Pepco Files New SOS Rates

Pepco-MD Generation Service Charge 9/1/13 – 11/30/13 (¢/kWh)

Schedule MGT LV II

On Peak:        8.420

Intermediate:   7.788

Off Peak:       7.520


Schedule MGT 3A II

On Peak:        8.303

Intermediate:   7.680

Off Peak:       7.416

Charges above are for generation only, and do not reflect bypassable transmission or reconciliation.



The original source can be found here.

Energy Auction Debate Leads to Customer Losses

State lawmakers are in the process of deciding whether or not the retail electricity accounts of Connecticut Light & Power and United Illuminating will be auctioned off to private marketing companies. This is an attempt to raise cash for the state, even though it will cost the 665,000 CL&P customers. Starting on July 1st, these 665,000 customers were expecting reduced rates of about 5-8%. Now, this price cut is not going to happen. This is because the power companies could not guarantee energy traders that they would still have their large customer base for the remaining half of the year. Without this guarantee, they were unable to lock in lower rates. Now these rates will remain unchanged and nobody will be able to take advantage of the lower market prices. The states power procurement manager Jeff Gaudiosi said “even with the specter of this auction being there, we lost all of our buying power for 2013 and into 2014.”

From the perspective of the government, this auction could raise around $80-$100 million, a nice boost to the state budget which is why Governor Dannel P. Malloy is pushing for it. If the auction could bring lower rates to customers, it should be done, if not, it would be a very unsuccessful attempt. If the state were to take this money from the auction, it would basically be a large tax. Private marketing firms are willing to pay significantly more per account, and it is only logical that the paying customers should see some of this money on their end. To put it in perspective, in the year 2000 the market was moved from the power companies to private marketing firms. These marketers have been trying to sell at rates they claim are better than average. 47% of customers have taken that route.

Those individuals who don’t switch will stay with CL&P or UI and will be paying based on a state approved buying strategy. Now the standard offer is 7.615 cents per kilowatt hour at CL&P. Regardless, customers will be paying a monthly bill to either company at the same regulated distribution rate.

According to Malloy, customers would be segmented into blocks of 100,000 and auctioned off as groups. The proposal states that anyone could opt out of the auction and continue paying standard rates. Marketers would not be allowed to charge for switching, and they would have to offer a 5% discount below the standard rate for the first 12 months. As good as this sounds, that 5% is based on the current price, where customers would have seen that as a minimum of savings because of market conditions. This is just an estimate as we cannot know for sure.


Better Cost Control now licensed in New Hampshire

Better Cost Control, a leading electricity and natural gas procurement adviser for companies in the deregulated states, has just received license approval by the state of New Hampshire’s Public Utility Commission.

Based in Newton, Massachusetts, Better Cost Control has been providing its energy procurement services since 2002.  Their experience  and expertise puts them in the position to get customers the best terms on their energy costs. They do this by finding prices that are not advertised and negotiating with energy supply companies, some of whom only work with brokers like Better Cost Control.

By working with energy suppliers throughout the U.S. they are well aware of each supplier’s individual strengths and weaknesses. 

If you have ever encountered an energy contract, you know they are highly complex. The devil is in the details; what seems at first to be the lowest price may, in the end, actually be higher than you thought. The Better Cost Control team negotiates hundreds of these contracts each year. They know what to look for.

Services are now offered through independent agents in these states:

  • Connecticut
  • Delaware
  • Illinois
  • Maine
  • Maryland
  • Massachusetts
  • New Hampshire
  • New Jersey
  • New York
  • Ohio
  • Pennsylvania
  • Rhode Island
  • Texas
  • Washington, D.C.

For more information or for custom pricing, call 860-436-2768.

New Standard Offer Prices for National Grid in Massachusetts

The Massachusetts DPU approved new standard offer electricity supply pricing for National Grid customers for the period May 2013 to October 2013.

Fixed Basic Service Charge in ¢/kWh
May-October 2013
G-1: 6.827
Streetlights: 6.827

Fixed Basic Service Charge in ¢/kWh
May-July 2013
G-2, G-3 May: 7.208
G-2, G-3 June: 7.152
G-2, G-3 July: 7.119

Variable Basic Service Charge in ¢/kWh
May-October 2013
NEMA G-2, G-3:
May: 6.516
June: 7.448
July: 7.626

SEMA G-2, G-3
May: 6.495
June: 7.342
July: 7.583

WCMA G-2, G-3
May: 6.408
June: 7.336
July: 7.575

G-1 in all zones
May: 6.899
June: 7.347
July 7.6861
August: 7.354
September: 6.998
October: 7.030
Streetlights: 6.827

The complete DPU filing can be viewed here.

To protect your business from price fluctuations and obtain the lowest possible competitive pricing, contact Better Cost Control.

Natural Gas Prices – Rising

PEPCO rates in Washington D.C. to Increase 6% in June, 2013

Pepco, the electricity distribution company for Washington, D.C. posted its new summer rates for the period beginning June, 2013.

For General Service Non-Demand customers, the new rates will be as follows:

June – October: $0.08734 per kwh

November 2013 – May 2014: $0.08405 per kwh

At the time of this posting, commercial customers in Washington D.C. can definitely save money with a fixed price electricity contract.  To learn more, contact us.

Visit the PEPCO website.

What is a Load Profile and why is it Important?

A load profile defines how an electricity customer uses its electricity over time. It is created using measurements of a customer’s electricity use at regular intervals, typically one hour, thirty or fifteen minutes, and provides an accurate representation of a customer’s usage pattern.

Since this requires the use of expensive interval meters, for most customers utilities conduct load studies using interval metering on samples of customer groups or segments and use the results to represent the segment’s usage pattern. Unless you have an interval meter, your load profile, for electricity supply pricing purposes will be based on your Rate Code Average Load Profile and your month-by-month total usage.

A basic fact with electricity pricing is that prices are lowest at night and on weekends.  A fixed price is determined by creating a weighted average price for your electricity usage for each interval and the cost of electricity for that time period.  Since nights and weekends have the lowest cost, the more relative usage during these periods, the lower your average cost will be.

Let’s look at some examples:



This is an average residential load profile.  You can see that the usage peaks are between the hours of 5PM and 10PM, when people come home from work, watch TV, etc.  Usage then drops off, with the lowest point at 3:00AM.  You may say, “All my lights are off at that time!”.  Remember, these numbers are averages of all residential users.  Many are night-owls.  Some work second shift jobs.

What is important to understand is that this is the average load profile that is used when pricing residential electricity.  This graph will vary with your geography, since heating and air conditioning uses electricity, with difference kWH requirements depending on our weather.


This is the load profile for a Small Business customer.  Note that the maximum usage is between the hours of 8:00AM and 4:00PM.  This is when electricity is most expensive, so the average cost will be higher than a residential customer, in most cases.


Large Commercial Users will have an average load profile like this one.  Again, note that the maximum usage is between the hours of 8:00AM and 4:00PM, which is when electricity is most expensive.

The primary difference from the small commercial user is that there is a much more significant amount of electricity used during the peak periods.  As a result, the price will likely be higher than the small commercial customer pays, since the weighted average of usage by hour, will be skewed toward the peak hours.


This load profile is for a manufacturer that is operating with three shifts.

Note that their electricity usage varies very little during the entire 24-hour period.  From a supplier perspective, this is a very attractive load profile.  The high usage during the off-peak hours will help this customer obtain a much lower price, if they obtain a competitive supply contract.  If they do not get a contract, they will be short-changing themselves by not taking advantage of their preferential load profile to reduce their electricity costs.

In Summary, your company’s Load Profile has a major impact on your electricity price.  If you wonder why it is so difficult to simply call a supplier and get a price quotation the phone, this is one of the reasons.  Getting the best price for your electricity supply is more complicated than most people realize.  Just one more reason why an experienced broker can help you navigate the energy procurement process.



U.S. natural gas futures hit 17-month high as cold lingers

(Reuters) – U.S. natural gas futures rose to a 17-month high late Sunday as forecasts for colder weather and robust electricity generation boosted demand.

Front-month April natural gas futures on the New York Mercantile Exchange rose more than 2 percent to $3.965 per million BTU units in electronic trading, the highest level since October 2011, according to Reuters data.

Gas prices have risen about 25 percent over the past month as lingering winter weather across the country and bigger-than-normal draws from storage have tightened the typically well-supplied market.

New York Capital Zone Electric Rates Nearly Double in Jan and Feb 2013

Nimo Pricing

Electricity customers in the  National Grid NiMo Zone F (Capital Zone) have seen their rates skyrocket in Jan and Feb  from ~$0.06 to over $0.12 per kWh.

In the 2012 Tariff Filing Letter, the proposed action states that:

“The Public Service Commission is considering whether to approve or reject, in whole or in part, revised tariff leaves filed by Niagara Mohawk Power Corporation d/b/a National Grid (“Niagara Mohawk”) that would increase the Company’s electric and gas base delivery revenues by $130.7 million and $39.8 million, respectively, effective April 1, 2013, and make other tariff amendments and accounting changes.”

Customers in Upstate New York should understand that fixed rates are in the $0.055 to $0.065 range for 12 months.  You can completely eliminate price fluctuations by contracting your electricity supply instead of dealing with the volatility of monthly pricing.

To obtain a fixed price electricity price quotation, contact Better Cost Control.  We represent all the suppliers, so you can be assured of the lowest prices with the best contract terms.

New Jersey Electric Rates to Change

The NJ State Board of Public Utilities on Thursday approved the results of state’s annual electricity auction. It sets the wholesale electricity prices that the state’s electric utilities will pay and pass through to all New Jersey customers.

For three of the state’s four utilities, including Jersey Central Power & Light and Atlantic City Electric, there will be a  decrease in supply rates on June 1.  Rates for for PSE&G will be essentially the same.

Average JCP&L ratepayers will see a decrease of 3 percent; Atlantic City Electric customers will see a decrease of 5.35 percent and PSE&G customers will see their average rates increase by .05 percent.

The price of wholesale natural gas, which powers electric plants, is lower than in 2010. Since 2009, average energy costs for  small and medium-sized businesses have fallen about 30 percent, the BPU said.

But whether prices continue to fall in future years is unknown. “We have seen relative price stability in the last couple of years,” Hanna said. “What is going to happen in the future with natural gas prices is very difficult to predict.”  This is why fixed price contracts provide the opportunity to lock in long term fixed prices to protect from increases.

The value of both electricity auctions was about $7 billion, which represents approximately 8,700 megawatts of electric generating capacity.

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.