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Crude Oil and Natural Gas Move to Different Hemispheres

On December 16, 2011, we looked at the relationship between natural gas and crude oil prices (see “Crude Oil and Natural Gas Get a Divorce” here).  We looked at how historically, on an energy equivalent basis ($/mmBtu), crude oil (West Texas Intermediate at Cushing, Oklahoma) traded at about a 50% premium to natural gas at the Henry Hub in Louisiana, reflecting crude oil’s greater energy density, portability, and flexibility.  We also looked at how, more recently, natural gas and crude oil prices had become decoupled and how the ratio of the price of crude oil to the price of natural gas had moved from the 1.5x historical multiple to, in December 2011, the astounding level of 4.9x.

What is the relationship now?   

From December 2011 to the end of March 2012, crude oil prices continued to rise, from $99.41/Bbl to $106.16/Bbl, while natural gas prices continued to decline, from $2.99/mmBtu to $2.17/mmBtu.  The primary drivers of these price changes have been the Iranian oil embargo (crude oil) and the US overhang of natural gas in storage.  The graph below shows monthly average crude oil and natural gas prices on an energy equivalent basis through March.

This continued divergence in price movement drove the energy equivalent crude oil/natural gas price ratio from 4.9x to 8.5x at the end of March, as shown on the graph below.

Where does the relationship appear to be headed in the future? 

As of April 13, 2012, the forward market expects the price of crude oil to rise over the next nine months, from $17.93/mmBtu ($103.64.Bbl) in May 2012 to $18.28/mmBtu ($105.64/Bbl) by January 2013, and then to decline.  At the same time, the market expects natural gas prices to rise from $1.98/mmBtu in May 2012 to $3.23/mmBtu over the same time period.  Expectations are that crude oil will fall to $15.81/mmBtu ($91.41/Bbl) by December 2017 while natural gas will continue to rise but remain under $5.00/mmBtu over that 68 month period.  These data are presented in table and graph format below:

The May contract prices for WTI crude oil and natural gas at $17.93/mmBtu ($103.64/Bbl) and $1.98/mmBtu, respectively, mean that crude oil is trading at NINE TIMES the price of natural gas on an energy equivalent basis.  From a historical multiple of 1.5x to 9.0x now, crude oil and natural gas not only got a divorce, they moved to different hemispheres.  Expectations are that this ratio will decline, but only to 3.2x by December 2017.

The graphs below show the (i) historical and forward price and (ii) relative relationship data on individual graphs:

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Copyright 2012 by Avalon Energy® Services LLC

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Avalon Energy Services Completes New Energy Supply Contracts on Behalf of Clarion Partners

Avalon Energy Services recently completed an electricity procurement process for five properties in Washington, DC owned by Clarion Partners, LLC. Under the new supply contracts, the five buildings will pay 27% less, in aggregate, than what they currently pay under existing contracts.  Avalon Energy Services’ press release related to this was picked up by a number of news organizations.  Read the full press release, as reported by NASDAQ OMX GlobeNewswire here.

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Natural Gas Prices Continue to March Down

March is the last month of the five month winter heating season.  As of March 30, the level of US working gas in storage was 2,479 BCF.  This is an increase during a time of the year when natural gas is historically withdrawn from storage, not injected.  The March 30 level is 927 BCF, or 59.7% greater than the average March working gas level of 1,552 BCF recorded over the previous five years.  The graph below shows the minimum, average and maximum levels of working gas in storage over the years 2007 through 2011 as well as the levels recorded so far during this year, 2012.

The graphs below show the January, February and March working gas storage levels compared to the average level over the period 2007 through 2011.

As seen in the table below, the volume of natural gas in storage continues to increase compared to the historical average.

Yesterday, the May natural gas futures contract settled at $2.09 per Dekatherm.

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Copyright 2012 by Avalon Energy® Services LLC

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Energy Prices Always Go Up (continued)

As discussed on this blog, there is a common perception that energy prices have been, and continue to be, on a one way path upwards.  In previous posts we focused on natural gas and showed that rather than rising, natural gas prices have, in fact, fallen dramatically, over both the short run and the long run (see here and here).

Electricity prices in PJM continued to fall last year as well.

First some background.  PJM is the independent electric grid operator in the Mid-Atlantic and parts of the Mid-West and is responsible for the reliability of the electric transmission system and, equally importantly, managing the market for wholesale electricity and related services throughout its operating territory (as well as into and out of PJM).  Below is a map of the territory PJM covers.

PJM has many pricing points individually referred to as locational marginal prices (LMPs).  LMP is the pricing mechanism for wholesale power in PJM.  LMPs vary by location when transmission congestion exists.  LMPs can be nodal or zonal.  Nodes refer to specific buses.  Zonal LMPs correspond to PJM transmission zones.  Energy prices are established in both the day-ahead and real-time markets.  When referring to LMPs over time, they are often presented as “average prices” or as “load weighted average prices.”  The later accounts for the amount of load at a node or in a zone during each hour over the total measurement period.  All in, PJM keeps track of over 10,000 LMPs.

So, back to the story.  During 2010, PJM zonal day-ahead load weighted average locational marginal prices averaged $50.92 per megawatt-hour (MWh).  This weighted average price dropped to $48.69 per MWh during 2011, a 4.4% decline.  LMPs vary significantly by zone, as shown on the graph below.

The change in average LMPs between 2010 and 2011 varied considerably by zone.  LMPs dropped about 10% in the PSEG and Pepco zones.  There were some exceptions to the overall decline in LMPs, such as in the AEP zone, in which the average LMP increased.  A sampling of zonal price changes is presented in the table below.

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

From January 2001 to the present, LMPs in PJM have averaged $55.81 per MWh.  Current LMP prices are well below this average, as shown on the graph below (in red).

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

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Copyright 2012 by Avalon Energy® Services LLC

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OFO (No Room at the Inn)

Huh? What does OFO mean? First, a step back.

The US natural gas pipeline and distribution system can be thought of as a large container with producers injecting natural gas (supply) and customers withdrawing natural gas (demand).  Last year, during 2011, the US consumed 24.4 trillion cubic feet (TCF ) of natural gas, or, on average, about 67 billion cubic feet (BCF) per day.

Interconnected with the US pipeline system is about 4 TCF of working gas storage capacity that is used to help balance supply and demand. Generally, natural gas is injected into storage during the summer and fall and withdrawn during periods of peak winter demand. Formation pressure from natural gas wells along with pressure added to the systems by mechanical compressors (driven by reciprocating engines and gas turbines) move natural gas through the pipeline and distribution systems. There are times when customers take more natural gas out of the pipeline and distribution network than is being injected by production wells or from storage. This can occur during prolonged cold spells and when surface equipment associated with production wells freezes over, for example. In these cases, the result will be a decline in system pressure. As system pressure drops, the ability to deliver natural gas to all customers diminishes. Systems operators have several tools available to manage pipeline pressure, including using “line pack” or also interrupting service to some customers. However, during extreme conditions, these tools may not be enough to maintain system pressure and operators may resort to an Operational Flow Order (OFO).

An OFO is an order to transportation customers and their suppliers that they together must keep the amount of natural gas they inject into the system within a tight limit compared to the amount of natural gas a customer burns. If injections for a customer fall below the threshold compared to actual burns, penalties are applied which, in the worst case, can be substantial.

So far, the 2011/2012 winter has not been very cold. Why, then, would a discussion of OFOs be of interest today?

On Friday, March 16, Delmarva Power (which operates a natural gas distribution system) issued an Operational Flow Order “until further notice.” This OFO was issued “due to warmer than normal weather conditions…and the inability to inject gas into storage.” So, here we are still in the winter heating season, when distribution companies are normally withdrawing natural gas from storage, and Delmarva has run out of storage capacity into which to inject natural gas. Rather than being concerned that system pressure will drop to an unacceptably low level, the concern is that system pressure will RISE to an unacceptably HIGH level.

Rather than being concerned that customers will withdraw more natural gas from their system than is delivered into their system, in their OFO, Delmarva indicates that “customers may deliver no more than one hundred and five percent (105%) of the volumes of gas tendered for burn by the customer on a daily basis, net of losses and unaccounted-for gas.”

Because deliveries are scheduled in advance (“nominated”) and because actual usage can vary significantly due to changes in weather and other factors, this is a tight threshold on a short cycle (daily) basis.

And what if a customer over delivers? Delmarva’s OFO states, “For all such … over-delivery volumes, a charge of THIRTY FIVE DOLLARS ($35.00) per MCF will be applied…” (emphasis added).

Currently, Delmarva’s commodity cost rate is $5.28 per MCF. This means the penalty is 563% of the cost of delivered natural gas. If you file your taxes late, you may be subject to a 10% penalty. If you deliver natural gas over the threshold into the Delmarva system, the penalty is more than SIX-FOLD the commodity cost of natural gas.

OFOs, when they are issued, occur during the winter. OFOs issued to ensure adequate delivery of natural gas during times of exceptionally cold weather do occur but are infrequent. OFOs, such as this one, issued during winter time to ensure that excess deliveries are not made are highly unusual. An employee of another East Coast natural gas utility indicated that over the company’s life, there has never been an OFO related to reducing system pressure during the winter time. The size of the penalties in the case being discussed here is a measure of how significant the current oversupply situation is.

What is driving this situation? Simply put, the combination of unusually warm weather this winter and diminished industrial demand for natural gas has created a large natural gas surplus. Normally, imbalances can be managed with storage. But, this year, there is no room at the Inn. Storage levels are far too high. There is nowhere for the natural gas to go.

Below are updates to two graphs presented in a previous blog post (

Natural gas storage levels remain excessively high. And, as noted previously, the gas cannot stay in storage until next winter because the reservoirs need to be cycled down. As we predicted, this “overhang” continues to keep downward pressure on natural gas prices. On Friday, the April 2012 natural gas futures contract closed at $2.33 per dekatherm (Dth) and the twelve month strip at $2.92/Dth.

The Avalon Advantage – Visit our website at, call us at 888-484- 8096, or email us at

Copyright 2012 by Avalon Energy® Services LLC

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Liquefied Natural Gas (LNG)

The development of a liquefied natural gas export trade was identified in a previous article as an influence that would put upward pressure on natural gas prices. To follow is an overview of where the US liquefied natural gas markets have been and where they may be headed. But first, what is liquefied natural gas?

At atmospheric temperature and pressure, natural gas (methane, CH4) exists in a gaseous state. When cooled to minus 260 degrees F, methane condenses into a liquid state. This liquid form of methane takes up approximately 1/600th the volume of methane in gaseous form and is known as liquefied natural gas or LNG. From a commercial perspective, the distribution of natural gas is limited to the pipeline network natural gas can be delivered into, whereas, because of its much greater energy density (70% that of gasoline), LNG can be transported in cryogenic tanks over long distances by specialized ocean going vessels.

How big is the LNG market in the US? The above graph shows the volume of LNG imports and exports into and out of the US over the twenty-six year period of time spanning 1985 through 2010. [Click on graphs to enlarge.] LNG imports became significant around the turn of the century, peaked at 770 billion cubic feet (BCF) during 2007 and then fell off as natural gas prices dropped precipitously during 2008. During 2010, the US imported 431 BCF of LNG. LNG export volumes have been minor, averaging 58 BCF per year.

During 2011, the slide in LNG imports continued as shown in the graph above, totaling 350 BCF (estimate).

How have LNG imports compared to overall US consumption? Consumption of natural gas in the US rose dramatically from 4,971 BCF during 1949 to 22,101 BCF during 1972, after which it fell to 16,221 BCF during 1986 and then rose to 23,775 BCF during 2010. Over the last 26 years, LNG imports as a share of total US consumption peaked at 3.3% during 2007.

How have LNG import volumes behaved compared to US natural gas prices? These two variables are presented together on the above graph. It is hard to tell much from this graph. We took the above data and lagged (shifted forward in time) the natural gas prices one month at a time and calculated the correlation between LNG import volumes and US natural gas prices.

The correlation is highest at 53.8% with a 19 month lag as shown on the left graph above. The graph to the right shows the same volume and pricing data with prices shifted forward 19 months.

So far we have looked at LNG import volumes. What about LNG export volumes? Since 1985, LNG export volumes have been minor, averaging 58 BCF per year. In the current low natural gas price environment (the February NYMEX futures contract settled at $2.32 on 1/19/12) this will change.

There are twelve LNG import terminals in the US (see table at end of article). Nine applications have been submitted to the Department of Energy seeking permits that would allow facilities to export LNG. Two permit requests have been conditionally approved. One is Cheniere Energy in Sabine, Louisiana and the other is Dominion’s Cove Point facility on the Chesapeake Bay.

Exports of 6 BCF per day, or 2,190 BCF per year, are equivalent to 9.8% of current US natural gas consumption. The nine facilities that have applied for export permits, together, seek to ship about 14 BCF of natural gas per day. If they are all successful, exports would grow to 5,110 BCF per year, or the equivalent of 22% of current US natural gas consumption.

This is a stunning change in the US LNG trade and will certainly create upward pressure on natural gas prices in the US. The range of estimates of the price increase impact of each BCF per day of exports, according to ICF, are from $0.02 to $0.30 per mmBtu. EIA’s estimates for each BCF of exports range from $0.07 to $0.17 per mmBtu.

The Avalon Advantage – Visit our website at, call us at 888-484- 8096, or email us at

Copyright 2012 by Avalon Energy® Services LLC

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How Low Can They Go?

How low can natural gas prices go? We may find out soon. First some background.

US natural gas demand varies considerably over the course of a year, driven primarily by natural gas usage related to heating. During peak winter months, natural gas demand exceeds the production capacity of North American natural gas wells. Natural gas can be stored underground in significant quantities in depleted reservoir, salt cavern, and aquifer storage facilities and called upon to meet demand during these peak winter usage periods.

The US underground natural gas storage infrastructure is extensive, as shown on the above map.

Natural gas is injected into underground storage facilities during periods of low demand and then withdrawn during times of peak demand. As natural gas is injected and withdrawn from these storage facilities, some natural gas must remain in the reservoir in order to maintain adequate pressure. This is referred to as “base” or “cushion” gas and is permanent inventory. Additional natural gas in an underground storage facility is “working” gas and is available to be delivered during higher demand periods.

The graph above shows monthly US natural gas base, working, and total storage volumes going back to September 1975. The injection and withdrawal of working gas is highly seasonal (red line) while base gas levels are much more stable (green line).

The above graphs show monthly US natural gas injections and withdrawals (gross and net), over the same 436 month time period. Both graphs are asymmetric along the horizontal zero axis. Over time, injections equal withdrawals. However, working gas is injected more evenly during non-winter time periods while withdraws occur much more quickly during the winter.

As shown on the above graph, natural gas is generally injected during the months of April through October and withdrawn heavily during December, January, and February.

Looking back over the past ten years, as shown in the table above, the US natural gas base gas level has remained fairly steady at about 4,300 billion cubic feet (BCF) while monthly working gas has varied considerably from a low of 730 BCF to a high of 3,851 BCF.

More recently, the US ended the year 2011 with 3,472 BCF of working gas in storage, 12.5% above the 3,087 BCF year-end average of the past five years.

At month end, January 2012, the US natural gas storage level stood at 2,966 BCF, 729 BCF (or more than 30%) higher than the five year January average of 2,237 BCF. This is significant.

Much lower than normal volumes of natural gas have been withdrawn from storage as a result of the mild winter so far, and the large amount of natural gas in storage represents a significant overhang of supply as the winter heating season winds down. What does this mean for natural gas prices in the near term? Unless February and March are exceptionally cold, short term natural gas prices are headed down.

Spot natural gas prices could be headed to sub $2 per million Btu (mmBtu) or even sub $1 per mmBtu levels. Liam Denning, writing in the The Wall Street Journal, recently suggested that spot natural gas prices could turn NEGATIVE. How can this be?

For operational reasons, natural gas storage reservoirs must be cycled. Working gas can be injected under pressure and stored for several months, but the natural gas must be periodically removed in order to reduce reservoir pressure and maintain the integrity of the storage reservoir. Storage operators levy stiff penalties if storage customers do not adhere to withdrawal schedules. Normally, this is not an issue for storage customers as their natural gas is withdrawn during the winter heating season. But at this point, it does not look like there is enough winter left for end users to need the large volume of natural gas in storage. And, the gas cannot stay in storage until next winter because the reservoirs need to be cycled down. So, in order to avoid penalties, storage customers may have to liquidate their positions during the spring when demand for natural gas is generally at its lowest, or during the summer time. This would drive spot market prices down. It is conceivable that prices could get down to zero, at which point storage customers may be motivated to pay someone to take their gas in order to avoid penalties.

The Avalon Advantage – Visit our website at, call us at 888-484-8096, or email us at

Copyright 2012 by Avalon Energy® Services LLC

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Natural Gas Price Drivers

We have noted previously on this blog that natural gas prices have declined dramatically over the last three years. On January 19, 2012 the February futures contract settled at $2.32 per million Btus. This is lower than natural gas prices have been in a decade and we are in the winter heating season, a time when prices generally rise. Adjusted for inflation, prices have not been this low since late 1998.

Looking ahead, the graph below shows the evolution of the twenty-four month natural gas futures curve over the last year and a half. It may seem counterintuitive, but as the futures curve has dropped it has remained upward sloping. In other words, as natural gas prices have declined, the market has continued to expect prices to rise in the future.

Several readers have asked what the major influences on natural gas prices are. Natural gas is very much a commodity and, as such, its price at any point in time is subject to the economic interaction of supply of and demand for natural gas. For our purpose here we have identified a number of influences and grouped them into those that create upward pressure on natural gas prices and those that will continue to moderate natural gas prices.

Influences that could drive natural gas prices upwards:

– Economic recovery
– Coal fired power plant shutdowns
– Greater industrial use of natural gas
– The development of a US LNG export trade
– More restrictive regulation of hydraulic fracturing (fraccing or fracking)
– Natural gas well shut-ins
– Decreased drilling for natural gas and the shift to more profitable oil basins

Influences that will continue to moderate natural gas prices:

– Further development of shale gas reserves, particularly the Utica Shale in the Appalachian Basin
– Drilling to hold onto mineral leases

This list is certainly not comprehensive but should serve as a good starting point. We will discuss these influences in this and future blog posts.

The Avalon Advantage – Visit our website at, call us at 888-484-8096, or email us at

Copyright 2012 by Avalon Energy® Services LLC

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Cape Wind

It was recently reported that a power purchase agreement between National Grid and Cape Wind was approved by the Massachusetts Supreme Judicial Court. National Grid is committed to purchasing half of the output of the project at a starting price of 18.7 cents per kilowatt-hour. This price will then escalate 3.5% per year for 15 years.

With this 3.5% annual compounding, the contract price will reach 30.3 cents/kWh in the fifteenth year. Over the term of the agreement, the average price from Cape Wind will be 24.1 cents/kWh. How do these prices for wind generated electricity compare to historical electricity prices in New England?

The above graph shows the daily price of electricity in NEPOOL over the period of time spanning 2001 through 2011 (blue line). NEPOOL is New England’s bulk electric power market. In New England, as is the case elsewhere, electricity prices exhibit considerable volatility. Over this eleven year period, daily electricity prices have been as high as 31.2 cents/kWh and as low as 2.5 cents/kWh, and have averaged 6.3 cents per kWh (red line).

Electricity prices in New England have been declining. Since the beginning of 2009, daily electricity prices have averaged 5.2 cents/kWh.

So, how does the cost of electricity from the Cape Wind project compare to historical prices in New England? In order to provide a visual sense, the two graphs above are reproduced below, each modified to have the same vertical axis scale. In both cases, the horizontal red line represents the historical average wholesale price of 6.3 cents/kWh.

Cape Wind’s website describes their project as consisting of 130 wind turbines that can produce up to 430 megawatts of electricity. Assuming a 25% capacity factor and the application of both the historical average NEPOOL price and the average Cape Wind contract price to the total projected output of the wind farm, the annual difference in cost is estimated to be $167 million.

The Cape Wind project represents a large, long position in what today is expensive electricity with a fixed escalator. This analysis is limited and does not reflect future price movements (up or down) in the cost of electricity associated with the existing and future fleet of generation in New England nor the environmental, social and operational costs and benefits associated with the existing and future fleet of generation and the Cape Wind project.

The Avalon Advantage – Visit our website at, call us at 888-484-8096, or email us at

Copyright 2012 by Avalon Energy® Services LLC

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Best Friends? – Natural Gas and Electricity Prices

We have looked at historical and forward natural gas prices. How have electricity prices been behaving?

The graph above shows the monthly average of electricity prices at PJM West (a trading hub where electric generation is concentrated) spanning the 131 month period of time of January 2001 through November 2011. Like natural gas, electricity prices peaked during 2008, declined, recovered somewhat, and then declined again. The relationship between electricity prices and natural gas prices can be seen better in the graph below:

Please note that in this graph electricity prices have been converted to cents per kilowatt-hour. When plotted together, electricity prices and natural gas prices seem to track closely, and the reality is that they are closely related. In the Mid-Atlantic, electricity prices and natural gas prices are strongly correlated. Natural gas fired generating units are usually the marginal units called upon by the grid operator and, as such, set pricing in the wholesale markets. So, generally in the Mid-Atlantic, as natural gas prices go, so go electricity prices.

While electricity price and natural gas prices tend to move together, the relationship between the two does change over time.

The graph above shows the correlation on a rolling 24 month basis. Over this period, the correlation between electricity and natural gas averaged 71% but has been as high as 97% and as low as 21%. The weakest correlation was during 2008, when natural gas prices moved upward more vigorously than did electricity prices. After having moving up to 97%, the correlation has been declining over the last two years.

In the above graphs, you can see how over the last two years, electricity prices have recovered more strongly than natural gas prices, leading to declining correlations between the two.

The Avalon Advantage – Visit our website at, call us at 888-484-8096, or email us at

Copyright 2012 by Avalon Energy® Services LLC