As you can see at the bottom of the previous page, power prices were on the move last week. Aside from their regular correlation to the natural gas futures market, there were other dynamics in play last week. Specifically, the Supreme Court of the United States ruled on the Cross State Air Pollution Rule (“CSAPR”). CSAPR requires 27 states in the eastern half of the United States to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ozone and fine particle pollution in other states. This ruling, if affirmed by the federal appeals panel, would require impacted power plants to undergo a drastic retrofit to reduce these emissions.
The ruling somewhat surprised many market analysts. Quickly the market had to determine what impact the cost of such a retrofit should create on the forward energy curves. On-peak energy prices rose anywhere from $1.00 to $1.70 per mWh and off-peak energy prices increased $0.50 to $1.00 per mWh. With this late April/early May surprise to power markets, attention has quickly shifted from the winter of the polar vortex to the upcoming summer in which power consumption peaks. Considering the storage levels of natural gas and the reliance on natural gas for power generation, natural gas prices will continue to play the leading role in driving energy pricing for electricity. But, depending on the market and the specific customer’s load profile, energy prices only account for 50%-70% of a contract price.
The next largest component is the cost for capacity. Simply, capacity means having adequate generating resources to ensure that the demand for electricity can be met at all times. This is very similar to reserving pipeline space, or transport, in natural gas vernacular. The primary difference between capacity in power and transport in natural gas is the underlying cost used to calculate a per unit charge. In natural gas, the underlying cost is fairly stagnant year over year and does not change too often. The risk on that component changing is fairly minimal. In power, and specifically in PJM utilities where most of IGS Energy’s commercial and industrial customers operate, the underlying cost for capacity changes each year (years in this case run from June to May).
The graph shows the rates for five utilities, all in the PJM area. You will see that AEP, ComEd, and Duke all share the same curve because they are on the western side of PJM. First Energy should also share that curve except that unexpected retirements of multiple coal fired plants significantly increased their capacity costs and drove their June 2015 and beyond capacity prices higher. Lastly, PECO is in Philadelphia and on the eastern side of PJM. The eastern side is almost always more expensive due to the amount of load there and the location and types of power plants which serve that load. Beyond understanding the differences between utilities, year over year changes within a utility are most important, especially for the western part of PJM. Capacity prices for the past two years have been relatively cheap, between $15 and $30 per megawatt-day. That jumps north of $125 for Jun-15 to May-16 and even higher for the following year. Some relief comes in the final year shown on the graph. First indications of capacity costs for Jun-17 to May-18 will be known at the end of May and we will update this graph accordingly at that time.
What end users need to understand, especially those finishing fixed rates in the coming months, is that pricing for future terms will be more expensive compared to your last price. With capacity costs more than quadrupling in some cases, an unavoidable increase in price is almost certain. End users should certainly consider looking at longer term pricing so as to enjoy the benefit of the cheaper third year capacity costs and to help mitigate the price shock that is coming as a result of capacity cost increases.