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Maryland Renewable Energy Portfolio Standard (RPS) – Veto Override

Last week, the Maryland House and Senate voted to override Governor Larry Hogan’s 2016 veto of the 2016 Clean Energy Jobs bill.  As a result, Maryland’s Renewable Energy Portfolio Standard (RPS) will increase from 20% in 2022 to 25% in 2020.  The graph below shows the effect of the original RPS rule in blue overlaid with the newly amended rule in red.

Maryland’s solar “carve out” will increase as well as shown below.

Regulatory guidance is that customers with executed retail electric contracts in place prior to the effective date of the override are grandfathered from the additional RPS costs until the expiration of the grandfathered contract.

This is a good time to consider extending your electricity supply contracts to year 2021.

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

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 2017 by Avalon Energy® Services LLC

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Separate Paths – Part 2

By Ana Rasmussen, Intern

Our last blog post Separate Paths – Part 1 looked at how electricity distribution costs have been rising since 2008 and many of our readers have had questions about just why this is happening.  In order to explore this, and to try to get some answers, I dove in and analyzed seven years’ worth of Pepco electric bills from a representative home in Pepco’s Maryland service territory.  Before sharing my findings, I want to acknowledge that my base data is just from one household, which can be problematic for making generalizations.  However, the kWh rates for individual charges should be representative and similar for other residences in the area over these years.  I cannot account for differences in usage from one household to the next, but I believe this can shed some light on the larger shifts taking place within the utility cost structure.

First, once all of the data was collected and organized I looked at the percentages of the total bills that were from electricity distribution, transmission and generation.  As you can see in the charts below, a drastic transformation has taken place.  In 2009 distribution charges accounted for 24.6% of the total bill, but by 2015 it makes up 41.7% of it. The portion of the bill coming from transmission charges also more than doubles during this period resulting in generation’s share to fall to just over 50% of the total bill.  While generation’s portion of the bill has been falling, transmission and distribution have been on the rise since 2009.

Next, I decided to focus on distribution and breakdown the individual rates and charges included under distribution on the Pepco bills.  The four most important components of the distribution charge, and the way in which they are charged, are as follows:

Please note Pepco’s distribution energy charges are different from their generation energy charges.  Generation energy charges represent the cost of procuring energy for customers.  Distribution energy charges represent the cost of providing electricity delivery services to customers.  These distribution energy charges are billed on a kilowatt-hour usage basis.  So, while they are referred to as “energy charges,” they do not relate to the procurement of energy, only to the delivery of energy.

The customer charge is a flat rate charged once a month. Over this period, the charge has gradually risen from $6.65 to $7.39 a month. In the chart below you can see the yearly average rate for the other three primary components of distribution.  Although the Montgomery Country Energy Tax has fallen slightly since 2009, both distribution energy charge and Empower MD charge have risen.

Throughout this time period the average yearly distribution energy charge has been increasing, but to get a better understanding of it on a unit rates basis, I charted them by month. Below you can see how the rate falls in the winter months and rises during the summer months. Over the seven year period, the distribution energy charge has increased, on average, about 6.8% per year.  Also notable is the growing distance from peak to trough each year.

After an in depth look at seven years’ worth of residential Pepco electric utility bills, the shifts in generation, transmission and especially distribution have become more clear. Although far from perfect due to a lack of access a broader set of data, I hope that this analysis has been able to provide some insight on current trends and answer some of your questions.

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 2016 by Avalon Energy® Services LLC.

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Separate Paths – Part 1

By Ana Rasmussen, Intern

Since the shale boom began in earnest during 2008, natural gas prices in the US wholesale market have fallen dramatically. Prices have hovered within the 2 to 6 dollar per million Btu (mmBtu) range over the last few years, with the prompt month NYMEX natural gas contract trading at a remarkably low $1.70 mmbtu today. As we have been reporting for some time, wholesale electricity prices have also experienced a similarly dramatic decline, although that relationship has been weakening in recent months (see Natural Gas and Electricity Are Parting Ways – Part 1 and Natural Gas and Electricity Are Parting Ways – Part 2).  Given the decline in wholesale electricity prices, many of our readers have asked us why they have not seen a similar decline in their home electricity bills.

To answer this question we examined electric utility bills from a typical Maryland residence from the last 10 years and broken down the different charges included in the total cost. First, if you single out generation and transmission (G&T) charges during this time period, you can see in the graph below that they have been more or less in decline since the end of 2008. G&T charges represent the costs of producing electricity and of moving high voltage electricity from generation facilities to distribution lines.

However, this does not give us the whole picture. Our electricity bills are not only based on G&T, but distribution costs as well. As you can see below, while generation and transmission have been declining, distribution charges have actually been rising. Distribution charges include the costs of maintaining, expanding and improving the electric system to deliver electricity from high voltage transmission system to customers, homes and businesses, as well as the utility’s depreciation expense and return on rate base.  Other components of distribution costs include, but are not limited to, grid resiliency, environmental surcharges and county energy taxes.

Ultimately, simultaneously falling G&T charges and rising distribution charges are to blame for the lack of change in our electric utility bills at home, even with wholesale prices so low. In the final graph you can see the total utility bill charges have remained relatively stable as a result of this gradual cost shift from G&T to distribution over the last few years.

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 2016 by Avalon Energy® Services LLC.Blog 058 - image 04

 

 

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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

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.

Copyright 2014 by Avalon Energy® Services LLC

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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.

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 2013 by Avalon Energy® Services LLC    

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Day-Ahead and Real-Time Pricing in NYISO

We recently looked at the Day-Ahead and Real-Time electricity markets in PJM.  The New York Independent System Operator (NYISO) also operates a two settlement process with Day-Ahead (DA) and Real-Time (RT) markets, which are the subjects of this article.

First some background.

The NYISO, like only two other ISOs (CalISO and ERCOT), serves only one state.  New York State has a population of 19.6 million people, 8.3 million of whom  live in New York City.  NYISO recorded its maximum summer peak load of 33,939 megawatts during 2006 and its maximum winter peak load of 25,541 megawatts during 2004/2005.  NYISO is very dependent on natural gas as a fuel source and minimally dependent on coal.  The make-up of generation in NYISO is as follows:

The NY Control Area is broken up into 11 Load Zones, labeled A through K.  Across the state, electric power generally flows from west to east and from north to south.

New York Independent System Operator – Control Area Load Zones

Roughly a third of the load in NYISO is located in Zone J (New York City).  The next highest load areas are Zone K (Long Island) and Zone C (Central, which includes Syracuse and Ithaca).  The remaining eight zones account for less than 50% of the total load in NYISO.  See the tables below:

With so much load concentrated in Zones J (NYC) and K (Long Island), and with most of the electricity generation located outside of these zones, energy supply in these two zones is often constrained,   leading to higher pricing.  We will see this later.

The Day-Ahead market is a forward market in which hourly Locational Based Marginal Prices (LBMP) are calculated for the next operating day based on generation offers, demand bids, and scheduled bilateral transactions.  The Real-Time market is a spot market in which current LBMPs are calculated at five-minute intervals based on actual grid operating conditions.  The Real-Time market is also referred to as a “balancing market.”

The following analysis is based on NYISO hourly pricing data over the two year period ending June 30, 2013—a total of 17,544 hours.

The table below summarizes, by zone, hourly pricing in the NYISO Day-Ahead market.

Zones J (NYC) and K (Long Island) have higher average pricing and significantly higher variance in pricing than other zones, as highlighted by their maximum and minimum values.

The table below summarizes hourly pricing data for the Real-Time market.

Average pricing in the Real-Time market is about the same as in the Day-Ahead market.  However, the variability in prices in the Real-Time market is much greater across the board.  This stands out graphically as shown below.

The following graphs plot all 17,544 hourly Day-Ahead prices for both Zone A (West) and Zone K (Long Island).  The vertical scales are kept constant for comparison purposes.  The red lines on each graph are trend lines.        

And, the two graphs below plot all 17,544 Real-Time prices for both zones.

Another way to look at this volatility is to examine the standard deviation of prices.  The results are presented on the graph below.  Comparing Zone K to Zone A, Day-Ahead prices were 3.4 times more variable in Zone K and Real-Time prices were 2.4 more variable in Zone K.    

Separate from the level of volatility, especially in Zones J and K, average prices in all of the zones have fallen considerably in recent years.  Average prices in Zone J and Zone K are less than half what they were in 2008.     

Conclusions:

Real-Time prices are more volatile than Day-Ahead prices.

Zone J (NYC) and Zone K (Long Island) prices are more volatile than those of the other nine zones in the NY Control Area.

Notes:

– The New York Independent System Operator (NYISO) is a not-for-profit corporation that began operations in 1999.  The NYISO operates New York’s bulk electricity grid, administers the state’s wholesale electricity markets, and provides comprehensive reliability planning for the state’s bulk electricity system.

– Underlying data and the control area map are from the New York Independent System Operator.

– 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 2013 by Avalon Energy® Services LLC