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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

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Real Energy Cost Savings

Below are the results from a sampling of reverse auctions conducted for Avalon Energy Services’ customers, including customers of varying size, over the past few months.  The first graph shows the customer’s annual energy costs before competitive bidding (blue line) and after contracts were executed on accepted bids (red line).  Pre-auction annual energy costs ranged from $0.7 million to $9.6 million, while post-auction costs ranged from $0.5 million to $5.6 million.

This translates into savings from about $0.2 million to about $4.0 million per year, as shown on the graph below:

Annual savings on a percentage basis are presented in this third graph and range from 27% to more than 40%.

Of course, past performance is not necessarily an indicator of future results, but in our experience, a well-executed and carefully managed reverse auction will achieve the most advantageous results for a customer.  The key is to use a skilled energy consultant who can effectively analyze your needs, customize a solution, and successfully use competition among suppliers to bring about the optimal energy procurement outcome.

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 blog.  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 During a Heat Wave

PJM operates two markets for energy, the Day-Ahead (DA) Market and the Real-Time (RT) Market.

PJM’s Day-Ahead Market is a forward market in which hourly LMPs (locational marginal prices) are calculated for the next operating day based on generation offers, demand bids, and scheduled bilateral transactions.

PJM’s Real-Time Market is a spot market in which current LMPs are calculated at five-minute intervals based on actual grid operating conditions.

How do the two markets relate?  Let’s use July 19, 2013 as an example.

During the day before (July 18), load serving entities (electric distribution companies and retail energy providers) submit to PJM their electricity usage forecasts for their load during July 19.  These forecasts, provided in one hour increments, together represent the aggregate PJM demand forecast for the delivery day, July 19.

Also, during the day before (July 18), electricity generators submit to PJM offers to supply energy during the delivery day, July 19.  These offers, also provided in one hour increments, together represent the total pool of supply PJM has available to match supply to demand.  Offers are zone specific.

Through its “least cost” dispatch model, PJM then sorts through the generators’ offers, accepting, for each one hour period for the delivery day, the least expensive offers first and then incrementally more expensive offers until it has enough supply to meet the forecasted demand.

As a great simplification, offers for the hour ending (HE) 1400 in the ComEd Zone may have looked something like this:

Below is a sample of actual accepted offers by selected zone for the July 19 hour ending 1400:

The graph below shows the Locational Marginal Prices (or the highest accepted offers) for each of the 24 hours of July 19 by selected zone.  Note that the vertical scale spans $0 to $240.

Then, reality happens.  Despite the best efforts on the part of retail energy providers to project usage, actual demand levels vary.  The weather is cooler or warmer than expected, commercial and industrial facility activity levels differ from what was projected, transmission lines become congested, substations fail.

Forecasted and actual (instantaneous) demand for July 19 is shown below:

Demand for electricity within PJM peaked at 156,944 megawatts at hour 1420 (2:20 pm).

During the delivery day, when actual demand is greater or less than what was procured in the Day-Ahead Market, energy is purchased or sold in the Real-Time Market to instantaneously match supply and demand.  Prices in the Real-Time Market during the hour ending 1400 were as presented below.  Note that in some zones the Real-Time price is higher than the zonal Day-Ahead price while at the same time, in other zones, the Real-Time price is below the Day-Ahead price.

Prices in the Real-Time Market over the full 24 hours of the delivery day of July 19 for select zones are presented below.  The vertical scale now spans $0 to $500.

Because prices are set every five minutes, prices in the Real-Time Market are more volatile than in the Day-Ahead Market, where they are set on an hourly basis.

In the Mid-Atlantic, July 19 was the fifth day of a heat wave.

Below is a contour map of Locational Marginal Prices as of 1605 (4:05 PM).

Below are both Day-Ahead and Real-Time prices during July 19, presented on one graph.

During this day, Real-Time prices were often higher than Day-Ahead prices.  This is not always the case.  Below is a graph of Real-Time and Day-Ahead prices during July 17, 2013.

Notes:

– “PJM” refers to the PJM Interconnection, which is a Regional Transmission Organization and operates the electric transmission system serving all or parts of Pennsylvania, New Jersey, Maryland, Delaware, the District of Columbia, Illinois, Indiana, Kentucky, Michigan, North Carolina, Ohio, Tennessee, Virginia, and West Virginia.

– Surface Heat Index map from Plymouth State Weather Center.

– Other data, maps and graphs from PJM.

– 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 story.  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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Energy Prices Always Go Up (Part 4)

As discussed several times previously on this blog, there is a common perception that energy prices always go up.  We have examined both natural gas prices (read here and  here) and electricity prices (read here).

In this post, we look again at electricity prices—specifically, how they behaved in PJM last year.

PJM zonal day-ahead load weighted average Locational Marginal Prices (LMPs) averaged $50.92 per megawatt-hour (MWh) during 2010 and $45.19 during 2011, an 11.3% decline.  During 2012, this weighted average price dropped to $34.55 per MWh, a further 33.6% decline.  This is a stunning decrease and was driven primarily by the decline in natural gas prices.  Electricity and natural gas prices are strongly correlated in PJM as natural gas-fired generating units are generally the marginal units called upon in PJM’s least cost dispatch model.

LMPs vary significantly by zone, as shown on the graph below.

The change in average LMPs between 2011 and 2012 varied by zone but, in all cases, was lower during 2012.  The decline ranged from 19.4% in the Commonwealth Edison zone to 35% in the Atlantic City Electric zone.  A sampling of zonal price changes is presented in the table below.

The overall decline can also be seen in the further contraction of prices into the lower end of the frequency distribution shown below.

From January 2007 to December 2012, Day Ahead LMPs in PJM averaged $46.57 per MWh.  This corresponds to the period during which PJM has in place its capacity market model, referred to as its Reliability Pricing model (RPM).  Current LMPs are well below this average, as shown in the graph below.

The LMPs plotted above are in nominal dollars and do not take into account inflation.  The effect of inflation can be illustrated by increasing the right side of the red line relative to the left side.  In other words, in real dollars, the decline in electricity prices in PJM is more dramatic than shown.

Do energy prices always go up?  The answer remains “no” as it relates to electricity and natural gas prices.

The Avalon Advantage – Visit our website at www.avalonenergy.us

Copyright 2012 by Avalon Energy® Services LLC

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Avalon Energy Services Completes New Energy Supply Contracts on behalf of Donohoe Real Estate Services

BETHESDA, Md., May 14, 2013 – Avalon Energy Services, the Mid-Atlantic’s leading energy consulting firm, announced today that they successfully completed an electricity procurement for 19 commercial real estate properties managed by Donohoe Real Estate Services. The properties are located in Maryland and the District of Columbia.  Under the new contracts, the properties will save more than $1.5 million per year on electricity supply costs.

“We are pleased to assist the premier firm of Donohoe Real Estate Services in obtaining such great savings,” said Jim McDonnell, Chief Operating Officer of Avalon Energy.

Tim Gallagher, President of Donohoe Real Estate Services, noted “At Donohoe, we have a more than century long tradition of creating value for our tenants and our property owners.  Working with Avalon Energy has allowed us to further build upon this tradition.”

Avalon Energy Services, LLC (Avalon Energy) provides a range of energy consulting services to commercial, industrial, institutional, and government customers.  Services include consulting related to energy procurement, energy audits, demand side management, and the implementation of distributed generation and combined heat and power (CHP) applications.  Avalon Energy’s website is www.avalonenergy.us.

Founded in 1884, The Donohoe Companies is the oldest full-service real estate organization in the Washington, DC region and also one of the largest — ranked in the top 50 private companies in the metropolitan area.

Donohoe has invested billions of dollars in Washington’s premier office, hotel, retail, industrial, and residential projects.  In addition, Donohoe provides a full range of building management, brokerage, and maintenance services to major institutions, corporations, and associations.

Today, guided by a fourth generation of the founding family, Donohoe remains committed to the basic values of excellence, integrity, and customer satisfaction. The philosophy and tradition that has brought Donohoe over a century of success continues to be the foundation of their business approach — hard work, fair play, and the willingness to take reasonable risks with prudent provision for the future.   For more information, please visit Donohoe’s website at www.donohoe.com.

Contact:

Jim McDonnell                                                Kevin Furnary

Chief Operating Officer                                 Senior Consultant

Avalon Energy Services, LLC                    Avalon Energy Services, LLC

888-484-8096, ext 202                               703-868-5677

jmcdonnell@avalonenergy.us                   kfurnary@avalonenergy.us

The Avalon Advantage – Visit our website at www.avalonenergy.us

Copyright 2012 by Avalon Energy® Services LLC

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What Does a Superstorm Look Like?

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

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 Superstorm Sandy impacted electricity prices in the PJM service area.

After marching northward off the shore of the Atlantic coast, almost 1,000 mile wide Hurricane Sandy became Superstorm Sandy.  She made a sharp left turn and headed due west.  The eye of the storm, along with its tidal surge and 90 mile per hour winds, then made landfall in southern New Jersey around 6:30 PM on Monday, October 29, 2012.

The storm’s destructive winds caused extensive damage to property along its path.  This damage led to large and rapid reductions in electric load, first in New Jersey, the Delmarva Peninsula and New York, and soon thereafter, elsewhere in the Northeast.

As the storm approached land, the locational marginal prices (LMP) of electricity in the Mid Atlantic were about $40 to $50 per megawatt-hour.   After landfall, in the areas where the hurricane hit hardest in PJM – New Jersey and the Delmarva Peninsula – LMPs dropped dramatically and turned negative.  The image below is of a contour map of LMP prices in PJM at 9:10 PM on Monday, October 29.

The phenomenon of negative LMPs occurs from time to time, but is infrequent.  Negative LMPs rarely drop so far, across such a wide area, and for such an extended period of time as occurred here.  Negative LMPs even backed up into eastern and northern Pennsylvania.  The areas that were less affected by the storm, such as mainland Maryland and Virginia, maintained more normal LMP levels.

The graph below shows select PJM LMPs over the course of the entire day (midnight to midnight, Monday, October 29), before and after landfall of Superstorm Sandy.

Electricity prices remained fairly steady overall within PJM over the course of the day, with a peak occurring around 10 AM.  After the eye of the storm hit land, LMPs in the PSEG Zone (the largest electric utility in New Jersey) first spiked upwards and then turned negative for more than three hours.  At one point, LMPs in the PSEG Zone approached negative $400 per megawatt-hour (see pink line above).

System wide, load within PJM declined as the storm approached, landed and barreled into New Jersey, Delaware, Pennsylvania and New York.  This progression can be seen by the steepness of the change in instantaneous demand starting around 6 PM on the blue curve below.

Closer to the eye of the storm, in the Atlantic City Electric Zone (AE Zone), load began to fall off starting around 10 AM, continued to drop throughout the afternoon, showed some short lived recovery around 8 PM, and then fell precipitously thereafter.

Further north and west in New Jersey, in the Public Service Electric and Gas Zone (PS Zone), load similarly exhibited a slow fall off after noon and then a rapid decline starting around 6 PM.

In the Philadelphia Electric area, (PE Zone) load peaked at about 10 AM, slowly declined at first, and then also dropped off sharply starting around 6 PM.

The graph below shows the impact of Superstorm Sandy on the movement of power into and out of the PJM grid.  During most of the day, PJM was importing about 2,200 MW and continued to do so until about 10:30 PM when, the need for power greatly reduced, imports from adjacent grids fell dramatically.

The following day, Tuesday, October 30, LMPs were volatile and mostly positive as shown on the graph below.  This volatility was caused by the episodic restoration of generation, transmission lines, and sub-stations and distribution lines.

The overall decline in load PJM-wide and its subsequent slow recovery can be seen on the graph below.

This graph shows the AE Zone slowly recovering.

Load in the PS Zone also recovered slowly but in an even more sporadic manner.

Load recovery in the PE Zone followed a similar pattern.

Conclusion

The high winds, rain and tidal surge associated with Superstorm Sandy caused devastation to a large area of the Northeast.  Negative LMPs are generally short lived, transitory phenomena.  The magnitude of the initial damage caused by Superstorm Sandy can be seen by the highly negative LMPs that occurred over such a wide area, and for such an extended period of time.   This was a result of rapid decline of load and the inability of supply to be ramped down quickly to match the reduced level of load.

Notes:

– “PJM” refers to the PJM Interconnection, which is a Regional Transmission Organization and operates the electric transmission system serving all or parts of Pennsylvania, New Jersey, Maryland, Delaware, the District of Columbia, Illinois, Indiana, Kentucky, Michigan, North Carolina, Ohio, Tennessee, Virginia, and West Virginia.

– Satelite image from www.weather.com.

– Other data and maps from PJM.

– David White and Evelyn McDonnell 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.

Copyright 2012 by Avalon Energy® Services LLC

 

 

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What Does a Derecho Look Like?

Late Friday, June 29, 2012 a destructive set of thunderstorms swept through the Mid-Atlantic region.  With winds of up to 80 mph, the storms produced extensive damage and left several million utility customers without electricity.  The National Weather Service (NWS) refers to this kind of fast-moving, long-lived, large, and violent thunderstorm complex as a “derecho.”

On the NWS map below, blue marks indicate reports of damaging wind.  Black squares indicate winds over 75 mph.

The graph below shows PJM system wide load during the day of Friday, June 29, 2012, with demand peaking at 147,183 MW at 16:20 (blue line).  Late in the evening, you can see the drop off in demand resulting from the storm, with the most rapid decline starting around 22:00.

The map below shows LMPs at 23:45 on Friday, 6-29-12, shortly after the storms had passed over Washington, DC and Baltimore but had not yet reached their full intensity on the Delmarva Peninsula and in southern New Jersey.  LMP prices in the legend are in dollars per megawatt-hour.


On Saturday, 6-30-12, demand in PJM reached only 120,024 MW at 17:30 (see blue line below), a reduction of more than 27,159 MW, or more than 18% lower than peak demand the day before.

The graph below shows demand within the Pepco Zone during Friday, 6-29-12.  Demand in the Pepco Zone reached a peak of 6,592 MW at 16:30 and then slowly dropped to about 5,500 MW by 22:30.  Then the storm hit.  As the storm made its way over Pepco’s service territory, demand plummeted by 3,000 MW, or 45%, in less than one hour as much of the distribution system was damaged and service rendered inoperable.

The following day, Saturday, 6-30-12, demand in the Pepco Zone continued to decline until 07:00, when it reached a low of approximately 2,300 MW.  Later the same day, demand peaked at only 3,939 MW, a reduction of 2,653 MW or 40% lower than the prior day’s peak.  Note the different vertical scale on the graph below.

The story was similar in the Baltimore area.  Demand in the BGE Zone peaked at 6,852 MW during Friday, 6-29-12.  The storm hit the area around 22:30, after which demand plummeted over the course of about an hour from about 6,000 MW to about 3,400 MW.

The following day, demand in the BGE Zone peaked at only 4,291 MW.

The table below summarizes peak demand before and after the storm.  On Friday, 6-29-12, prior to the storm, peak demand in PJM was 147,183 MW.  The following day peak demand was 120,024 MW, a more than 18% decline.  However, it is important to note that there are factors other than the storm related outages that influenced the decline in peak demand, most notably the day of the week.  6-30-12 (the day after the storm) was a Saturday, and on weekends commercial load is generally lower.  In fact, the “day ahead” peak demand forecast for 6-30-12 (made before the storm hit) was 135,065 MW.  This is a more realistic reference from which to measure how much load in PJM was still offline 18 hours after the storm.  By this reference, load was off by 15,040 MW, or a substantial 11%.  The level of load reduction in the Pepco and BGE zones was much more significant.

The graph below shows locational marginal prices ($/MWh) over the course of the day of Friday, 6-29-12.  Prices peaked at $280/MWh during the late afternoon and remained volatile during much of the evening.  When the storm hit the major East Coast load centers at about 22:30, LMPs briefly sank to $0, recovered, and then diverged significantly as midnight approached.  LMPs in the Pepco Zone went negative as there was more supply than the now greatly diminished load.  Negative LMPs in a congested zone, such as the Pepco Zone, is a highly unusual phenomenon and is an indicator of how rapid and extensive the damage was during the storm.

The graph below shows a close up of this significant divergence:

Before June 29, few of us were familiar with the term “derecho.”  Now we know what one looks like.

Notes:

– “PJM” refers to the PJM Interconnection, which is a Regional Transmission Organization and operates the electric transmission system serving all or parts of Pennsylvania, New Jersey, Maryland, Delaware, the District of Columbia, Illinois, Indiana, Kentucky, Michigan, North Carolina, Ohio, Tennessee, Virginia, and West Virginia.

– Data and maps from PJM.

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

Copyright 2012 by Avalon Energy® Services LLC

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What does a warm day look like?

What does a warm day look like?

Here are several ways of looking at one particularly warm day – June 21, 2012.

The blue line on the graph below shows instantaneous electricity demand in PJM (see note 1).

Electricity demand ebbed to 88,367 megawatts at 4:25 AM and then began to rise as temperatures in the Mid-Atlantic climbed into the upper 90s.  Overall demand in PJM peaked at 145,331 megawatts during the late afternoon at 4:55 PM.

The graph below plots the Locational Marginal Price (LMP) for various zones and nodes within the PJM Interconnection footprint over the 24 hour period of time spanning 6 PM June 20 to 6 PM June 21.

LMPs don’t follow the same smooth path overall demand follows.

Generation is concentrated on the western side of the power grid and demand is concentrated in the East in the load centers stretching from northern New Jersey through Philadelphia and Baltimore to Washington, DC.  As a result, power generally flows from West to East through the high voltage transmission network.

The grid operator has many tools at its disposal to match supply to demand.  These tools include generation (base load, intermediate, peaking, and intermittent sources), spinning reserve, and demand response.  And, they need all of them.  As they match supply with demand, electrical, mechanical, and operational constraints intervene.  Generators trip.  Transmission lines reach their capacity.  Thermal limits become exceeded.  The sun and wind start and stop shining and blowing.  Load jumps up and down.  Because electricity cannot be stored in meaningful quantities, imbalances between supply and demand are reflected immediately in the price of electricity in the form of LMPs.

Looking again at the graph above, for almost half of the 24 hour period, LMPs ranged between $20 and $40 per megawatt-hour (MWh).  As temperatures rose driving up demand, the electric grid became more and more stressed, and LMPs became more and more volatile.

Peak prices occurred at 3:50 PM.  Prices at that moment averaged $105.11/MWH and were as low as $19.69 in the Commonwealth Edison zone and as high as $235.46 in the Jersey Central zone.  The table below shows LMPs at the same point in time for several zones.

Prices are considerably higher in the Eastern part of PJM, especially in New Jersey, reflecting the constraints associated with moving power into the area.

The maps below have overlain on top of them LMPs at various points in time during the day.  These LMPs are color coded and contoured by price.  Here is the price legend:

11:30 AM – Most of the grid between $26/MWh to $30/MWh (teal).  Northern New Jersey at $68/MWh (yellow).

1:15 PM – Higher prices expand west out of New Jersey into Pennsylvania and also down the East Coast, ranging from $68/MWH to $115/MWh (yellow and light brown).  Negative prices appear in southern Virginia (dark blue).  This excursion only last 10 minutes.

2:30 PM – Prices reach $250/MWh to $300/MWh in northern New Jersey (darker brown).

3:50 PM – $300/MWh to $400/MWh prices extend into Pennsylvania, northeast Maryland, and down the Delmarva Peninsula.  Chicago enjoys $20/MWh energy.

5:35 PM – New Jersey and most of Pennsylvania back to $56/MWH to $62/MWH range.  Locally, from Allentown to Philadelphia, prices are higher at $68/MWH to $76/MWh.

5:45 PM – Prices fall into the $34/MWh to $76/MWh range across the grid except for $200/MWh to $250/MWh excursion reaching in from the Southern Tier of New York.

The prices discussed above are wholesale prices.  For comparison, Pepco residential customers are currently paying 8.6 cents per kilowatt-hour (the equivalent of $86 per megawatt-hour) for electricity supply.  Of this amount, approximately 6 cents per kilowatt-hour represents the cost of energy ($60 per megawatt-hour).  By comparing, on just this one day, prices in the wholesale market to those in the retail market, one can get a sense of the commodity price risk wholesale electricity suppliers take on when contracting to supply customers with fixed price energy.

Notes:

– “PJM” refers to the PJM Interconnection which is a Regional Transmission Organization and operates the electric transmission system serving all or parts of Pennsylvania, New Jersey, Maryland, Delaware, the District of Columbia, Illinois, Indiana, Kentucky, Michigan, North Carolina, Ohio, Tennessee, Virginia, and West Virginia.

– Data and maps from PJM.

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

Copyright 2012 by Avalon Energy® Services LLC

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Natural Gas Prices – Time to Hit the Panic Button?

Over the last 25 days, the daily spot price of natural gas at the Henry Hub has risen more than 30%.  This is a dramatic percentage increase over a short period of time.  Is it time to hit the panic button?  No.  In short, the percentage increase is so large because the base has gotten so small.

There has been much reporting in the press recently about how natural gas prices are at ten year lows.  While this is accurate, it does not fully convey how truly low natural gas prices have fallen.  The graph below shows daily spot natural gas prices since January 1997.

Over this 184 month period of time, the daily spot price has been as high as $18.48/mmBtu (2/25/03) and as low as $1.05/mmBtu (12/04/98).  The median price was $4.37/mmBtu.

The cumulative distribution graph below shows these historical prices.

For each price point, the graph shows how often prices have been at this point or lower.  For example, prices have been at or below $18.48/mmBtu 100% of the time and at or below $4.37/mmBtu 50% of the time.

The recent 4/20/12 low of $1.82/mmBtu is highlighted on the cumulative distribution graph below.

Over the study period, daily spot prices have been at or below $1.82/mmBtu ONLY 2.2% OF THE TIME.  This is an infrequent occurrence by historical standards.

The 5/15/12 daily spot price of $2.38/mmBtu is now highlighted on the graph below.


Prices have been below this price only 17.4% of the time.  Thought of another way, prices have been greater than $2.38/mmBtu 82.6% of the time.

While daily natural gas prices have run up, they are still low.

Notes:

–          Data are from the U.S. Department of Energy , Energy Information Administration

–          Prices are in nominal terms and are not adjusted for inflation

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

Copyright 2012 by Avalon Energy® Services LLC

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Long Tailed Fish Swimming East

Markets adjust.  There are perhaps few better examples of that adage than the crude oil and natural gas markets.  One way of looking at how these two markets adjust is through the rotary rig count.  Baker Hughes keeps track of the number of active drilling rigs in the US (and also internationally).

Since July 1987, the number of active drilling rigs in the US has been as low as 488 (April 1999) and as high as 2,031 (September 2008).

The September 2008 rig count peak occurred three months after crude oil and natural gas monthly average prices peaked at $133.88/barrel and $10.28/mcf, respectively.  The rig count then followed the subsequent collapse of energy prices.  Crude oil fell to $39.09/barrel by February 2009 and soon thereafter, the rig count bottomed at 876 rigs in June 2009.  Since this bottoming in the rig count, the count has risen dramatically over the past three years to the current level of 1,945 active rigs.  The following graphs present historical monthly average crude oil and natural gas prices.

Baker Hughes also classifies operating drilling rigs by their primary target – oil or natural gas.  The rig count broken out by these two targets is depicted on the graph below.

Since the total rig count bottomed out in June 2009, the contributions to this total number between oil and natural gas directed rigs have changed significantly.  The number of natural gas directed rigs tracked the subsequent rise and fall of natural gas prices.  The number of crude oil directed rigs, however, has been on a one way track upwards, paralleling the sustained run up in crude oil prices.

Compared to the summer of 2009, today there are 52 fewer rigs exploring primarily for natural gas and 1,149 more rigs exploring for crude oil.

The graph below shows the active US crude oil and natural gas rig count on a percentage basis.

The change in focus from drilling for natural gas to drilling for crude oil has been a longer term trend, going back to the summer of 2005.  Seven years ago, about one in ten rigs were focused on crude oil.  Today, for more than two-thirds of the rigs, crude oil is the primary target.

So far we have looked at data back to 1987.  During this period, today’s count of 1,945 active rigs is close to the 2,031 maximum.  Looking back further in time, how does this compare?

Today’s total rig count is less than half the 4,530 rigs that were operating during late 1981.  Advances in drilling exploration techniques such as 3-D seismic, horizontal drilling and centralized drilling pads have increased success rates in exploratory drilling and increased drilling rig productivity.

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