Making Sense of the Present Electricity Market


  • Regional issues are ruling the day, when it comes to understanding today’s electricity market– gas & power correlations remain critical, but we continue to see increased frequency of separation.  There are fundamental factors that are behind this trend:
    • Northeast basis – too much info on this to put in this blog posting, but the short-story is that the region is short gas pipeline capacity and this year’s cold temps and pipeline constraints have caused huge gas spikes to New England (several days in $20-30 range) and to a less extent New York Zone 6 (>$20).  Day-ahead power has moved with gas with some spikes near $200/MWh. This is impacting long-term prices.  Unfortunately, the pipeline constraints are unlikely to be resolved in the near-term.
    • ERCOT Resource Adequacy – this issue is also not going away as ERCOT is expected to remain below is target for reserve margins and the increased offer caps are not expected to resolve the problem.  So do not expect summer premiums to disappear and there will be ongoing discussion on solutions to the problem.  Regulatory news and summer price spikes will both impact forwards.
    • PJM Capacity –the wholesale energy prices in the market remain low, but capacity prices vary greatly within the ISO – rising for most of the West and falling for the East over the next 2 years with certain areaa having exceptional spikes (ATSI).  Note that we have updated capacity charts that clearly illustrate this trend.
    • California Cap & Trade & SONGS outage- ongoing strength in forwards as Cap & Trade has been implemented and there is still tremendous uncertainty regarding SONGS, which has been shut down for almost one year.
  • Customer message:  The overall message is straightforward, but may be difficult for customers to accept since many have had consistent year-over-year price declines since the peak of 2008.
    • Year-over-year declines in gas have stopped with 2012 likely being the bottom.
    • Rangebound gas behavior for the near-term with modestly higher prices possible for 2014.
      • It makes sense that natural gas futures are higher than a year ago, but below long-term averages.  And we expect this to continue.  So don’t count on another spring dip – it is very unlikely to see a repeat of April 2012.
    • Both upside and downside are limited by coal-to-gas, production economics, storage, etc.
    • Regional fundamentals are causing significant regional risks that must be considered.  If you only focus on natural gas, you are exposed to significant regional risks such as New England winter spikes and ERCOT summer spikes.
  • Regional issues may provide a better rationale for customers to contract their electricity now.

PJM Capacity Price Forecast

The PJM Interconnection capacity auction parameters released late on Friday show a likely increase in new gas capacity clearing, increased demand response and a weak demand outlook, all of which could lead to lower capacity prices for delivery year 2016/2017, according to market analysts.

PJM’s annual capacity auction for delivery year 2016/2017 will not take place until May, but the auction parameters PJM posted last week are already giving analysts hints on how the results could turn out.

UBS Investment Research said in a Monday report that it predicts the regional transmission organization price will clear at $124/MW-day, down from $136/MW-day last year, with the MAAC zone clearing at $157/MW-day, down from $167.50/MW-day last year.

Barclays also predicted that this year’s capacity auction results will be “somewhat lower” than last year’s auction but it pegged the prices higher than UBS did, with the RTO price expected to be between $100 and $120/MW-day and the MAAC zone clearing between $130 and $150/MW-day, according to Barclays’ Monday report. Barclays also gave a prediction for the PS North Zone, between $160 and $180/MW-day.

Before each capacity auction, PJM calculates each zone’s capacity emergency transfer limit and its capacity emergency transfer objective and publishes that information in the auction parameters. Any zone that has a CETL less than 1.15 times its CETO is modeled as a zone in the upcoming auction, and the ratio level helps predict the potential for constraints within the zone.  CETL is defines as the Capacity Emergency Transfer Objective and  CETL is defined as the Capacity Emergency Transfer Limit.   An electricity broker adviser such as Better Cost Control can benefit larger customer in taking this information into account when procuring electricity.

Both the ATSI and Cleveland zones were projected at about a 140% CETL/CETO ratio, suggesting they will not clear separately, said Julien Dumoulin-Smith, analyst for UBS, in his Monday report. Meanwhile, the PS and PS-North zones were projected at 102% and 120%, respectively, suggesting those zones will clear at a higher level than the RTO-wide price, he said.

The update cemented UBS’ view that prices will show a “modest downward trajectory” in this year’s auction, Dumoulin-Smith said. Recent changes to Environmental Protection Agency demand response rules and potentialnatural gas capacity exemptions from the Minimum Offer Price Rule could play a part in capacity prices decreasing.

“Updated MOPR prices from PJM confirm a modest jump is necessary to make new gas capacity economic, however all new capacity is likely exempted from MOPR,”Dumoulin-Smith said. “Despite potential changes to demand response bidding rules, we see the EPA recent decision to allow the use of backup diesel generators as limited DR as driving another large increase in DR.”

Barclays also cited the EPA backup diesel generator rule, saying it “did not hurt the prospects for demand response.”

PJM is looking at largely flat demand growth, year-on-year. The footprint-wide peak forecast load for 2015/2016 was 163,168 MW, compared the forecast load for 2016/2017 of about 165,425 MW, up slightly more than 1%.

Furthermore, the slight increase in the load forecast isn’t due to a true rise in demand. The East Kentucky Power Cooperative will integrate its system into PJM in June, resulting in its inclusion as the EKPC zone in the upcoming auction. The addition of the EKPC zone added a peak load contribution of 2,213 MW to the footprint-wide forecast peak load for the 2016/2017 delivery year, according to the parameters.

“The parameters supported the weak demand fundamentals for power in the Mid-Atlantic and Midwest,” Barclays’ report said.

The weak demand, demand response and energy efficiency as well as net capacity are the drivers in this year’s auction, able to cancel out the impact of a higher net cost of new entry, Barclays said.

Barclays expects to see 2,500 MW of new generation, uprates or imports entered into the auction and 1,200 MW of shutdowns or derates regionwide. UBS said it expects to see 700 MW of retirements. Barclays also predicts the auction will see 1,500 MW of new demand response and energy efficiency, compared to last year’s growth of 814 MW.

The installed reserve margin rose slightly in this year’s auction parameters, compared with last year’s auction, edging up less than 1% on the year to 15.6%. The IRM is the level of capacity reserves needed to satisfy the PJM reliability criterion of no more than one occurrence of load lost in ten years, the parameters said. The reliability requirement is used to establish the target reserve level to be procured in the annual capacity auction.


How does the electricity grid work?

This video does an excellent job of explaining how the electricity grid actually works. While most people looking to contract electricity through an energy broker just care about the price, I think that it’s worth understanding how the electricity is delivered.  You can’t control the delivery cost, just the supply cost.

A picture says a thousand words, so need I say more?

PJM Electricity Interconnection Organization’s capacity locked in at price of $136 per MW

PJM’s capacity auction secured a record amount of new generation, demand response and energy efficiency resources for the 2015/2016 delivery year to keep the grid reliable as dozens of coal plants retire and are converted to natural gas.

The auction, known as the Reliability Pricing Model (RPM) auction, procured 164,561 megawatts (MW) of capacity resources at a base price of $136 per MW, compared to the price last year of $125.00 per MW.

Capacity prices were higher than last year’s because of the retirement of existing coal-fired generation, due to environmental regulations, which go into effect in 2015.

PJM serves 60 million people in 13 states in the Mid-Atlantic and Midwest and the District of Columbia. Capacity prices were higher in northern Ohio and the Mid-Atlantic region.

For the Mid-Atlantic, PJM said capacity will cost $167 per megawatt.

The Mid-Atlantic region includes utilities served by Pepco Holdings Inc’s Atlantic City Electric, Delmarva Power and Pepco; Exelon Corp’s Baltimore Gas and Electric and PECO; FirstEnergy’s Jersey Central Power and Light, Metropolitan Edison and Pennsylvania Electric; PPL Corp’s PPL Electric Utilities, Public Service Enterprise Group Inc’s Public Service Electric and Gas; and Consolidated Edison Inc’s Rockland Electric.

In FirstEnergy Corp’s northern Ohio territory, PJM said the capacity price will be $357 per megawatt due to the high number of power plant outages in that area.   With the exception of the AEP territory, Capacity is a fairly small component of the retail price of electricity, and the cost of capacity at the retail level tends to be averaged out over several years.


Why long term electricity contracts in PJM service area make sense

The inexperienced electricity buyer looks just at the price and goes with the lowest price. In today’s market (April 2012), shorter term contracts have the lowest price. But taking this approach can be short sighted. Why is that the case? First off, when you want to get a new contract in a year, your price will likely be a lot higher. As long as you know that, fine.  But there is more to understand.

In the PJM service area, one component of your fixed price are future capacity rates and trends. We are encouraging our customers to consider the longest term possible, up to a 24 month term, up to the period ending May 2015, to blend low energy prices against higher capacity rates. Locking in a longer term will protect you from the capacity price increases, which are a known number. So even if the energy cost is the same, the electricity prices will rise because of the rising capacity charges.  The higher capacity charge from next year is averaged into the present cost, which is one reason a longer term contract costs a bit more.  But when you look at your total cost over the 24-month period versus what they would be otherwise, based on the direction of the economy, you will win big overall and protect your budget.

PJM Capacity Cost Component

· June 2012/May 2013 $131.48 Per MWH
· June 2013/May 2014 $227.11 Per MWH
· June 2014/May 2015 $136.50 Per MWH
· June 2015/May 2016 Unknown at this time

· Capacity rates (set three years in advance by PJM) have increased to over $227 level for your next capacity rate contract term

· Recovering economy should keep capacity rates at least to the 2014/2015 level when PJM conducts next auction in May ‘12

· EPA’s plan for MAT (Mercury Air Toxin) rules have driven several generators to close 50’s vintage power plants due to high compliance cost coal plants exerting upward pressure on next auction. Less coal generation means higher prices, but cleaner air. Another reason to lock in a longer term contract.

Capacity charges are typically calculated based on the difference between a customer’s peak energy use during a billing period and their nominal use (normal or hour-to-hour use) during the same period. If the customer expects to have substantially more power available to them than they actually use, then a demand charge is applied to cover this difference.

Demand charges are not a means of gouging customers by charging for unused energy. Instead they are a means of insuring that customers can have larger-than-normal supplies of energy available to them at a moment’s notice.

Keep this information in mind when deciding what contract length you want. Take a long term view and next year you’ll be smiling at the decision you made. Consider the slight increase that you will pay in the short term your price for insurance against rising prices. Insurance costs money. Would you go without fire insurance because it costs money and you have never experienced a fire?