Posted on Oct. 16, 2009

By Allen Brooks


In the last six weeks natural gas futures prices have jumped from a modern day low to nearly $5 per thousand cubic foot (Mcf) as commodity traders and investors started to cover their short positions in this fuel as the days moved closer to the beginning of the winter heating season. The jump in the gas price ends what has been an extended price slide that started back in summer of 2008 when prices were in excess of $13 per Mcf and early signs of the developing global recession emerged.

The traders and investors who have been covering their negative bets on natural gas prices have been motivated by signs the nascent U.S. economic recovery is gathering strength, especially among sectors such as automobiles and home construction that are large consumers of natural gas and its components as feedstocks for petrochemical materials. Additionally, there was the realization that the ratio of crude oil to natural gas prices, which at one point this summer stood at 27:1 (27.08) in contrast to the inherent energy- value ratio of 6:1, was way out of line historically and certainly unsustainable.

At the start of 2009, the oil-to-gas price ratio stood at slightly under 8:1 (7.94). It subsequently dropped in early January to the low so far for the year of 7:1 (6.79). Since that point the ratio has climbed steadily, reaching its peak on September 3rd. After falling to a recent low of 13.67, the ratio has bounced around due to volatility in both crude oil and natural gas prices, but it seems to be locked into a range of 14 to 15:1. The big question is with winter energy demand about to arrive will cold temperatures drive natural gas prices higher while at the same time crude oil prices remain stable, or possibly weaken further, given the continuing sluggish economic recovery?

Natural Gas Is Historically Cheap Even After Recovery; sources: EIA, PPHB

 When we look at the ratio of crude oil to natural gas prices for the past 15 years, it is interesting to note how the ratio has become more volatile and higher in recent years following almost a dozen years of a relatively stable relationship fluctuating around a 7:1 ratio as shown by the dark blue line from 1994 up until 2006 on the accompanying chart. The most recent years have demonstrated considerably greater price volatility between the two energy fuels. It appears the ratio averaged closer to 11:1 from 2006 through 2008. Volatility in the ratio has exploded in 2009. We have marked the low, high and current ratios with small red lines. It was this volatility and the extreme undervalued nature of natural gas that enticed more and more investors and traders into the commodity trade of the decade, which was to buy natural gas futures while at the same time selling crude oil futures. For significant parts of this year that trade didn’t work, but in recent weeks it has. Part of the success of the trade has been the calendar working against commodity traders who earlier in the year had sold natural gas futures with the expectation that gas prices would continue to fall. If they sold them early enough in the year, then they had profits locked in when natural gas prices started to climb. As time passes, bringing the start of the winter heating demand season closer, the impetus for higher natural gas prices strengthens. As a result, these commodity traders are now covering their short positions by buying near-month natural gas futures adding upward pressure to the gas price.

 If one looks at the current prices for physical deliveries of natural gas, there is almost a $1 spread between them and the current November futures price. If we average all the physical gas price points as of October 8th, contained in the Enerfax Daily schedule, it comes to $3.98 per Mcf. This is when the November natural gas futures price traded for $4.96, or a spread of $0.98. This spread is truly reflective of the near-term oversupply situation for natural gas and the optimistic demand outlook associated with the futures price.

 The nearly 100 percent increase in natural gas prices since the beginning of September seems counter-intuitive given the industry’s fundamentals. Natural gas storage facilities and pipelines are nearly all at full capacity forcing gas producers to involuntarily shut-in some of their current production. In other words, near-term industry fundamentals suggest the market should be experiencing weaker natural gas prices, which is consistent with the physical gas prices. On the other hand, the intermediate and longer term outlooks for natural gas demand point to higher prices in the future.

 The brighter over-the-horizon outlook reflects a universal belief that industrial demand for natural gas will recover with the economy and the recent growth in gas production volumes will slow and eventually reverse as the impact of the significant cutback in gas-focused drilling takes its toll on output.


Rigs Drilling For Gas Have Been Cut In Half; sources: Baker Hughes, PPHB

 From the peak in natural gas drilling activity, the gas-oriented rig count has been cut by more than half. In recent weeks the number of rigs drilling for natural gas has begun to rise. It is this rig count increase in the face of an essentially stable natural gas production level that has investors, commodity traders and industry people puzzled. While a simple graph of onshore natural gas production is showing a decline since late last year, overall gas production has remained relatively flat for the past nine months as production from the Gulf of Mexico has risen to offset the decline in onshore gas production.

 After dropping due to Hurricane Ike last September, Gulf of Mexico natural gas production has recovered and is now above the declining trend line that extends back to the start of 2005. In fact, current gas production is back to where it was at the start of the summer of 2008. The recovery and subsequent production growth of offshore natural gas helps explain why total U.S gas production has remained healthy in the face of weak prices for most of this year.

 What continues to be absent from the dynamics of the natural gas market is a sustained pickup in industrial gas demand. Increased heating-related gas demand is inevitable as winter arrives. The issue will be the amount of heating demand increase if other economically-sensitive gas demand remains dormant. A recent forecast by Matt Rogers of Commodity Weather Group suggests that the U.S. Northeast may experience its coldest winter in a decade due to the development of a weak El Niño in the southern Pacific Ocean region. Mr. Rogers point is that 75 percent of the time a weak El Niño develops, colder than normal temperatures are felt in this region of the country. Of course, there is a 25 percent chance that it won’t develop.

 When an El Niño develops, which it does periodically, the path of the upper atmosphere’s jet stream across North America is altered. Typically the alteration involves the jet stream dipping lower on the continent, i.e., shifting from Canada down into the United States, which allows Arctic cold weather to move further south than normally and into the Midwest and Northeast regions of the country. The challenge with predicting this jet stream shift is whether it becomes a more permanent shift during the winter months or only shifts occasionally.

 Even the Farmers’ Almanac is calling for a colder winter than in recent years for at least two-thirds of the nation. Importantly, that means more periods of bitter cold weather for two of the major populous regions of the U.S. That should boost natural gas demand. The one naysayer seems to be the Energy Information Administration (EIA) that is calling for heating bills this winter to be about 8 percent lower than last winter due to both milder temperatures and lower oil and gas prices. The EIA says it expects winter temperatures to average 1 percent warmer than last year – a sharp contrast to the independent weather forecasters. Maybe their forecast is tied to their view about the role of global warming. The real problem for the natural gas industry is that it really needs a recovery in industrial gas demand to help smooth out the industry’s supply/demand trends, and the latest government economic statistics suggest a mixed bag in that regard.

 So far this year, natural gas prices have fallen from $6 per Mcf at the start to a recent low of $2.50 before rallying back to $5 in recent days. These prices are a far cry from the $13-$14 per Mcf prices achieved in the halcyon days of the summer of 2008. The extended price decline, while partially explained by the fall in industrial gas demand, has largely been attributed to continued over-production of natural gas from the industry’s highly successful gas-shale drilling efforts that are spreading across the country. The growth in the past several years of natural gas production associated with these successful gas-shale developments reversed an eroding production profile for the industry that had existed for decades. The questions facing the industry now are whether gas-shale production will eventually overwhelm traditional natural gas drilling and production efforts and whether it is possible that the U.S. becomes a net gas exporter at some date in the future.

 To help arrest the growth in natural gas production and boost gas prices, producers have cut back their drilling activity by roughly 50 percent since last fall, but because gas-shale wells are so prolific compared to conventional gas wells, the drilling reduction appears to be having limited impact in slowing production growth. In the latest monthly data from the EIA’s industry survey, gas production does appear to be falling, at least on land. The challenge, however, is to try to decipher whether this production decline is real or involuntary.

 Natural gas storage as of September 25th was at 3,589 billion cubic feet (Bcf) out of an estimated industry-wide capacity of 4,000 Bcf. The problem is that natural gas storage facilities are spread around the country in the eastern and western consuming regions and in the gas producing areas. Additionally, there are limitations on the amount of natural gas that can be transported via pipelines from the producing regions to the consuming markets. As a result of these infrastructure limitations, the overall storage capacity ratio may not accurately reflect the true impact that high storage volumes are having on gas production.

 When we look only at industry-wide storage volumes plotted against total natural gas production, the surge in storage appears to be coinciding with a flattening, and now declining gas production.

 The level of gas storage volumes and the amount of injections shows even more clearly how the nearly full storage levels are impacting gas production.

 As total gas in storage has climbed to a record high, even after a roughly 100 Bcf of new storage capacity added, injection rates have fallen to low levels as there is little appetite or room for more gas. Some portion of the fall in current natural gas production has to be associated with involuntary production curtailments. The challenge is to determine how much of a fall-off is due to curtailments and how much is a fall in well productivity.

 To begin to look at this issue, we were provided data for monthly natural gas production in Texas. At this point we cannot vouch for its correctness, but we plotted it against the initial daily production by month for the state coming from the EIA’s Form 914 survey of gas producers. Lastly, we went to the Texas Railroad Commission web site and took only the 2009 monthly natural gas production data currently available, converted it to daily production figures, and plotted that data. The point of the exercise is to show that all these Texas natural gas production data sources are consistent in their pattern – steadily down. The interesting thing is to look at the shapes of the curves for 2009. The production data provided to us shows flat production for several months and then a steep decline. The EIA’s data shows a decline but at a more modest pace for all of 2009. The Texas Railroad Commission data shows a steady decline, but at a much faster rate than the EIA data. Unfortunately, these curves don’t answer the question: Is the decline due to falling natural gas well productive capacity, or is it a function of low prices, or is it due to involuntary cutbacks due to rapidly filling storage capacity?

 Since a lot of Texas natural gas tends to have higher finding and developing costs we suspect that some of the fall in gas production has been due to the weak gas prices. Producers must have been looking at their costs versus market prices and deciding to shut-in gas production. But some of the fall off in production has to be associated with older, less productive wells. Our guess is, however, that between these two explanations, the former is more important than the latter, but we cannot prove this conclusively.

 So while we wrestle to understand the current falling gas production figures, we are drawn back to looking at what the industry is doing with its drilling effort. The sharp fall-off in gas-oriented drilling rigs will eventually take a toll on production, but for the time being one has to be concerned about the recent uptick in the gas-oriented rig count before we know why production has fallen.

 At the same time, when we look at gas production compared to the number of rigs drilling horizontal wells, although we know not all rigs drilling horizontally are seeking natural gas, the strong upturn there could be a precursor of future gas supply challenges since the gas- shale wells, drilled horizontally, are so much more productive than conventionally drilled gas wells.

 The chart of gas production versus the total number of rigs drilling either directionally or horizontally shows a potentially less ominous supply challenge for the natural gas industry.

 The recovery in natural gas prices back to the $5 per Mcf level is certainly a positive for the industry. The latest production figures suggest that gas supplies are shrinking, but the weekly gas injection figures continue to reflect the impact of nearly full storage capacity. We can safely assume that gas production volumes are being reduced due to involuntary well shut-ins. What we don’t know is whether the industry is Wiley Coyote having run off the mountain road and is now suspended in air waiting to fall.

 Is natural gas production about to drop like a rock? Or is it possible we just need to get rid of some of the gas storage volumes with cold weather allowing producers to ramp back up their shut-in wells? That last scenario will come with current or higher winter gas prices. The former scenario suggests a natural gas price that rockets straight up. Unfortunately an exploding gas price will bring with it the seeds of the next price collapse.

 We reiterate our view that without a healthy economy the natural gas market will struggle to regain solid economic footings.

Our Perspective:

The market has presented great opportunites for companies to lock in their natural gas and electric prices in the deregulated market. Many of our clients have found unexpected savings.

Although the market has ticked up in the last couple of days, lack of demand have still kept the market price competitive from what you spent over the last 12 months.

If you have not looked into these opportunities, it still is not too late. Prices are dynamic and timing is everything.

Take the first step and ask the question, ” How much can we save?”

You might be surprised by the answer.

If you would like to know more about growing your bottom line from savings in the natural gas and electric market, feel free to contact us?

You may email or leave a comment and we will contact you.

There are no upfront fees and all the savings fall to your bottom line!

 Allen Brooks is a managing director at Parks Paton Hoepfl & Brown, a Houston-based energy-focused investment banking firm. This article previously appeared in the October 13 issue of Musings From the Oil Patch.


As reported in Philadelphia Inquire



HARRISBURG – Paying more than $4 a gallon at the pump may be bad enough, but Pennsylvanians should prepare for another painful pinch to the pocketbook.

In 2010, state-imposed rate caps on electricity prices are set to expire, and utilities are positioning themselves for massive increases. In some parts of Pennsylvania, depending on the provider, residential customers could have to pay an additional 70 percent or more.

Peco Energy, which serves most customers in Philadelphia and its suburbs, predicts it will raise rates by 20 percent starting in 2011.


Some state lawmakers say the pending spikes, little noticed by the public, will be equivalent to the biggest tax increase since the days of Ben Franklin.


Now a group of legislators is promising to take on the big utilities and push to limit the hikes in what could be an epic battle.


“Let’s get ready to rumble,” Sen. Jim Ferlo (D., Allegheny) told utility lobbyists in the audience of a news conference last week.


The looming confrontation dates to the mid-1990s when Harrisburg deregulated the state’s electric industry in the hope of saving consumers money by opening the market to competition.


In exchange for being allowed to bill customers for building costly power plants, utilities agreed to institute rate caps for electricity use.


The problem was that competition never materialized. The primary reason: It was too costly for utilities not already established in the state to come in and build plants.

Since then, large Pennsylvania utilities have reaped hefty profits despite the caps, and their stock prices have soared.


Once caps are lifted starting in 2010 for 85 percent of the state, those profits are expected to grow even larger, legislators argue.


Sen. Lisa M. Boscola (D., Northampton) called the pending rate hikes “the perfect storm that is coming,” and blamed “nothing but profiteering and runaway greed.”


She and other lawmakers, including Sen. Vincent J. Fumo (D., Phila.), have pushed legislation to tackle the matter for more than a year. One option they are advocating is extending the caps indefinitely. Another would cap rate increases year to year at the rate of inflation or 5 percent, whichever is lower.


But Peco and other utilities strongly oppose an extension, arguing that it could impose a major financial strain on them since they are now buying power at higher costs.

Such a move could “wreak havoc in the electric market and jeopardize service to customers,” said Mary R. Rucci, Peco’s director of communications.


Others say it would run afoul of the 1990s deal that created the caps. “Rate caps were never intended to be a permanent fixture,” said Terrance J. Fitzpatrick, chief counsel of the trade group Electric Power Generation Association.  He said that customers had reaped the benefits of the caps for years, and that now the bill was coming due.


Before deregulation, Pennsylvanians paid 15 percent more for their electricity than the national average, Fitzpatrick said. With the caps, those customers are paying 2 percent less than the average.


“Instead of seeing gradual increases, customers are going to see them all at once,” added Fitzpatrick, a former member of the Pennsylvania Public Utility Commission.

Instead of extending caps, utilities are advocating conservation and other programs to reduce customer bills. The industry is also pushing a compromise that would phase in the higher rates to smooth the transition.


“Everyone has the same goal,” Rucci said. “We need to work through this and determine the best solution for customers and also to allow the utilities to be healthy.”

Peco provides electricity throughout Philadelphia and Delaware County and much of Bucks, Montgomery and Chester Counties – 1.6 million customers in all. Electric rates for those customers are set to increase by 20 percent Jan. 1, 2011.


Consumers in other parts of the state would suffer even more pronounced kilowatt shock.

The 1.4 million customers in eastern and central Pennsylvania served by PPL Electric Utilities, including portions of the Philadelphia suburbs not covered by Peco, could see increases of 37 percent, according to the Pennsylvania Consumer Advocate’s Office. Bills for Allegheny Power customers in the western part of the state could spike 63 percent.

And bills have already shot up 75 percent for some Pike County Light & Power customers in northeastern Pennsylvania, where caps expired in 2006.


Peco’s planned hikes are less than others in part because it currently charges a higher rate for electricity.


Gene Stilp, a longtime Harrisburg activist and founder of Taxpayers and Ratepayers United, predicted the rate hikes would force businesses to move to other states in search of lower utility bills, costing Pennsylvania thousands of jobs.


“The gas crisis is nothing,” Stilp said. “It’s child play compared to what’s coming.”

Unlike ever-rising gas prices, state lawmakers say, electricity is a cost they can do something about, even in a marketplace that has been deregulated for a dozen years.

“This is Exxon in our backyard that we can control,” Fumo said.


But getting anything done on this issue in Harrisburg has been a struggle. Lobbyists and advocates on both sides have bogged down legislation. Even the parts of Gov. Rendell’s wide-ranging energy plan that dealt with the expiring caps stalled during this year’s budget process.


Legislators now pin their hopes on what they called the “outrage factor” that they are sure will come once word of the rate hikes sinks in.


“If we were to tell people that we were going to raise their taxes by $365 a year or more – and get nothing back for it – there would be an outrage,” Fumo said. “There would be a rebellion, and everybody would be up here yelling and screaming.”


Our Perspective:


This issue has been simmering for several years in PA. Instead of allowing the providers to recoup their cost over a period of years, a cap was put on the price of electricity the providers could charge. Add this projected price increase to the fact that demand is projected to grow 1.5% a year for the next 8 – 10 years and the utilities will have difficulty meeting the growing demand.


Could you picture rolling brown outs!


What do you think the response will be from the general public if we are told that is their solution to meet growing demand?


Gov Rendell sees this issue brewing and is looking to establish an incentive package that will have Businesses and homeowners look to Clean Energy Alternatives. Like other states in the area ( NJ ), PA is looking to reduce demand by 20% by the year 2020 and explore alternative resources to help meet the growing demand.


You can be your own provider!


How would you like to get paid for producing electricity?


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