the regional transmission organization (RTO), with exceptions in the ComEd and Eastern MAAC zones where capacity prices cleared at $215 and $225, respectively. In last year’s auction, annual resources cleared at $120/MW-day (27 percent lower) in most of PJM following rule changes that limited demand response and generation imports.

As regulators fine-tune new regulatory changes concerning capacity and reliability, retail electricity prices are becoming more expensive. PJM’s performance capacity and ERCOT’s operating reserve demand curve rules are examples of how frequent regulatory changes increase the costs of compliance (i.e., keeping automated deal-capture, pricing and risk systems up to date) and subsequently the price of retail power. Frequent rule changes also make it difficult to price forward deals and to hedge when the rules are still being crafted. Increasing regulatory change and the escalation of transmission and distribution charges are the product of an aging infrastructure that requires ongoing repair and replacement. These factors will continue to add cost and create upward pressure on power prices for some time to come.

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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.

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