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Natural Gas and Electricity Are Parting Ways – Part 2

In our last article, Natural Gas and Electricity Are Parting Ways – Part 1, we explored the weakening correlation between wholesale natural gas prices and electricity prices in the Mid-Atlantic.  While natural gas prices have fallen dramatically over the past seven years, and electricity prices have fallen as well, electricity prices have not fallen as far.  We discussed how this weakening relationship is, in part, a result of natural gas-fired generating units more and more often being dispatched before coal-fired units.  In this article, we look at the influence of capacity prices.

Capacity

The cost of energy delivered by a competitive supplier consists of several elements—generation, capacity, transmission, and ancillary services.  Costs to suppliers resulting from PJM’s energy auctions are reflected in competitive suppliers’ generation charges.  Competitive suppliers are also required to own or to reserve generation capacity.  PJM runs separate capacity auctions to place a price on this capacity.  These auctions establish capacity prices for each of the three consecutive future planning years.

Polar Vortex 

During the depths of the Polar Vortex of January 2014 (see What Does Volatility Look Like?), there were times when more than 20% of generation capacity in PJM was unable to respond when dispatched by the grid operator.  The grid operator then had to call upon non-economic (meaning more costly) resources to fill in, some of which also were unable to respond.  The grid came within a few thousand megawatts of brownouts, and prices soared to more than $2,600 per megawatt hour during some hours.

Capacity Performance

Clearly more reliable generation capacity was required.  PJM proposed, and the Federal Energy Regulatory Commission (FERC) approved, a change in regulation creating a new Capacity Performance product.  With Capacity Performance, PJM established new, more stringent requirements for generation regardless of weather conditions and system conditions, and also established onerous penalties in the event that generation does not respond when called.  Most generators bid their capacity again during two Transitional Auctions, for the planning years 2016/2017 and 2017/2018. As a result, due to this change in regulation, capacity prices have been reset higher for each of these two planning year periods.

The table above presents, for the 2016/2017 and 2017/2018 planning years, capacity prices that were originally established as part of Base Residual Auctions (BRA) and the new prices established as part of Capacity Performance (CP) Transition Auctions.

Additional investment was clearly needed in order to improve system reliability.  PJM’s strategy with Capacity Performance is, on the one hand, to provide generators “resources to invest in improvements in such areas as dual-fuel capability, securing firmer natural gas supplies and upgrading plant equipment,” while, on the other hand, imposing substantial penalties for non-performance.

These increased costs associated with Capacity Performance, which will be reflected in electricity prices, are unassociated with changes in natural gas prices and are another driver of the decline in correlation between electricity prices and natural gas prices.

Notes:

– Evelyn Teel contributed to this article

– Capacity prices and quote from PJM website

The Avalon Advantage – Visit our website at www.AvalonEnergy.US, call us at 888-484-8096, or email us at jmcdonnell@avalonenergy.us.  Please feel free to share this article.  If you do, please email or post the web link.  Unauthorized copying, retransmission, or republication is prohibited.  Copyright 2015 by Avalon Energy® Services LLC

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Natural Gas and Electricity Are Parting Ways – Part 1

In recent articles, we have explored the dramatic decline in natural gas prices over the past seven years.  See These Are Days To Remember and 10,000 Maniacs Were Right.

In the US Mid-Atlantic, natural gas and electricity prices have, over time, tended to move together.  While there has by no means been a perfect correlation between the two, the relationship has been strong.

Over the past 15 years, the coefficient of determination (R2) has averaged about 67% (see yellow line).  In other words, over this time period, 2/3 of the change in electricity prices can be explained by changes in natural gas prices.  More recently, however, the strength of this relationship has weakened and continues to weaken further (see red line).  Electricity prices have declined but not as precipitously as those of natural gas.

Why has this relationship weakened?  Two significant drivers relate to (i) dispatch order and (ii) capacity prices.

Dispatch Order

In scheduling energy to serve electricity users, the grid operator, PJM, utilizes a least-cost dispatch model.  PJM develops an expectation of projected system load on an hourly basis and then seeks bids from generators to supply energy to serve this load.  After bids have been submitted, for each hour, PJM accepts the lowest cost offers first and then works their way through higher price offers until sufficient supply has been cleared to match the projected load.  (There are a number of system constraints and complications that must be incorporated into the process, but this pretty much captures it.)  For each hour, the price at which the last megawatt-hour (MWh) clears sets the price for all the supply offers that clear in that hour.

For many years, the last generating units cleared were generally natural gas-fired units.  As a result, it has been these natural gas units that have set the price for electricity, leading to the strong link between natural gas prices and electricity prices.  A common understanding was that “as natural gas prices go, so go electricity prices.”

But now, low natural gas prices are leading to lower and lower supply bids by natural gas-fired generators, causing them to more frequently fall down the dispatch order and clear before coal-fired units.  Because of this, coal fired units are now more often becoming the marginal, or price-setting, units.  And, as a result, falling natural gas prices have not driven down electricity prices to the extent they once would have.

In addition to procuring energy, electricity wholesale suppliers must also own or procure capacity.  In our next article, we will look at how capacity costs influence electricity prices.

Evelyn Teel contributed to this article.

The Avalon Advantage – Visit our website at www.AvalonEnergy.US, call us at 888-484-8096, or email us at jmcdonnell@avalonenergy.us.  Please feel free to share this article.  If you do, please email or post the web link.  Unauthorized copying, retransmission, or republication is prohibited.  Copyright 2015 by Avalon Energy® Services LLC

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Natural Gas Market Update

The above graph looks at natural gas prices going back to January 1997.

Natural gas prices have retreated from the Polar Vortex bump and remain relatively low by historical standards.

The prices plotted above are not adjusted for inflation.  If they were in 2014 dollars, the left side of the curve would be more elevated.  In real dollars, today’s prices are lower than they appear on the graph.

Looking to the futures market, the effects of the Polar Vortex lingered into the summer over concern about whether or not there was sufficient supply of natural gas to refill storage after the dramatic drawdowns during January and February.

This is highlighted on the left side of the blue line above which plots the 36 month futures curve as of 4/29/14.  This curve is backwardated, meaning the months close in time were priced above the months further out in time.

The near dated months have since retreated as concerns about storage refill have diminished because of (a) greater natural gas production than expected, and (b) unusually mild summer weather reducing summer time electricity load and the related reduced demand for natural gas.

This is highlighted on the red line above which plots the 36 month futures curve as of 10/24/14.  The months closer in time have declined significantly with the December ’14 contract down $1.26/mmBtu or 25%.  The entire curve has declined as well, though to a lesser extent.   The futures curve is no longer backwardated.

The table above shows the simple average of the monthly prices of the 36 and 48 month forward curves as of 4/29 and 10/24.

Overall, the 36 month futures curve is down 14.7% while the 48 month curve is down 12.7%.

The graph above looks further ahead at the 60 month futures curve which indicates that the market expects prices to rise.

While the curve is upward sloping, five years into the future, natural gas is trading well below $5/mmBtu.

Summary:

Over the past six months, market sentiment has swung from concerns that natural gas supply cannot keep up with storage injections – and upcoming winter demand – to the reverse.  Now the talk is more about an oversupplied market.  While there is low correlation between crude oil and natural gas prices, the recent decline in crude oil prices has contributed to overall bearish sentiment.  Generally, the best time to go long is when the market sentiment is most negative.  We may be approaching that point for natural gas.

The Avalon Advantage – Visit our website at www.avalonenergy.us, call us at 888-484-8096, or email us at jmcdonnell@avalonenergy.us.

Notes:

Please feel free to share this article.  If you do, please email or post the web link.  Unauthorized copying, retransmission, or republication is prohibited.

Copyright 2014 by Avalon Energy® Services LLC

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In The News – Avalon Energy Services

Avalon Energy Services recently completed an electricity procurement project for KBS Capital Advisors’ One Washingtonian Center property in Gaithersburg, MD.  Marc Deluca, Regional President of KBS, noted that “Electricity markets have exhibited extreme volatility.  The folks at Avalon Energy Services have deep expertise and an unsurpassed understanding of the energy markets and how they work.  With their advice and counsel, we were able to successfully navigate our way to a very positive outcome. “

Click here for the full story.

Avalon Energy Services also recently became licensed by the Pennsylvania Public Utility Commission to assist commercial, industrial and governmental natural gas customers in all of the natural gas distribution company service territories in the Commonwealth of Pennsylvania.  These are:

  • Columbia Gas of Pennsylvania
  • National Fuel Gas Distribution Corporation
  • PECO Energy Company
  • Peoples TWP LLC
  • Peoples Natural Gas Company, LLC
  • Peoples Natural Gas, LLC – Equitable Division
  • Philadelphia Gas Works
  • UGI Utilities, Inc.
  • UGI-Central Penn Gas
  • UGI-Penn Natural Gas
  • Valley Energy, Inc.

Avalon Energy Services is now licensed for electricity and natural gas in Maryland, Pennsylvania, New Jersey and the District of Columbia.

Copyright 2014 by Avalon Energy® Services LLC

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Capacity Factor – Part 2

In our previous article we looked at Capacity Factor and how it differs between nuclear generation and solar PV (photovoltaic).   We concluded that in order to generate the same amount of electricity as 1/3 of the capacity of the US nuclear generation fleet (33,042 MW), 154,760 MW of solar PV capacity would be required.  This is a result of the substantially different Capacity Factors of nuclear (90.9%) and solar PV (19.4%) and is summarized in the table below.

A reader asked how much solar PV capacity would be needed in order for solar PV to generate as much electricity as the entire US nuclear generation fleet.  As noted in the previous article, the current US nuclear generation fleet consists of 100 operating units with a combined capacity of 99,125 MW which, during 2013, produced 789,016,510 MWh of electricity.

In order to calculate the amount of solar PV capacity needed, we can rearrange the Capacity Factor formula we used last time as follows:

Solving for the solar PV capacity needed to supply the same amount of electricity as the US nuclear generation fleet, we arrive at the following:

Capacity (MW) = 789,016,510 MWh / (19.4% x 8,760 hours/year)

Capacity (MW) = 464,280

In summary, 464,280 MW of solar PV capacity would be needed in order for solar PV to generate as much electricity as the entire US nuclear generation fleet.  This is 365,155 MW more than the existing 99,125 MW of installed nuclear capacity and is summarized in the table below:

As noted in our previous article, solar PV, like other sources of electricity generation (nuclear, wind, coal, natural gas, geothermal, biomass, etc.) comes with a set of tradeoffs.  Each source has its own strengths and weaknesses.  The focus here is simply on Capacity Factor.

The Avalon Advantage – Visit our website at www.avalonenergy.us, call us at 888-484-8096, or email us at jmcdonnell@avalonenergy.us.

Notes:

Data from the US Energy Information Administration

Evelyn Teel contributed to this article.

Please feel free to share this article.  If you do, please email or post the web link.  Unauthorized copying, retransmission, or republication is prohibited.

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Capacity Factor

In a recent article in the Energy Law Journal, the authors state,

By as early as 2016, installed distributed solar PV capacity in the United States could reach thirty gigawatts (GW).  If that forecast is on track, distributed solar generation will have increased from less than one GW in 2010 to the equivalent of nearly one-third of the nuclear generating capacity in the United States in less than a decade.1

Is the comparison to “one-third of the nuclear generating capacity” meaningful?  Could the amount of solar PV (photovoltaic) generation output expected to be available as early as within two years be equivalent to one-third of today’s nuclear generation output?  The short answer to both questions is “no” and the reason is that nuclear and solar generating facilities have substantially different Capacity Factors.

What is Capacity Factor?

Capacity Factor is the ratio of the actual output of an electricity generating unit over a time period to the unit’s maximum possible output over the same time period.  This ratio expresses the extent to which a unit is, or is not, operating at full output.  A high Capacity Factor, say 80% or 90%, indicates that a generating unit is operating close to “full out,” whereas a low Capacity Factor, say 20% or 30%, indicates that a generating unit is operating well below its maximum capability.

More specifically, Capacity Factor is defined as follows:

For example, a 500 megawatt (MW) unit that generates 2,187,500 megawatt-hours (MWh) of energy during the course of a year has a Capacity Factor of 50%, calculated as follows:

Capacity Factor = 2,187,500 MWh / (500 MW x 8,760 hours/year)

Capacity Factor = 50%

Why don’t generating units operate at 100% Capacity Factor?

There are many reasons.  All operating equipment must be backed off periodically for maintenance.  Mechanical failures and accidents lead to unscheduled outages.  The individual economics of each unit lead to them being called upon more or less under grid operators’ economic dispatch models.  Wind and solar units are physically constrained by how frequently the wind blows and the sun shines.

US Nuclear Generating Fleet

The current US nuclear generation fleet consists of 100 operating units with combined capacity of 99,125 MW which, during 2013, produced 789,016,510 MWh of electricity.  The overall Capacity Factor of the nuclear generating fleet is therefore:

Capacity Factor = 789,016,510 MWh / (99,125 MW x 8,760 hours/year)

Capacity Factor = 90.9%

Analysis

The Energy Information Administration (EIA) reports that during 2013, the average Capacity Factor of solar PV in the US was 19.4%.

Over the same time period, 99,125 MW of nuclear capacity, with its 90.9% Capacity Factor, generated 789,016,510 MWh of electricity:

Going back to the opening quote, one-third of the nuclear generating capacity in the United States” is 33,042 MW, which was responsible for 263,005,503 MWh of electricity:

Given Solar PV’s much lower Capacity Factor, 33,042 MW of solar PV capacity would generate only 56,152,330 MWh of electricity, or 206,853,173 MWh (78%) less than the output of the same amount of nuclear capacity:

In order to generate an equivalent amount of electricity as 33,042 MW of nuclear capacity, substantially more solar PV capacity would be required:

In other words, in addition to the 33,042 MW of solar PV capacity projected to be online by as early as 2016, another 121,718 MW of solar PV would be required in order to generate the same amount of electricity as 1/3 the output of the nuclear generation fleet:

Is the amount of solar generation expected to come online in a decade equivalent to one-third of today’s nuclear generation capacity?  No, and the reason is that nuclear and solar generating facilities have substantially different Capacity Factors, 90.9% versus 19.4%, respectively.

This is a challenge solar PV faces.   The nuclear industry increased its capacity factor from 50% during the 1950s to what it is today through operational improvements.  The capacity factors of coal and natural gas units vary based on their individual economics and their dispatch merit.  Solar PV is bounded by the physical limits of when the sun shines.

The purpose of this article is to take a recent quote and use it as an opportunity to explain Capacity Factor.  Solar PV, like other sources of electricity generation (nuclear, wind, coal, natural gas, geothermal, biomass, etc.) comes with a set of tradeoffs.  Each source has its own strengths and weaknesses.  The article is meant simply to look at Capacity Factor.  Other tradeoffs will be the subject of future articles.

The Avalon Advantage – Visit our website at www.avalonenergy.us, call us at 888-484-8096, or email us at jmcdonnell@avalonenergy.us.

Notes: 

1Elisabeth Graffy and Steven Kihm, Does Disruptive Competition Mean a Death Spiral for Electric Utilities?, Energy Law Journal, Volume 35, No, 1, 2014.

Data from the US Energy Information Administration.

Evelyn Teel contributed to this article.

Please feel free to share this article.  If you do, please email or post the web link.  Unauthorized copying, retransmission, or republication is prohibited.

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What Does Volatility Look Like?

This article looks at how cold weather led to great volatility in real-time wholesale electricity prices during January 2014 in the PJM Interconnection (PJM).

The month of January 2014 was the coldest in decades in the US as a Polar Vortex pushed its way into the Midwest, South, and East.

Winter electricity use in the Mid-Atlantic generally exhibits a daily bi-modal pattern, with morning and evening peaks.  The graphic below shows total PJM load during the 24 hours of January 22, 2014.

Because of the exceptionally cold weather on that day, during the morning and afternoon, real-time electricity prices were elevated, averaging about $350 per megawatt-hour.  During the evening peak-demand period, as a result of the shutdown of the Calvert Cliffs Nuclear Power Plant’s two units, prices rose even more substantially.  The two nuclear units, located on the western shore of the Chesapeake Bay in Calvert County, Maryland, together represent more than 1,700 megawatts of installed capacity.  The outage was described by the facility’s owner, Constellation Energy Nuclear Group (now part of Exelon Corp), as the result of an electrical malfunction on the non-nuclear side of the plant.  Regardless of the side of the plant on which the malfunction occurred, real-time prices in the transmission-constrained Potomac Electric Power Company (Pepco) and Baltimore Gas and Electric (BGE) Zones rose dramatically, for about a five hour period, reaching $1,890.70 per megawatt-hour in the Pepco Zone and $1,896.94 per megawatt-hour in the BGE Zone.

The table below presents real-time prices in eight of the twenty PJM zones at 2050 (8:50 PM).  Real-time prices are shown in megawatt-hours ($/MWh) and kilowatt-hours ($/kWh).  A map of all of the PJM Zones is presented at the end of this article.

The grid operator, PJM, had been calling on demand response all day during January 22.  The average demand response price (Average DR Dispatch Lambda) rose to $835 per megawatt-hour at hour 1759 (5:59 PM) as shown below.

During January 23, 2014, as both the bitterly cold weather and the Calvert Cliffs outage continued, prices remained elevated, especially so in the constrained Pepco and BGE Zones.  The table below presents real-time prices in eight PJM zones at 2030 (8:30 PM).

The contour map below shows real-time prices exceeding $550/MWh across all of the PJM zones at hour 2255 (10:55 PM).

The average demand dispatch prices reached $1,000/MWh at the same time.

The following day, January 24, with the Calvert Cliffs outage continuing, real-time electricity prices exceeded $2,600/MWh in the Dominion Zone during the morning peak at 0705 (7:05 AM).  Real-time prices previously set a record of $2,450.54/MWh in the Dominion Zone on January 7, 2014.

Less than two hours later, at 0850 (8:50 AM), due to a transmission constraint, a small portion of northern central West Virginia experienced negative prices while prices on the western side of PJM continued to exceed $200/MWh and on the eastern side exceeded $600/MWh.

Real-time price volatility continued within PJM in even more dramatic ways.

At 1700 (5 PM) on January 27, real-time prices in the Pepco Zone spiked to $545.08/MWh while real-time prices in almost the entire Dominion Zone dropped below zero to minus $80.45/MWh as shown on the price contour map below.

This volatility is shown on the graph and table below.

Volatility occurred not only in the real-time market but also in the day-ahead market.  On January 28, day-ahead prices averaged about $600/MWh as shown here…

…while real-time prices averaged less than $400/MWh…

Putting This Into Perspective

For comparison, real-time wholesale prices in PJM averaged $31.21/MWh during 2012.  The peak high price of $2,680.21/MWh that occurred in the Dominion Zone on January 24, 2014 represents an 86-fold increase compared to the average.  This is not an 86% increase but a multiple of 86 increase.  This is the equivalent of walking into a convenience store to buy a gallon of milk and having the clerk tell you that yes, they do have milk, but because of current market conditions, they have to charge you $343 for a gallon.  Comparisons to other everyday items are presented below:

The low price of minus $80.45 per megawatt-hour that occurred during January 27, also in the Dominion Zone, represents a 2.6-fold decrease compared to the average.  This is the equivalent of walking into a Starbucks and having the barista inform you that they have coffee, in fact too much coffee, and they will pay you $5.16 to take a cup away.  Comparisons to other everyday items are presented below:

Conclusion

Wholesale electricity prices are volatile—more volatile than the price of virtually any other commodity.

The volatility of electricity prices during January 2014 shows how much risk purchasers of index electricity products take on. In a related fashion, it also shows how much risk retail energy providers take on when they do not effectively hedge their load.

It is likely that some retail energy providers will not survive this period of volatility.    

For more on how electricity prices in the PJM Interconnection area can be affected by weather and other events, please see:

What Does an Extended Cold Spell Look Like?

What Does a Cold Day Look Like?

What Does a Superstorm (Sandy) Look Like?

What Does a Derecho Look Like?

What Does a Warm Day Look Like?

What Does an Earthquake Look Like?

PJM is divided into twenty load zones.  These zones are color coded on the map below:

The Avalon Advantage – Visit our website at www.avalonenergy.us, call us at 888-484-8096, or email us at jmcdonnell@avalonenergy.us.

Note:  Data and graphs from PJM.com

Please feel free to share this article.  If you do, please email or post the web link.  Unauthorized copying, retransmission, or republication is prohibited.

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What Does an Extended Cold Spell Look Like?

This is a follow up to our blog posted Monday evening titled “What Does a Cold Day Look Like?” and looks at the impact on real-time wholesale electricity pricing of extended cold weather.

We reported that as a result of Winter Storm Hercules barreling through the Mid-West, Mid-Atlantic and Northeast last Thursday and Friday (January 3 and 4), real-time wholesale electricity prices in the  PJM territory were elevated and volatile, ranging from negative prices to $739.70 per megawatt-hour ($/MWh) or $0.74 per kilowatt-hour (kWh).  For comparison, we noted that real-time wholesale prices in PJM averaged $31.21/MWh or $0.0321/kWh during 2012.  We also noted that during times of extremely cold weather, consumers pull out all of the stops.  Air circulation equipment runs longer and electric resistance heating kicks in.  The result is increased usage and high prices.

Moving ahead to Monday and Tuesday, January 6 and 7, the weather remained bitterly cold and the Polar Vortex moved further south.

The difference during this later two day period was that thermal mass (such as building foundations and walls, and the ground itself) had largely dissipated any retained heat.  The result was an increase in the amount of energy required to heat buildings and homes.

From 7:50 PM to 8:25 PM on Monday, January 6, real-time wholesale electricity prices exceeded $1,000/MWh across the entire PJM grid.  As an indication of how far south the cold spell reached, the peak price for the day of $1,238.77, which occurred at 8:10 PM, was in the East Kentucky Power Coop Zone.

Below are PJM real-time prices and system load during the 24 hours of Monday, January 6.

On Tuesday, January 7, real-time wholesale prices exceeded $1,000/MWH from 6:40 AM to 11:55 AM and then again from 5:30 PM to 5:55 PM.  Prices peaked in PJM at 7:15 AM at $2,450.54/MWh.  This occurred in the Dominion Zone.

Below are PJM real-time prices and total system load during the 24 hours of Tuesday, January 7.  Peak system load was reduced significantly by voltage reductions, voluntary customer conservation, and the implementation of demand response.  PJM reported 38,000 MW of generation outages.  Additional electricity supply was imported from two other RTOs – NYISO and MISO.

The table to the left below summarizes the PJM peak real-time wholesale electricity prices over the past four weekdays and shows the 2012 PJM total system average for comparison.  The table to the right shows the PJM total system peak demand which, at 141,483 MW on Tuesday, 1/7/14, represents a new PJM winter record.  The previous winter peak, which was about 5,000 MW lower, was set on 1/5/07.  The all-time system summer peak of 158,450 MW occurred during the summer of 2011.

For more on how electricity prices in the PJM Interconnection area can be affected by weather and other events (i.e., an earthquake), please see:

What Does a Superstorm (Sandy) Look Like?

What Does a Derecho Look Like?

What Does a Warm Day Look Like?

What Does an Earthquake Look Like?

Post Script – A reader in Connecticut sent us the following image indicating that it is also what an extended cold spell looks like:

The Avalon Advantage – Visit our website at www.avalonenergy.us, call us at 888-484-8096, or email us at jmcdonnell@avalonenergy.us.

Note:  Data and graphs from PJM.com

Please feel free to share this article.  If you do, please email or post the web link.  Unauthorized copying, retransmission, or republication is prohibited.

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What Does a Cold Day Look Like?

In previous blog posts, we have examined how weather and other events affect electricity prices.

What Does a Superstorm (Sandy) Look Like?

What Does a Derecho Look Like? 

What Does a Warm Day Look Like?

What Does an Earthquake Look Like?

We continue this series by looking at how electricity prices in the PJM Interconnection area can be affected by cold weather.

Winter Storm Hercules brought snow and cold temperatures to the northeast United States on Thursday and Friday, January 2 and 3, 2014.

Because of heavy cooling loads, electricity usage and wholesale electricity prices in the PJM area during the summer tend to be substantially higher than usage and wholesale prices during the winter.  Most air conditioners are powered by electricity whereas much of the winter heating load is carried by natural gas and, to some extent, fuel oil.  However, during times of extremely cold weather, consumers pull out all of the stops.  Air circulation equipment runs longer and electric resistance heating kicks in.  The result is increased usage and high prices.

The map below shows real-time wholesale electricity prices at 5:40 PM on January 2.  As is typical, electricity prices are higher in the eastern part of PJM (PJM-East), where most of the load is located, than in the western part of PJM (PJM-West), where most of the generation is concentrated.  Real-time prices differences in PJM are a result of the costs associated with transmitting electricity from generating facilities (source) to load (sink) and the related line losses.  On the map, the price scale in the bottom left corner of the map is in dollars per megawatt-hour ($/MWh).

The east-west differentiation in prices is dramatic.  The table below shows prices in dollars per megawatt-hour ($/MWh) and dollars per kilowatt-hour ($/kWh) for six delivery zones.  For comparison, real-time wholesale prices in PJM averaged $31.21/MWh or $0.03/kWh during 2012.

Summer electricity prices also tend to be substantially more volatile than winter prices.  But, extreme weather, hot or cold, can drive price volatility and at times, winter prices can exhibit strong volatility.  Below is a dramatic example.  While prices in North Jersey (PSEG Zone) were high, around $500/MWh, prices in West Virginia and western Virginia were negative.

This was a result of transmission constraints brought about by the heavy demand in PJM-East and the inability of many coal fired generating plants in PJM-West to ramp down quickly.  In other words, while there was great demand for electricity in PJM-East, there was temporarily insufficient transmission capacity to move electricity from west to east.  These transmission constraints developed more quickly than generation in PJM-West was able or willing to curtail their output.  The result was that, rather than receive revenues for their output, generators had to pay to deliver their energy into the system.

After a continued day of volatile prices, by 11:35 PM electricity prices had moderated significantly over the entire grid.  As shown on the graph below, prices had fallen to the $20/MWh to $40/MWh range.

However, Friday, January 3 brought more cold temperatures…

…and more volatility.  At 2:05 AM on Friday, January 3, less than three hours after the snapshot above, prices spiked, exceeding $700/MWh in northern New Jersey.

During the remainder of Friday, prices continued to exhibit a strong East-West differentiation…

…but showed some periods of quiescence:

…as well as across the board extremely high prices:

The graph below shows real-time prices throughout the entire day:

This graph shows PJM total system wide load over the day.  Peak demand was 128,611 MW.

The Avalon Advantage – Visit our website at www.avalonenergy.us, call us at 888-484-8096, or email us at jmcdonnell@avalonenergy.us.

Note:  Electricity price data and graphs from PJM.com.

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Real Electricity Prices (Energy Prices Always Go Up, Part 5)

This article is part of an occasional series that examines the common perception that energy prices always go up.  We have examined both electricity prices (read here and here) and natural gas prices (read here and here).

An article published recently by CNSNews.com states that, according to the Bureau of Labor Statistics (BLS), “The price of electricity hit a record for the month of October” and that “Americans now pay 42 percent more for electricity than they did a decade ago.”  Sounds scary.

Is it?  Let’s see.

Here, in graphical form, are the October US City Average electricity prices, in dollars per kilowatt-hour (kWh), as found on the BLS website.

During the period of time from 2003 to 2013, October electricity prices rose from $0.093/kWh to $0.132/kWh, a 41.9% increase.

It is important to note that the data above are in “nominal” dollars and do not account for the effects of inflation.  Over the time period examined, the purchasing power of a dollar has declined, so the electricity prices presented above are not being compared on a consistent basis.  In order to make the data consistent, we can normalize it by adjusting for inflation by converting the data to “real” 2013 dollars.  Another BLS dataset can help with this.

The BLS tracks changes in the purchasing power of a dollar through its Consumer Price Index (CPI).  The CPI can be used to convert dollar values from past years into inflation-adjusted dollar values for the current year.  For example, the 2003 electricity prices can be converted to 2013 dollars as follows:

Electricity Price 2013 = Electricity Price 2003 x (CPI Base Year / CPI Current Year)

Electricity Price 2013 = $0.093/kWh x (232.9/184.0)

Electricity Price 2013 = $0.118/kWh

The graph below shows the nominal electricity prices presented above along with the same data converted to real 2013 dollars:

The 42% increase on a nominal basis equates to only a 12% increase in real dollars.  Not quite so scary.

Looking further back in time, how have electricity prices behaved in nominal and real terms?

The graph below shows October electricity prices from the same BLS dataset for the period of time 1979 to 2013.

Over this period, October electricity prices have increased from $0.053/kWh to $0.132/kWh, a 149.1% increase.

The graph below shows the same data converted to real 2013 dollars:

In real 2013 dollars, October electricity prices have DECLINED from $0.170/kWh to $0.132/kWh.  This is a 22.4% decline in real dollars.

Do electricity prices always go up?  In real terms, no.

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