- Is It Possible To Have Sub $4/Mcf Gas For Five Years?
- Interesting Bits of Energy Market Data
- Energy R & D and Pet Food
- Cartoon Explains Cap-and-Trade Bill and Climate Change
- A Strange Case of California Energy Regulation
- Transport Fuel Future: Natural Gas Or Electricity?
- Economic And Energy Impressions From The Road
- Nat Gas Players And Farmers: Watching The Weather
Musings From the Oil Patch
August 4, 2009
Note: Musings from the Oil Patch reflects an eclectic collection of stories and analyses dealing with issues and developments within the energy industry that I feel have potentially significant implications for executives operating oilfield service companies. The newsletter currently anticipates a semi-monthly publishing schedule, but periodically the event and news flow may dictate a more frequent schedule. As always, I welcome your comments and observations. Allen Brooks
Two weeks ago we attended a presentation at the Petroleum Club where Jim Simpson of BENTEK Energy, LLC, a natural gas oriented analytics firm, presented his case for sub $4 per thousand cubic feet (Mcf) natural gas prices through 2010. His audience at the Houston Producers Forum consisted of 160 energy and financial executives. Following his presentation and in response to the first question from the audience, he dismissed the likelihood this distressed price scenario would last for 10 years as low gas prices did throughout the 1990s, but he did say it was possible the low price could last five years.
If that answer wasn’t depressing enough, he responded to the second question about the impact of Exxon’s Horn River gas discoveries in Canada on the U.S. market by saying he could not rule out the possibility of sub $3/Mcf natural gas prices for a period of time. Following the second question no one in the audience ventured another − possibly out of fear that they would be bidding down the estimate of future gas prices. Stop while you’re ahead seemed to be the mantra. As the moderator thanked the presenter, the shell-shocked audience began to drift out of the dining room. The only missing ingredient among the darkness of the room and the dark mood of the audience was a funeral dirge playing in the background.
Is it possible that natural gas prices might never recover to their lofty levels of earlier this year (five years is virtually a lifetime for most investors)? On the other hand, one can rightly ask: What does Mr. Simpson know? His is only a forecast and we know the spotty record of energy price forecasters. He did, however, bring some telling data and insights that must be considered, but in the end a forecast is a forecast and it depends on critical assumptions, one being that current market conditions and company actions continue as they have in the past, assumptions that become suspect when dealing with energy markets.
In light of the surge in unconventional natural gas production and weak demand fundamentals, natural gas prices have been depressed throughout 2009 despite crude oil prices rallying back to almost half of their historic high of last July. Mr. Simpson’s analysis examined changes in natural gas supply and demand and how successful development of the new unconventional gas-shale resources has created a significant oversupply that is depressing current gas prices. Part of the problem plaguing natural gas as Mr. Simpson pointed out is geography – the location of new gas supplies and gas consuming markets given transportation capacity limitations for moving the growing supply volumes.
Mr. Simpson explained the problem with a chart showing the total capacity of all pipelines out of the Southeast/Gulf Coast region that has been fixed at 23 Bcf/d for a number of years. He then showed how net pipeline outflows have grown over time trimming the un-utilized capacity each winter season. The production flows were defined as regional production plus inbound flows from other basins plus storage withdrawals and LNG imports minus intraregional gas demand and storage injections. From the winter of 2005-6 to last winter, the nominal surplus pipeline capacity has shrunk from 7.5 Bcf/d to 3.5 Bcf/d, or by more than half. As gas shale production in this region and/or LNG shipments continues to increase, we can expect a further shrinking of available pipeline capacity putting the brakes on supply growth. Will those brakes limit western gas inflows to the region, LNG shipments or gas-shale production growth?
Exhibit 1. Supply Up, Pipeline Take-Away Needs To Expand
Source: BENTEK Energy, LLC
In a nutshell, Mr. Simpson’s analysis is that falling natural gas demand coupled with rising gas supplies have placed gas producers in a box. The box is caused by a lack of adequate long-haul pipeline capacity in the geographic region spanning from East Texas to the Texas Gulf Coast and across Louisiana to Mississippi (an area referred to as an “I”). This capacity constraint restricts more costly gas supplies located west of the pipelines’ terminus points because the market is adequately served by cheaper gas volumes. Not only are more expensive western gas supplies fighting cheaper shale-gas production for access to the long-haul pipelines and the consumer markets in the Northeast, Midwest and Southeast regions of the country, but they also are competing with Gulf of Mexico gas and liquefied natural gas (LNG) supplies arriving from overseas markets.
Exhibit 2. Pipeline Capacity Crunch Is In Louisiana
Source: BENTEK Energy, LLC
Compounding the gas producers’ problem is that current natural gas prices are below finding and development costs for many of the traditional western gas basins, making it difficult for them to compete for markets. Gas-shale basins have evolved into real estate and engineering plays in contrast to exploration plays. The ubiquitous nature of natural gas shales in this country has reduced the need for exploration; witness the collapse of the open-hole wireline logging market in the United States. The key for gas-shale profitability is to assemble as much prime acreage (that which possesses the thickest gas seams that can be easily exploited) and figure out how to drill, complete and produce the wells at the lowest cost.
Another advantage for many of the gas shales is that they are located either within the pipeline “I” or immediately adjacent. This gives them a location advantage and reduces the transportation cost. In addition, some of newly developing gas-shale plays are situated east of the pipeline terminus points allowing them access as the lines move north or east. At the root of the supply problem, however, is that the gas-shale wells are proving to be highly prolific resulting in low gas costs, even below currently weak gas prices, which further encourages their development. The growth of unconventional gas supplies is slowly displacing conventional natural gas production in this country.
Producers of unconventional gas supplies have been successful in reducing meaningfully their finding and development cost in recent months. Some of the cost savings have come from the oversupply of oilfield equipment and services that has contributed to lower service company prices, while continued technological improvements in accessing and extracting the gas from these challenging formations have also contributed.
We have used several of the slides from Mr. Simpson’s presentation to further explain his argument. In addition, we have updated one critical slide he used to demonstrate the impact of development efficiencies for gas-shale producers. The key assumption in Mr. Simpson’s analysis is the fall in natural gas demand, which he estimates has shrunk by 1.9 billion cubic feet per day (Bcf/d). The recession-induced consumption declines among industrial and commercial customers and reduced gas use by residential users was offset somewhat by higher natural gas use to generate electricity.
On the supply side, Canadian natural gas imports into the U.S. are off by approximately 1.4 Bcf/d, while LNG imports are higher by 0.3 Bcf/d. Mr. Simpson estimates that domestic natural gas production is higher by 2.0 Bcf/d, which is consistent with most other estimates. The net increase in gas supplies of 0.9 Bcf/d, when combined with the 1.9 Bcf/d demand fall, means the gap between gas supply and gas demand has grown to 2.8 Bcf/d. That gap represents approximately 4.5% of annual natural gas consumption based on 2008’s total consumption of 23.2 trillion cubic feet, or roughly 63.6 Bcf/d. Can this gap be closed?
Exhibit 3. Weak Demand And More Supply Pressure Price
Source: BENTEK Energy, LLC, PPHB
In Mr. Simpson’s estimation closing this gap will prove difficult. The challenge is due to the rapidly growing output from gas-shale basins, which is driven by their low development costs. Mr. Simpson argues that based on data his firm has access to, which is essentially daily production flows into pipelines, despite the significant drop in gas-directed drilling, production has not fallen off commensurately. We have re-created the essence of a slide Mr. Simpson used that showed the total U.S. rig count versus production, which he defined as gross gas withdrawals. One difference is that we elected to use the Baker Hughes gas-directed rig count rather than the total rig count. If we simply used the Energy Information Administration’s (EIA) data on monthly gross gas withdrawals, our daily numbers came out much higher than on Mr. Simpson’s slide. We then removed the volume of gas the EIA says is used for repressuring fields. Since that data is published with a long lag time, we calculated the average daily re-injected volumes for 2006 and 2007 and applied this average to the gross withdrawal estimates. When we plotted the results, our gross gas withdrawal estimates for 2009 showed more volatility than Mr. Simpson’s chart.
One might argue the recent monthly gross gas withdrawal declines reflect production responses to the dramatic decline in gas drilling we have experienced so far this year. Others might see the monthly fluctuations as too modest to assume a trend change and thus argue that gas production is essentially flat. This was Mr. Simpson’s argument, and he said he based his conclusion on data his firm gets daily. Since we don’t have access to his data, or know exactly where it comes from, we cannot explain the discrepancy between the two charts. What we can say about our chart is that if production has begun a downturn, it required a huge drop in the gas-directed drilling to move the needle. Of course, it is possible the monthly data variations are the result of producers shutting-in gas production due to low prices.
Exhibit 4. Gas Supply Barely Responds to Rig Count Collapse
Source: EIA, Baker Hughes, PPHB
There were two other aspects to Mr. Simpson’s analysis about the lack of production response to the falling rig count. First was the drilling efficiency improvement impact on production growth. Secondly, the improved economics for gas-shale wells due to lower total development expenditures versus increased total production. Fewer wells and greater initial production, even with higher well costs, has translated into improved economics.
To demonstrate his point, Mr. Simpson showed a slide with data on drilling and production in the Fayetteville gas shale formation taken from the 10-Q reports of Southwestern Energy Company (SWN-NYSE) for the first quarter of 2007, the first quarter of 2008 and the fourth quarter of 2008. We have updated the data through the first quarter of 2009, which not only further supported Mr. Simpson’s observations, but also added some additional insight. A crucial point in the Southwestern Energy data is the dramatic reduction in the time required to drill the wells even as their average lateral length increased. Additionally, the wells are showing progressively greater average production during their first 30 days of operation.
The improved drilling performance has slowed the pace of cost increases for these Fayetteville wells. With dramatic improvement in initial production additions per rig per year, the improving profitability of these gas shale wells is clear and helps explain why producers such as Southwestern Energy are inclined to continue drilling these highly profitable wells.
Exhibit 5. Drilling Efficiency And Well Productivity Spur Supply
Source: Southwestern Energy financials, BENTEK Energy, LLC, PPHB
When one examines the data for the 30-day average production rate per well and the IP additions per rig per year, there was a noticeable decline between the fourth quarter of 2008 and the first quarter of 2009. Southwestern Energy explained this quarterly variance as due to the delay in the expansion of the Boardwalk Pipeline that caused the company to develop a backlog of finished wells that could not be hooked up upon completion. When the pipeline expansion was completed, Southwestern Energy commenced hooking up the backlogged-wells based on the wells’ productive volumes. Therefore, the 2007 fourth quarter benefitted from more high-flow-rate wells beginning production as some lower-volume producing wells drilled in the quarter were shifted into 2009 for hook-up.
To demonstrate this point, Southwestern Energy detailed its monthly well performance. The initial production for wells hooked up in January and February 2009 was around 2,800 MMcf/d in contrast to the March production rate that was in excess of 3,300 Mmcf/d and the estimated rate in April (based on data for the first half of the month) of nearly 3,800 Mmcf/d. When one annualizes the production gains it becomes clear that the historic trend in initial well productivity and the IP additions per rig per year would have continued had wells been hooked up as they completed during the fourth quarter of 2008 and the first quarter of 2009, rather than being shifted around.
Exhibit 6. Fayetteville Well Productivity Continues To Grow
Source: Southwestern Energy financials, PPHB
The main message from Mr. Simpson’s analysis is that the efficiency performance of gas-shale producers will keep them drilling and producing. The net impact is that their development costs are falling and, in many cases, are below current spot gas prices and certainly below the prices suggested by the forward strip for natural gas prices. These trends will continue to put pressure on the more costly western gas basins, especially when it comes to seeking pipeline access. Add into this mix the potential for additional LNG volumes at what can be very low prices and more Canadian gas imports as a result of that country’s storage capacity rapidly filling, we could see more downward pressure on natural gas prices.
Countering the negative forecast for natural gas prices, the analysts at Bernstein Research recently issued a report arguing that the base production of U.S. natural gas is declining at an annual pace of 30% in 2009. They believe that if the U.S. gas rig count remains flat for the balance of this year, gas production from December 2008 to December 2009 will be down by 10.5%, implying in their view a switch from an oversupply of 1-2 Bcf/d to an undersupply of 4-5 Bcf/d. Since they believe gas supply will decline sharply in the summer months, they expect gas prices to rise during the second half of 2009.
Exhibit 7. Low Cost Shales Pressure Higher Cost Gas
Source: BENTEK Energy, LLC
The firm’s analysis is based on measuring the increase in the annual decline rate for natural gas wells and the contribution to production from new well drilling. The challenge in any analysis of the natural gas market is to understand the contribution from the unconventional gas shales. The Bernstein analysis begins with the EIA’s chart showing the relative contribution to total natural gas supply in the U.S. from conventional onshore, unconventional onshore and offshore gas production. The growing contribution from onshore unconventional supplies is clear.
Exhibit 8. Unconventional Gas Supply Grows Rapidly
Source: Bernstein Research
When production is examined on an annual basis it becomes clear that the domestic gas industry is facing an accelerating decline rate. This means gas producers must either drill more wells per year, assuming they continue to find the same size producing wells, or they need to find wells with greater production. Therein lays the great attraction with the gas-shale reservoirs around the country.
Exhibit 9. Gas Production In U.S. On Accelerating Decline Path
Source: Bernstein Research
Next they demonstrated that gas supply in the U.S. has become a real-time drilling issue. The chart showing the percentage of gas produced from wells drilled in the previous three years clearly demonstrates that conclusion. In fact, the last two years show a sharp increase in the trend reflecting the explosion in gas-shale drilling and production.
Exhibit 10. The Gas Supply Drilling Treadmill
Source: Bernstein Research
Equally important to understand about gas-shale production is not only its significant initial well production but also its rapid depletion. As the Bernstein analysis shows, non-horizontal gas wells tend to have about 45% decline rate in the first year while horizontal wells experience about a 62% rate, based on the data for 2007 and 2008. This means gas producers are on a sharply upward sloping treadmill of drilling if they wish to sustain let alone increase production.
Exhibit 11. Horizontal Wells Suffer Faster Declines
Source: Bernstein Research
In order to estimate how much additional gas supply can come from drilling this year, the Bernstein analysts examined the contribution to 2007 gas supply additions by the type of well drilled. What their analysis showed was that vertical wells drilled the bulk of all gas wells drilled that year and added the greatest share of volume. What is noticeable about the data, however, is the relative contribution per well by the various wells drilled. Offshore wells added the most gas supply per well by a wide margin, but both horizontal and directional onshore wells contributed more than twice that of vertical onshore wells.
Exhibit 12. Vertical Wells Are Source Of Production Gains
Source: Bernstein Research
Using the 2007 gas volume contributions by well type, the Bernstein analysts then moved on to see how much additional gas supply could come from drilling activity this year. They assumed there would be no change to the current rig count for the balance of the year. They did assume that because of the industry downturn, rigs drilling this year would be more efficient and better prospects would be drilled. This led them to assume an increase in the wells per rig that would be drilled and in the average December contribution per new well. Based on those assumptions and analysis below, the Bernstein analysts calculate that there will be a 10.5% reduction in production between December 2007 and December 2009.
Exhibit 13. How Natural Gas Supply Will Fall In 2009
Source: Bernstein Research
We have one issue with the Bernstein analysis: why do horizontal land rigs and wells not experience the same improvements as the vertical and directional categories? If we grant horizontal the same improvement total December volumes are 58.05 Bcf/d, or only down 1.3% from the December 2007 volumes. That one change in assumptions makes a huge change in the conclusion.
The issue of the gas futures price trend recently has been highlighted by a growing debate over whether greater controls should be placed on the futures trading market in an effort to restrain “speculators” from driving prices higher. While the possibility of tighter regulations in the commodity futures market is mostly focused on crude oil, any changes in the regulation of traders will impact all U.S. commodity markets.
The U.S. Natural Gas Fund (UNG-NYSE), a mutual fund that enables individuals to invest in natural gas futures, has been
Exhibit 14. Gas Fund Argues Holdings Don’t Impact Gas Prices
Source: US Natural Gas Fund 8-K
questioned about its role in accentuating gas futures price moves due to its size. In a recent 8-K filing, UNG produced a chart showing the funds’ growth, i.e., increase in futures contracts held as natural gas futures prices have fallen. UNG is using this chart to help dispel government attempts to put more restrictive limits on the number of futures contracts that traders, i.e., the fund, can hold.
The larger issue raised by UNG’s price and holdings chart is whether the fund has actually supported natural gas prices at higher levels than they would have traded absent the fund buying activity. One clearly sees that the dive in natural gas prices seemed to stop when the fund began to expand and gas prices have moved higher and stabilized as the fund grew even more. There is little doubt that natural gas has become identified as the best fuel to bridge the transition in energy eras for the United States from one dominated by “dirty” fuels to one marked by “cleaner” fuels so it is reasonable to expect increased investor interest.
Exhibit 15. Natural Gas Is As Cheap As It Has Ever Been
Source: EIA, PPHB
So far this year, the disparity between the price-to-energy-value of crude oil to natural gas has been volatile, but for much of the year it has been above the average of the past 15 years. Today the disparity is at an all-time high. In expectation of increased demand for natural gas and the extreme price disparity, investors have embraced the “natural gas trade” – buy natural gas futures and sell crude oil futures. The heightened investor interest in this trade explains much of the UNG fund’s growth this year. Intuitively the growth of the fund has supported natural gas futures prices at higher levels than supply/demand fundamentals would support.
Natural gas pricing this year may have sent the wrong signals to the E&P companies who were making decisions about drilling gas wells. There might have been a swifter and deeper gas-directed rig count fall-off this spring if gas prices had fallen faster and farther than they did. At current prices, producers drilling in most gas-shale basins are still making money. It would not have been the case if prices were lower. As a result, we may have entered an extended period of natural gas oversupply from sustained drilling despite low prices.
This realization may be behind comments by oilfield service company CEOs on their second quarter earnings conference calls about the pace of the industry recovery. Dave Lesar, Halliburton Companies’ (HAL-NYSE) CEO characterized it this way, “Due to continued weakness in natural-gas demand ... we believe it is unlikely that there will be a meaningful recovery in natural gas prices and, consequently, drilling activity for the remainder of the year."
Our own view is that natural gas is in an extended period of low prices driven by a combination of weak gas demand due to the anemic economic recovery and continued gas supply growth from domestic production, Canadian imports and additional LNG deliveries. Like Mr. Simpson, we don’t believe this will be a decade-long experience. Could it last five years? Possibly, but then again, no one knows. Absent a greater cutback in drilling and a more rapid falloff in production than we are currently seeing or a sharp upturn in gas-consumption, the domestic natural gas market may be in for an extended depressing period.
Energy R & D and Pet Food (Top)
A recent comment by was made by a staff member on the World Bank’s climate change blog that the world spent less per year on energy R&D than on pet food. She decided to check out it out and found worldwide energy R&D in 2007 was $12 billion according to the International Energy Agency statistics and consistent with the World Bank’s upcoming World Development Report. She then found that in 2005 Americans spent $34 billion on pet products of which 41%, or $14 billion, was spent on pet food and treats. She also pointed out that American pet food spending was about equal to the amount French citizens spend on cheese each year. Her conclusion is that unless something changes, we will “have the energy we deserve.” That may be true. On the other hand, maybe we should question the definition of energy R&D? Are we only talking about projects such as the recently announced biofuel from algae research to be backed by Exxon Mobil Corp. (XOM-NYSE), or do we include the various million dollar efforts to improve specific energy technologies or oilfield equipment? Regardless, this data point highlights how energy and climate research is playing a growing role in the broad social debate over the future of our economy and the environment.
We are sure the American public will be happy about “soaring utility” bills as President Obama explained in order to cool the environment for their grandchildren.
Exhibit 16. Pay Me Now Or Pay Me Later?
Many drivers in California have elected to drive vehicles powered by biodiesel as part of personal efforts to become “green drivers.” One such driver reported his surprise recently when he drove into his local biodiesel station and was flagged down by the attendant and told they no longer were dispensing biodiesel but rather only traditional diesel fuel. It turns out the station abandoned the biodiesel market due to a June decision by the State Water Resources Control Board to begin enforcing current laws against underground storage of biodiesel. Since most stations do not have the space for above-ground storage tanks, the state’s decision is forcing them to switch to petroleum-based diesel.
California regulators want to avoid the same sort of mistake they made when the gasoline additive MTBE migrated into neighboring drinking water. A representative of the board said that everything that is going to be stored underground needs to be tested by an independent authority. They are not worried particularly about the biodiesel but rather the additives that some suppliers put into the fuel. The problem is that getting the fuel tested can take up to three years and the state says there are as many as 1.5 million different formulations of biodiesel based on the various additives being sold in the state.
California drivers who want to use biodiesel because its exhaust has been determined by the EPA to not be harmful to human health are now facing a dilemma. Some biodiesel fuel suppliers mix a bit of petroleum in the fuel in order to take advantage of a tax incentive that the federal government grants for sales of blended fuels. In the end, this appears to be another example of one set of regulations de-railing the intent of other regulations. The issue will get sorted out eventually, but in the meantime, the environmental movement has suffered a setback from other environmental regulations.
Energy Secretary Stephen Chu has begun making some decisions about the government’s preferred future sources of energy for the U.S. automobile industry with his budget recommendation to slash funding for hydrogen fuel cells, a favored fuel of the Bush administration, by 59%. The Obama administration instead favors greater use of natural gas and electricity generated by renewable fuels such as wind and solar. As these broad policy decisions are made the future shape of the domestic vehicle market begins to take form.
In April of this year the EPA issued its review of the health of the population due to the buildup of greenhouse gases in our atmosphere. The review examined six gases including carbon dioxide and methane. It concluded that the emission of these gases from vehicle tailpipes results in an endangerment of the health and well-being of the American population and therefore these emissions should be regulated under provisions of the Clean Air Act. This finding began the process for the EPA to create rules for regulating carbon emissions, not just from new vehicles sold but possibly from other sources, too.
The Obama administration and the EPA administrators have indicated publicly they would prefer to see Congress pass legislation to deal with the greenhouse gas emissions issue rather than rely on possibly questionable provisions within the Clean Air Act to regulate them. The EPA’s endangerment claims, however, came under immediate attack following the revelation of the agency’s possible suppression of an internal report sharply questioning the science behind the decision.
The public comment period on the EPA’s report was scheduled to end in late June with rule-making to begin thereafter. We suspect any rules issued will be subject to vigorous legal challenges. With the recent House passage of the Waxman-Markey bill, referred to as the “cap-and-trade” bill, the potential for governmental regulation of emissions by law as opposed to administrative rule has moved a step closer to reality. Although there will be continued legislative and legal challenges, the political reality is that carbon emissions are going to be subject to some form of restriction and/or tax.
The effort to develop cleaner burning automotive fuels to reduce carbon emissions has been ongoing for many years. The problem is no one has yet developed a new fuel or engine that is more energy-efficient than diesel or gasoline and the internal combustion engine. This evolution is not without many attempts to develop alternatives, but as data from the Energy Information Administration (EIA) for 2007 shows, petroleum-based fuels still account for 96.3% of the Btus used to meet the nation’s transportation needs. Only 3.7% of Btus come from alternatives such as natural gas and electricity.
Exhibit 17. Petroleum Fuels Dominate Transportation Market
Source: DOE Transportation Energy Data Book
There certainly are many reasons why petroleum-based fuels dominate the transportation market. Principal among them is the energy performance of petroleum-based fuels followed by their ease of distribution and fueling compared to alternative fuels. Recently an increased PR effort has been waged that the natural gas-powered vehicle (NGV) market should receive greater support from the federal government and increased funding. The principal reason supporting this effort is the existence of huge natural gas resources within the confines of the United States that could ultimately eliminate our need to import crude oil, and especially crude oil produced by less-friendly suppliers. Secondarily, the California Energy Commission has determined that NGVs emit 29% less greenhouse gases than gasoline-powered vehicles and 22% less than diesel-powered, meaning they also can help deal with the nation’s global warming initiatives.
The arguments against NGVs are the lack of a fueling infrastructure; they have less cargo space; they require specific servicing not readily available and fueling them can be challenging; the lower energy content of natural gas decreases their driving range and increases their frequency of refueling; and the engines are basically retrofitted gasoline engines that must be approved by the EPA. Utah is a state that is aggressively supporting the NGV industry with heavy subsidies. It has asked the EPA to streamline its onerous and expensive certification process for retrofitting gasoline engines in order to boost vehicle availability. As for new NGVs, there is only one model selling in the United States and that is Honda Motor Company’s (HMC-NYSE) Civic GX, but it is only sold in California and New York.
According to Natural Gas Vehicles for America, only about half of the 1,100 natural gas fueling stations nationwide are open to the public compared to 180,000 gasoline stations. In trying to quantify the cargo space issue, we found the following data quite interesting. The typical automobile gas tank holds 15 gallons, so it carries approximately 1.85 million Btus of energy (115,400 Btus per gallon). That energy content is equivalent to 1,850 cubic feet of methane gas (1,000 Btus per cubic foot). At a compression factor of 180:1, a compressed natural gas tank must be able to hold 77 gallons of liquid, which suggests a tank that is 10.3 cubic feet in capacity or roughly five times the size of current gasoline tanks.
Besides tank size, owners of NGVs report it is often difficult for the fueling station compressors to sustain pressure long enough to allow them to completely fill their tanks, necessitating more frequent fuel stops. In addition, the “Phill” by Fuelmaker, a company owned by Honda, is the sole manufacturer of a natural gas refueling appliance for residential use, but it too is only available in certain states.
Even if we assume NGVs become popular and that hundreds of millions of dollars of capital investment are used to create a natural gas fueling infrastructure, it will take upwards of 20 years or more for today’s fleet of 250 million vehicles to be replaced. In our last Musings we discussed an analysis comparing the use of natural gas directly as fuel in a vehicle versus using the same volume of gas to generate electricity to power an all-electric or plug-in hybrid vehicle. In our analysis, the electric vehicle won.
Since that article, it has been suggested we should be focusing more on the potential for natural gas in the heavy truck market, which are powered by diesel fuel that is more polluting. By switching to natural gas or possibly LNG, companies could reduce their carbon footprint. While the 2007 DOE data does not segregate natural gas use in transportation by compressed gas versus LNG, we cannot say how much LNG is being used, but we suspect very little. The primary transportation use of LNG to our knowledge is in engines powering LNG tankers. The ships draw fuel from their cargos as they are traveling. This use of LNG to power engines has been ongoing for many years with few problems for the engines.
There are many pilot studies employing alternative fuels in different commercial vehicle applications. Much has been made recently of an experiment Wal-Mart (WM-NYSE) is conducting with CNG- and LNG-powered trucks. These tests have only recently started so we would expect it to be some time before there are definitive results that would motivate the company to convert the nation’s largest independent fleet of trucks to alternative fuels. Hereto there will be a replacement cycle to be dealt with as we doubt Wal-Mart is prepared to immediately replace its entire fleet with alternatively-powered vehicles, assuming truck manufacturers could even deliver sufficient new trucks within a reasonable time frame.
In recent days there have been new developments about battery technology suggesting that electric cars may be closer to a reality as a market force than previous thought. A video interview with the Dick Weir, the founder and CEO of EEStor Inc., a secretive start-up battery technology company in Austin, Texas, was leaked to Yahoo and put on its web site only to be removed shortly thereafter. A copy of the audio from the interview does exist and a transcript has been floating around the web. A technology reporter, Tyler Hamilton of Clean Break, who has interviewed Mr. Weir several times in the past is convinced the voice on the tape is that of Mr. Weir.
Exhibit 18. EEStor’s Battery Technology Makes For Small Unit
In the interview, Mr. Weir talked about the technology of making a capacitor from a composition modified barium titanate powder that gives the highest electricity permittivity. To develop the material, the elements had to be mixed in an aqueous solution that necessitated extensive chemical research in order to find the proper solution that did not cause one or more of the elements to drop out. The claims made about the technology, which is patented, are that it can withstand millions of cycles of charging and discharging without degradation in performance in contrast to lithium-ion batteries that survive for about 5,000 cycles before degrading. Secondly, the EEStor battery is 1/4th to 1/3rd the size, mass and volume of a lithium-ion battery and it can be charged in the same time required to fill a gasoline tank. The last, and probably the most significant advantage, is the battery’s cost. Because it uses barite, which is a much more available commodity worldwide – there are larger reserves and they are located in many more countries including a newly discovered mine here in the United Sates, in contrast to lithium that has limited reserves and is found primarily in Chile and China. The estimated cost of the EEStor battery is $100/kilowatt hour (kWh) compared to $800 - $1,200/kWh for lithium-ion batteries. The suggested cost of the EEStor battery is in the same price range as lead acid batteries but with huge performance advantages.
EEStor was founded by Mr. Weir and Carl Nelson who had previously worked together in the computer industry’s hard disc drive business. The interview revealed that EEStor is 20%-owned by the leading venture capital firm Kleiner Perkins Caufield & Byers and 10%-owned by the Canadian electric car manufacturer, ZENN Motors (ZNNMF.PK). ZENN just increased its ownership under an arrangement it had with EEStor whereby following certain milestone technological achievements, ZENN would invest additional money to fund commercial development of the battery.
Reportedly, EEStor is ahead of schedule for producing prototype battery units for installation in the CityZENN vehicle planned to be introduced by ZENN towards the end of 2009 or early in 2010. The all-electric CityZENN vehicle is designed to carry five passengers, have a 3,100 pound curb weight, an 80 mile per hour top speed and a 250 mile between battery charge range, and rechargeable within five minutes. The car will be comparable in size to the Toyota Motor Corp. (TM-NYSE) Camry or the Honda Accord. The price target is $30,000 or less. ZENN has the exclusive right to make vehicles smaller in size than the CityZENN, also.
In reading extensive commentary about the news from this interview on the web and on blogs, we found a number of engineers and scientists who are skeptical of the technology and Mr. Weir’s claims. Many of them point to the fact that EEStor has been working on this technology for four years with a history of prior claims that have not materialized. We do not possess sufficient technical knowledge to know whether the claims about the chemical and/or physical attributes of EEStor’s battery are true. We did find it interesting that one scientist referred to battery technology work he was involved with at Georgia Tech that is also focusing on barite but employing nanotechnology. He indicated they had not achieved anywhere near the attributes Mr. Weir claims EEStor has accomplished. On the other hand, Mr. Weir claims his technology has been certified by Southwest Research Institute and is being tested by Underwriters Laboratories. In order for ZENN to make its last investment, it had the technology tested and the claims verified.
When we attended a meeting at Rice University earlier this year we heard representatives from Kleiner Perkins discuss their clean energy investments. They indicated that their firm did not disclose all its clean energy investments for competitive reasons and the EEStor investment was not mentioned. We had heard rumors about their investment in EEStor and the close involvement of Lockheed Martin Corporation (LMT-NYSE), which was also confirmed during Mr. Weir’s interview. While there are numerous scientists who are skeptical of EEStor’s claims, we don’t know enough to bet against such a successful and heavy-weight high-tech venture capital investor as Kleiner Perkins.
The next 6-12 months may be a very exciting time for clean energy and alternative fuel vehicle technologies. Yes, NGVs will play a role, but we think plug-in hybrid electric vehicles (PHEVs) and all-electric cars will also be in the mix. We fully expect battery technology breakthroughs that will make them lighter, more powerful, faster to charge with less degradation, but most importantly, cheaper. At the moment we think PHEVs may be the ultimate winner in the alternative-fuel vehicle derby.
Three weekends ago we drove back from our summer home in Rhode Island. Traffic on most of the highways was generally heavier than we experienced back in May when we drove north. We did observe more camper trailers and motor homes this time, but we were struck by the fact that the truck traffic appeared to be appreciably lighter than this spring.
One image about trucks sticks in our mind. There is a stretch of highway near Chattanooga, Tennessee, that follows along the Tennessee River as it curves around the city. On the other side of the highway are train tracks. As we were navigating a sweeping curve on the highway we noticed a tractor truck pulling a container trailer on the other side heading north. In the background going south was a freight train pulling a long string (as far as our eye could see) of flatbed railcars each loaded with containers stacked two high. That image was a sign to us of some of the shifting economic trends underway in this country – more goods are being transported by train, which is more fuel-efficient than by highway. Of course for the final-mile of distribution the goods have to move by trucks since trains do not have that degree of flexibility. The image struck us as the perfect picture of the economy’s distribution system at work.
Another image we wrestled with was one we commented on in May – all the car dealer billboards along the highways. We wondered how many of them carried advertisements for now-closed car dealerships following the bankruptcies and restructurings of Chrysler and GM. We also wondered what impact these dealer closures were having on the various communities we were passing – job losses, charity contributions lost, people’s lives inconvenienced, etc.
Lastly, we carried images in our head of the economic downturn’s pain inflicted on the local communities around where our summer house is located. Signs of the downturn’s impact appear everywhere in empty store locations, closed restaurants, newspaper reports of and discussions with locals about employer plans for worker furloughs and job sharing arrangements in an attempt to spread the downturn’s financial pain.
Rhode Island was one of the first states to experience the effects of the recession. The state’s decaying economy and corrupt and ill-financed government sector have pushed it essentially into bankruptcy, although states cannot declare bankruptcy. The scary realization was that no one in the state legislature will or can acknowledge conditions and the need for drastic economic actions.
In June, Rhode Island’s unemployment rate hit 12.2%, up from 10% in January and up from 7.7% a year ago. In recent days the state’s July rate was released by the U.S. Bureau of Labor Statistics showing unemployment had climbed to 12.4%, the second highest in the nation and the highest rate experienced in 33 years, or during the height of the 1970s difficult economic times. What we know about unemployment statistics is that they fail to capture many of the discouraged workers, underemployed workers and people who have exhausted their unemployment benefits. The New York Times reported that Rhode Island’s true unemployment rate, if the people in all those prior categories were included would have reached 21.5%. The latest increase in unemployment came as a result of government and hospital workers who were laid off as the state’s FY2010 budget began.
HIS Global Insight has recently published a report providing its estimate of when individual state unemployment rates will return to their pre-recession levels. Six states are projected to reach that point sometime in 2011. Those states include Alaska, New Mexico, Minnesota, Texas, Utah and Virginia. Rhode Island won’t achieve that pre-recession unemployment level until sometime after 2015.
Our final impression from the drive home was how Pennsylvania has moved aggressively to capture federal stimulus money to fix its highways. We learned after returning home and after having endured several long stretches of single lane highway driving due to road re-construction that Pennsylvania had grabbed $3 billion dollars of stimulus money for highway construction. The shocking aspect of that announcement by Gov. Edward Rendell (D) was the money had only saved (or added) 5,000 jobs, and those will be temporary. We will appreciate the better roads when we drive them next but we will feel the pain in our pocketbooks every day for many years to come.
While natural gas consumption year to date has declined, within the electric power generation market it has increased largely at the expense of coal consumption. The electric power market has also benefitted from increased nuclear generation and more power from hydroelectric sources as the nation has experienced increased precipitation in regions where dams are located. Higher coal prices and falling natural gas prices have helped lift gas consumption especially for use in gas turbines for peak power generation. What might have really helped the natural gas market would have been a warm summer especially in the Northeast and Midwest that would have stimulated increased air conditioning load.
The cool summer throughout much of the country has become a topic of increased discussion among energy participants who are wondering why this summer’s weather pattern is so different from prior summers and what it portends for the upcoming winter. Of course energy people are always interested in hurricane activity, but so far this season, which started on June 1st, the topics have been very quiet. Historically, hurricane season doesn’t shift into high gear until the middle of August, with many of the strongest storms hitting the country in September. So, despite most forecasters having lowered their expectations for exactly how active this hurricane season may be, we all know it isn’t just the number of storms that occur, but rather their strength and trajectory. Just one strong storm hitting the wrong parts of the United States coastline can be more significant to the energy industry than a lot of weaker storms that do not land on our shores.
We have written about how the month of June in the Northeast U.S. was one of the coolest, wettest and darkest months on record. That pattern has largely continued with the week of July 13th establishing some 800 record low temperatures across the country. The cooler-than-normal weather this summer has been due to a change in the Arctic Oscillation (AO) weather pattern. The AO refers to the
Exhibit 20. Low Jet Stream Has Allowed Cool Air Into U.S.
spinning of winds in the Arctic region that can shift or block the jet stream. When the AO is in a positive phase, the jet stream tends to stay further north and warmer temperatures prevail over most of North America. On the other hand, a negative phase for the AO leads to a lower jet stream allowing more cold air to drift south producing cooler temperatures.
Exhibit 21. Arctic Oscillation Influences NA Weather Patterns
Effects of the Positive Phase | Effects of the Negative Phase
of the Arctic Oscillation of the Arctic Oscillation
(Figures courtesy of J. Wallace, University of Washington)
Source: National Snow and Ice Data Center
A climate research paper published in 2001 identified the AO and its role in driving weather patterns in the northern hemisphere. The paper, prepared by two research scientists, was based on an examination of daily weather data for specific weather stations in the northern hemisphere for the January through March periods of each year for the period 1958-1997. The data showed a strong correlation between AO negative phases and record cold days and snow storms over a much broader region of the northern hemisphere than previously thought. The paper discussed how the AO had remained in a positive phase for the 1980s and 1990s and reduced the number and frequency of winter days with subzero temperatures and substantial snowfalls in the midlatitudes. The authors questioned whether this pattern was the result of the buildup of greenhouse gases.
Based on research by Joe Bastardi, chief meteorologist for AccuWeather.com, he believes the lower tracking of the jet stream during June and early July contributed to cooler temperatures in the Midwest and Northeast regions of the country. He does not reference the AO as the driver of this pattern but rather cites the impact of volcanic activity and the emergence of El Niño in the Pacific Ocean. After a brief warm up for the Northeast in late July and early August, Mr. Bastardi believes the cool temperatures will return. But more important for the energy industry is his noting that cooler summers have often been followed by harsh winters. As he pointed out, temperatures in New York City did not exceed 85 degrees this June. There have been only three other times when temperatures in New York City failed to reach 85 degrees and in each case the following winter was unusually snowy.
Exhibit 22. Balance Of Summer Will Be Cool In Northeast
Mr. Bastardi pointed to other cities in the country that have similar patterns of cool summer temperatures and snowy winters. He also believes that the El Niño pattern that developed this summer will fade as the year progresses and further contribute to possibly the snowiest winter since 2002-03 when up to 80 inches fell in many places. He believes winter snowfall totals this year should be between 50 and 100 inches with the primary targets being cities located in New England down through the Appalachians and the mid-Atlantic region including North Carolina. This suggests higher energy bills for people living in the region along with the costs associated with added snow removal efforts, more travel delays and extended school closures.
Offsetting the more wintery pattern for the Northeast and mid-Atlantic regions could be a slightly warmer than normal and less snowy Midwest region extending from Kansas City to Omaha to Minneapolis to Chicago. On balance, it looks like energy participants are going to become “farmers” once again as they will have to maintain a heightened focus on weather forecasts. Energy investors should keep one thing in mind. The longer, colder and snowier the winter is in the Northeast, especially in Boston, the better the environment for energy stock prices.
Exhibit 23. This Winter Looks Colder And Snowier
In our years on Wall Street we have observed that energy stock prices tended to perform better when the Boston energy stock traders began wearing their topcoats. Likewise, when they merely started carrying them on their arms in the spring, energy stock prices begin to suffer. So here’s to a long and cold winter!
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Parks Paton Hoepfl & Brown is an independent investment banking firm providing financial advisory services, including merger and acquisition and capital raising assistance, exclusively to clients in the energy service industry.
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