Energy Market Trend for April-May 2013

A month ago NYMEX futures broke out of their range and exceeded $3.60 per MMBtu for the first time in four months.  A month later those prices look like a bargain as prompt month gas futures have broken $4.20 for the first time since July 2011.  Why?  The primary reason was the weather as March was COLD.  Heating demand depleted storage inventories to levels not seen since the last time that gas was over $4.10 – no coincidence there.  But the long-term picture is a bit different and not as grim.   Gas futures for 2014 are up significantly less than the near-term and 2015 and 2016 are down.  The bottom line is that the rally is being driven by near-term fundamentals while long –term prices have stabilized thanks to shale reserves resulting in a much flatter forward curve.  The detail is in the numbers below:

Prices as of 4/12/13        Change since 3/7/13

Prompt month natural gas           4.22                                        +0.64

12-Month Strip                                 4.37                                        +0.52

Calendar 2014                                   4.26                                        +0.15

Calendar 2015                                   4.27                                        -0.03

Calendar 2016                                   4.36                                        -0.09

($ per MMBtu)


Details on the Fundamentals:



The short story is that we had a winter this year while last year we did not.  Although nowhere near record cold, it was dramatically colder than the record warm winter of 2011-12.  And March was especially cold while last March was especially warm, so winter’s last gasp resulted in a strong surge of demand and storage withdrawals that stoked the market rally.  So now the market can breathe for a month and get ready for summer.  Early forecasts are calling for above normal temps as well as an above normal hurricane season.  But temps are tremendously difficult to predict this far out and storm direction is more important than count.  So for now, summer should be categorized as a critical and imminent point.

Natural Gas Storage :

The impact of weather on gas demand and gas prices is very evident through the trends in natural gas storage.  Over the last month we have seen the culmination of the gradual deterioration of the huge natural gas storage surplus that peaked in April 2012 at the same time that prices hit 10-year lows.  Storage inventories are now far below levels from a year ago and even below the 5-year average.  Here is the data:  current inventories equal 1,673 Bcf which is 804 Bcf or 32.5% below a year ago and 66 Bcf or 3.8% below the 5-year average.  The reduced inventories will result in additional summer gas demand to refill storage reservoirs in order to prepare for next winter.  This increase in demand pushes prices up for this summer and the possibility that we will go into winter with reduced inventories has increased prices for next winter.  But storage has limited impact on prices for the beyond next winter and this is a key reason that prices for 2015 and beyond have not been part of the recent rally.


Despite the rally, shale gas remains the dominant factor in natural gas prices.  Prices plummeted from 2008 to 2012 while crude oil prices eventually rebounded after the global recession.  And limits to recent price upside and the stickiness of long-term prices have clearly been partially attributed to the enormous shale gas reserves in the US.  At the same time, when the market found a bottom in 2012 and rebounded, one cause was producer reaction to low prices.  The market was just too low and drilling economics are likely to limit both upside and downside in prices for some time to come.  So while production remains strong, it has declined by close to 1 Bcf/day since the peak last November – an indication that producer did react to low prices of 2012.  But new estimates of US recoverable gas reserves were just increased by 20% to 2,384 (close to 100 years of supply at current usage levels) by the Potential Gas Committee, primarily driven by updated data for shale in the Eastern US including the Marcellus.  Although the economics of much of these reserves is uncertain, the amount certainly limits price upside.

Other Factors:

There are numerous other factors driving prices and most remain unchanged.  EPA regulations and LNG export both are highly likely to impact gas demand as soon as 2015.

In addition to impacts of trends in the NYMEX, both regional gas basis and regional power issues are driving power prices:

  • New England – winter gas basis volatility remains a hot topic with forward prices remain elevated as supply challenges due to pipeline constraints and reduced LNG imports expected to continue for the next several years.
  • New York – gas basis will get some relief thanks to pipeline expansions.
  • PJM – this market has seen the least volatility due to impacts of Marcellus shale, but capacity prices are changing significantly and are much higher for some parts of the ISO.
  • ERCOT – summer is around-the-corner and so are concerns about adequate reserves and risk of hitting the higher price caps.  Summer prices and heat rates are high.
  • California – Cap & Trade regulations have changed the market and uncertainty regarding generation from the San Onofre Nuclear Generating Station (SONGS) have ended California run of consistently low prices.

Market Outlook

The first question that we can answer with high confidence is that a repeat of the spring dip of 2012 is very unlikely to repeat.  The change in storage inventories from surplus to deficit is enough to prevent any such market crash.  Beyond storage, the market is “smarter” in 2013 by knowing the price points that require changes in supply and demand.  Power generator and gas producers behaviors have limited both upside and downside in the market.  This limits upside risk and this is apparent as long-term prices have stabilized, but also reduces chances for a big dip.  And the result has been an end to the seemingly never-ending prices declines from 2008 through 2012 and a flat price curve.

So what will trigger price spikes or buying opportunities?  Weather is critical as always, so watch out for the impact of summer heat and hurricanes.  It will be interesting to see whether producer activity picks up due to rising near-term prices.  And consumer demand from the industrial sectors has increased due to the US’s low natural gas prices compared to abroad.  The net effect is apparent in storage activity.  And key an eye on regional gas and power fundamentals and heat rates – watching the NYMEX alone is risky – ask customers in New England after last winter.

For the long-term, EPA regulations, LNG exports, Natural Gas Vehicles and the US economy will remain key drivers of the shape of the forward curve.

Fixed Price Customer Considerations

  • It is very difficult to buy in a rally and many customers are certainly frustrated as they have been waiting in vain for the supposedly “inevitabledip that the spring would bring.
  • Overall, higher prices are inevitable for most. It is possible that a dip is forthcoming, but targets from a month ago must be revised upward because any downward move before will be limited by the storage deficit.  Summer brings both potential risk and reward – so have a strategy to deal with both possibilities.
  • Budgets with year-over-year rate declines may be unrealistic depending on the timing of your previous contract and can result in undue risk by setting targets that are unlikely to occur.
  • Short-term contracts are a strategy to buy time, but do not recognize the possibility that current prices levels will be sustained or could move higher.
  • And long-term prices may still present a good value as they have risen much slower than the near-term.  And the flat forward curve provides opportunity for stable prices.

Consider Layering your contracts

  • Although they do not provide an escape from higher prices, products that allow layering have significant advantage during period of price strength by allowing initial layers to be utilized to mitigate risk with subsequent layers being utilized to take advantage of market dips, if they occur.
  • Hedging strategies will depend on both market fundamentals and customer risk tolerance.
  • Be careful of using prices from 2012 to form price targets except for final layers.
  • Even aggressive customers should be executing layers for the upcoming layers.
  • And initial layers should be considered if not already in place for 2014.
  • Recognize that the flat forward curve may provide significant value for layers into 2015.
  • Utilize seasonal layers to address regional concerns such as winter gas basis spikes in New England and summer price spikes in ERCOT due to heat.

 Customer message:  The overall message is actually the same as a month ago except that prices are higher and likelihood of a big dip in prices before summer has declined.  And this may be difficult for customers to accept since may have had consistent year-over-year declines since the peak of 2008.

    • Year-over-year declines in gas have stopped with 2012 likely being the bottom.
    • Range-bound gas behavior for the near-term with modestly higher prices possible for 2014.
    • 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.

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.



What is Index Pricing? Is it worth considering?

When most companies contract their electricity, they obtain fixed price contracts to hedge or protect their business from price fluctuations. In essence, they are paying a small premium for price insurance, providing the guarantee that their electricity price will not increase for the entire term of their contract.

But some companies are OK with some risk.  They believe that the energy markets are not likely to increase in price over the near term.  If this is what you believe, you might want to consider a variable or index priced electricity contract.  Your price will change month-to-month, but you will be buying exactly what the market charges.  This post is intended to educate you on a what can be a confusing subject.  Customers of some suppliers of index products might have been mislead by their sales people.  Our goal is to make sure that every customer understands exactly what their options are.

An Index Price Contract is based on the LMP (Locational Marginal Pricing) Index price, which is readily available by viewing the Independent System Operator (ISO) websites.  This is the wholesale price of electricity which changes every fifteen minutes.  Your price for the month will be based on how much electricity you use during every fifteen minute period of every day, times the LMP price for that fifteen minute period.


The process may seem complicated at first, but it starts with your Rate Code.  Your Rate Code tells the supplier what your Load Profile looks like.  A Load Profile defines how a customer uses its electricity every hour of the day and every day of the week for 365 days in the year.  Most businesses have the majority of their electricity usage between 8AM and 6PM.  Their weekend and night usage is typically lower.  So their load profile defines this.  A manufacturer running three shifts would have a very different load profile.

Your company may have an Interval Meter, which records your electricity in fifteen minute increments.  This data is used to create your Load Profile.  Most smaller users, with under 1,000,000 kWH/year of usage do not have an Interval Meter, so their load profile is defined as the average for all users in their Rate Code category.

Why is the Load Profile important?  Because with Index Pricing, you will be charged based on the LMP price for every fifteen minute period.



This graph on the right shows you what the Real-Time LMP price is, for this particular day in the ISO-NE zone.  The price you pay will be based on this information,

Now to an example:

  1. Assume you use 100,000 kWH in a given month.
  2. Your load profile can be used to determine how many kWH you use every fifteen minutes.
  3. Your kWH usage for that fifteen minute period is multiplied by the LMP price.
  4. A total for all the fifteen minute periods is added up.
  5. Finally, the ancillary charges are calculated and added to the bill.

Index Pricing has risk.  You will experience months with very low price, while other months will have very high prices.  On average, for a one-year period, you will likely save money.  But you must have the emotional comfort to understand that prices could fluctuate widely from month to month.  For this reason, Index Pricing is not usually for the small business customer, unless they really understand how it works.

For large electricity users, a Block and Index contract gives them the best of both worlds: you obtain a fixed price for a specified block of kWH usage and then pay the floating index price for the remainder.  This allows you to limit your risk exposure to rising prices (the block price) while benefiting from possible drops in prices with the index.

Finally, the chart below shows the Real-Time LMP price in MWH.  You divide the number by 1000 to calculate the per kWH price, before adding ancillary fees, which will add roughly $0.02 to the kWH price.  Please contact us if you would like to learn more about electricity and gas pricing option.


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.

Penelec Announces New Price to Compare

Electric Meter

Penelec’s Price to Compare is the total of the Generation Charge + Alternative Energy Portfolio Standard + Transmission Charge.  You can read the entire filing by clicking here.

The default service Price to Compare has increased for commercial customers, but decreased for residential customers, as follows

For the period March 1, 2013 through May 31, 2013

  • General Service (GS): 7.011¢/kWh
  • Residential (RS, RT): 6.975¢/kWh

Remember that the Price to Compare changes every three months.  You have no way of controlling your electricity costs without obtaining a competitive fixed price contract.  Contact us for more more information on electricity supply for your non-residential accounts.  Also consider the benefits of Renewable Energy Credits.

MetEd Announces New Price to Compare

MetEd’s Price to Compare is the total of the Generation Charge + Alternative Energy Portfolio Standard + Transmission Charge.  You can read the entire filing by clicking here.

The default service Price to Compare has increased as follows

For the period March 1, 2013 through May 31, 2013

  • General Service (GS): 7.921¢/kWh
  • Residential (RS, RT): 8.665¢/kWh

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.