Musings from the Oil Patch – March 30, 2010

• Falling Prices To Restrict Natural Gas Drilling Activity?
• Spring Has Sprung – Look Out For Gas Prices
• Global Warming Fears Ebb; Energy Industry Still A Target
• UK Electricity Issues Present Challenge For Many Governments
• The Latest Twist In Cape Wind Energy Approval Saga
• Pace Of Electric Vehicle Introductions Seems To Slow

Musings From the Oil Patch
March 30, 2010

Allen Brooks
Managing Director

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

Natural gas futures prices have slipped below the $4 per thousand cubic feet (Mcf) level in the last several days.  The drop was largely due to the unexpected gas storage injection reported last week.  With expectations that gas storage volumes are likely to continue to build during the seasonally mild weather spring season, the fundamental outlook for natural gas has become extremely negative.  At the same time, Wall Street firms are reducing their forecasts for natural gas prices this year.  Tudor, Pickering, Holt & Co. lowered its average price for 2010 from $7.50 to $6.20/Mcf.  Bernstein Research dropped its price to $7 from $9/Mcf.  While many

Exhibit 1.  Gas Prices Slumping After Winter Demand

Source:  EIA, PPHB

bullish analysts and investors are disappointed by the weakness in natural gas prices, they realize prices could have fallen much lower had the nation not experienced weeks of super cold weather this winter.  As gas storage volumes were about 4 trillion cubic feet (Tcf) at the start of the winter, they will end the withdrawal season at about 1.7 Tcf.  Without the cold winter it is likely that natural gas prices would be substantially lower – possibly a price well below $3/Mcf.

At the root of the gas price problem is a lack of significant natural gas demand growth coupled with a very modest decline in gas production due to the drop in drilling during the first half of 2009.  Most analysts have attributed the lack of a meaningful fall off in gas production to the increase in drilling in gas shale formations.  To test that thesis, we used a spreadsheet prepared by Baker Hughes (BHI-NYSE) that segregates the company’s weekly rig count data from the start of 2008 through mid-March by major drilling basins and whether the rigs are drilling for oil or gas. 

Exhibit 2.  Gas Shale Drilling Outperforming All Gas Drilling

Source:  Baker Hughes, PPHB

In this case, we plotted the number of gas-oriented drilling rigs working in East Texas, the Ft. Worth basin and Appalachia representing the Haynesville, Barnett and Marcellus gas shale formations against the total number of rigs drilling for natural gas in the country.  We indexed the data to 100 at the start of 2008.  As can be seen in the nearby chart, the gas shale rigs lagged the overall gas drilling count throughout most of 2008.  However, as we entered 2009, gas shale drilling activity began to outperform the total gas-oriented rig count.  What we know about gas shale drilling is that the initial production from these wells is extremely high, albeit for a relatively short time period.  Therefore, as gas shale drilling began to dominate all gas-oriented drilling, gas production declines anticipated by the absolute decline in gas-oriented drilling were largely offset.  Additionally, one should assume that producers drilling non-shale wells were “high-grading” their prospects, helping to ensure higher initial production from this smaller universe of conventional gas wells.  Combined, there was a much smaller production response to the sharp fall in gas drilling activity than anticipated.

The depressing near-term outlook for natural gas markets was reinforced by Dr. Jonathan Lewis of Halliburton (HAL-NYSE) who spoke at the RMI Oilfield Breakfast last Thursday.  In response to a question from the audience about the impact of gas shale development on Halliburton’s business, he stated that the company’s fracturing horsepower was operating at the highest level ever.  He also said that the backlog of drilled but uncompleted gas wells is growing due to the inability of the oilfield service industry to meet the demand for completion equipment.  Dr. Lewis described the phenomenon of a large backlog of these wells as another form of natural gas storage since wells can be completed in the future when demand for the gas is present. 

Dr. Lewis’s observation about a growing backlog of drilled but uncompleted gas shale wells is in contrast to observations by some Wall Street analysts who believed this phenomenon was over.  As oilfield activity fell during the first half of 2009, oilfield service companies reduced their list prices by offering increasingly higher discounts to gain work.  Discounts were raised to levels at which certain company managements concluded that the hydraulic fracturing work was unprofitable and elected to park their equipment rather than work at cheap prices.  That capacity reduction enabled the remaining companies to begin boosting prices by reducing discounts. 

It is our understanding that hydraulic fracturing discounts have been steadily shrinking during the first quarter of 2010.  At the same time, the upturn in gas shale well drilling has generated an increase in

Exhibit 3.  Rising Well Backlog Supported By Comments

Source:  EIA, API, PPHB

work.  And as Dr. Lewis confirmed, the growth in demand has exceeded the service industry’s ability to satisfy it.  Last November, we attempted to try to gauge the number of drilled but uncompleted wells as we felt that phenomenon could depress natural gas prices as the wells were completed and the production volumes hit the market, even if new well drilling declined.

As the chart from the study (not updated) shows, we expected the industry to reduce its backlog of uncompleted wells as we moved into the first quarter of this year, but then the backlog would begin growing even with higher prices for hydraulic fracturing services.  While we are not sure whether our number of drilled but uncompleted wells is close to the actual number, based on Dr. Lewis’s comments, our well backlog pattern appears correct.  That cannot be a good sign for future natural gas prices since the drilling rig count has continued to rise, including adding another 17 working rigs last week, although only two were targeting natural gas. 

Is it possible the gas-oriented rig count is poised to start falling in response to low gas prices?  Reportedly, Chesapeake Energy (CHK-NYSE) management told analysts that it was going to deactivate 20 drilling rigs in response to low gas prices.  Chesapeake’s CEO Aubrey McClendon also said he wished the company had more liquids, meaning more oil.  Today, virtually every independent producer wants to be seen as more oily than gassy because oil prices are $80 per barrel and natural gas prices closed Friday at $3.87/Mcf, a value differential of 20.7 to 1, approaching the peak disparity that existed last summer.  Maybe this is the first demonstration of capital discipline by a producer.

Exhibit 4.  Are Gas Producers Poised To Destroy Capital?

Source:  Bernstein Research, Art Berman, PPHB

Based on information contained in a report on the financial health of a group of independent producers issued by Bernstein Research, a universe of 41 companies is spending an average of 128% of its estimated cash flow.  If natural gas prices remain low, or fall lower, the companies’ cash flows will be reduced.  We would anticipate that these companies will need to reduce their capital spending.  On average, this universe of companies has a 43% debt to total capitalization ratio, which is not particularly high.  However there are at least a half a dozen companies that are spending more than their total cash flow with debt to total capitalization ratios of 50% or greater.  Unless natural gas prices rise or producers cut back their drilling, production and spending, the industry is headed for a train wreck resulting in substantial capital destruction.

Last week the Energy Information Administration (EIA) reported that natural gas storage volumes stood at 1,626 billion cubic feet (Bcf), an increase of 11 Bcf over the prior week.  With weather forecasts calling for warmer temperatures across the eastern half of the country, it appears the 2009-10 winter heating season is over.  As the red line in the nearby chart shows, the upturn in gas storage volumes has come earlier than the average of the last five years.  With the gas-oriented drilling rig count continuing to climb in recent months, expectations are that natural gas production will resume growing.  Absent any strong recovery in gas consumption from the power and industrial sectors, and as residential heating demand will be declining with warmer temperatures, the likelihood is increasing that gas storage volumes will climb back above the five-year range.

Exhibit 5.  Gas Storage Starting To Rise

Source:  EIA

Last Thursday when the EIA announced the latest gas storage figures, natural gas futures prices dropped by slightly over 3% to $3.98 per thousand cubic feet (Mcf).  A significant problem for the natural gas market is the lack of a strong economic recovery in the United States.  Traditionally, a cyclical economic recovery would be supported by a sharp recovery in the housing and automobile sectors, but as was pointed out by a Wall Street stock strategist on CNBC last Friday morning, new housing starts used to be at a 2.2 million annual rate, now they are 500,000, and automobile sales were 16 million units annually, and now are running at about 12 million.  Both of these sectors are heavily dependent on credit availability that remains an ongoing challenge.  While the corporate debt market is functioning better than a year ago, consumer credit continues to shrink and the housing sector remains in shambles as banks struggle with underwater mortgages and foreclosures rather than making new loans.  The high unemployment in the country has reduced consumer incomes and consumer willingness to assume new or more debt for large purchases such as homes and automobiles. 

The relatively bleak outlook for economic growth that dampens the prospect for increased natural gas demand has sent futures prices to six-month lows.  With the prospect of slow economic growth coupled with the realization that gas shale formations in the U.S. have dramatically increased our natural gas resource potential, ignoring the profitability issue for the moment, gas producers are aggressively pushing to find new markets for gas consumption.  The best opportunities appear to be in the electric power and transportation sectors – witness the strong push by Boone Pickens and Aubrey McClendon, along with others, for increased use of compressed natural gas as a transportation fuel.  Increased penetration in these two markets requires overcoming hurdles.

Exhibit 6.  Coal Is Cheap But Gas Is Cleaner

Source:  Black & Veatch

We attended a presentation last week by Chuck Stanley, chief operating officer of Questar Corporation (STR-NYSE), on the topic of “The Role of Natural Gas in U.S. Energy Policy.”  Mr. Stanley is an active member of the American Natural Gas Association (ANGA) that is pushing for increased use of natural gas in the country’s fuel mix.  The push is based on the greatly expanded gas resource base and the fact that natural gas is a much cleaner fuel than either oil or coal.  In a report authored by Anne Harris of Black & Veatch in February 2009, she showed the advantages and disadvantages of the three principal fossil fuels used in the U.S. – coal, oil and natural gas.  We have reproduced the table from the report summarizing these advantages and disadvantages.  (Exhibit 6.)

In the power generation sector, natural gas has gained market share recently due to the drop in the price of the fuel due to the surge in unconventional gas production, principally from gas shales.  While natural gas is now cheaper than coal in many areas, electric utility customers are bothered by the price volatility of the fuel.  Mr. Stanley remarked that price volatility is the number one issue he and his company confront when discussing contracts to sell gas to power plant owners.  He remarked that the gas industry needs to develop longer term supply contracts that eliminate or at least minimize the price volatility issue in order to put gas on an equal footing with coal. 

Gas producers could easily enter into long term contracts at a fixed price, but they are reluctant to do so because they are not sure about their ability to find new gas supplies at similar finding and development cost as the gas they are presently selling.  Mr. Stanley suggested that the nature of gas shale formations eliminates exploration risk and turns the development of the gas resource into a manufacturing operation lending itself to less cost volatility.  This is a popular belief among gas shale operators, Wall Street analysts and investors.  The problem is that as the industry gains more history with gas shale basins, it is finding that there is more variability within the shale formation than they thought and these formations may be more like conventional gas basins, i.e., there are “sweet” spots that are more productive than other areas within the formation.  This formation variability can impact finding and development costs and thus the profitability of gas shale output for operators. 

We must admit that when we heard Mr. Stanley discuss the need to develop an alternative contract for selling natural gas to power plant owners that reduces or eliminates price volatility, we flashed back to the late 1970s and early 1980s when the development of the deep Anadarko basin in eastern Oklahoma was underway.  The strong demand for natural gas from pipeline companies and industrial users at that time pushed producers to probe for gas at depths of 18,000 – 25,000 feet at huge costs.  The producers were willing to undertake these efforts because buyers were willing to enter into long-term, take-or-pay contracts.  As the early 1980s unfolded and the economy experienced the worst recession since the Great Depression, gas consumption slumped.  These take-or-pay contracts became albatrosses around the necks of the interstate natural gas pipeline companies.  Since they couldn’t sell this high-priced gas, they were faced with trying to renegotiate the contracts.  For producers there was little reason to cut the price.  As a result of the stand-off, these take-or-pay contracts nearly bankrupted the entire U.S. pipeline industry. 

Exhibit 7.  Gas Plants Can Beat Coal With Low Gas Prices

Source:  Black & Veatch

At the present time, natural gas is cheaper than coal for use in power generation in many regions of the country.  The nearby chart showing the cost of power generation by fuel is based on 2008 fuel prices.  Natural gas prices were considerably higher then.  What is evident from the chart is that the largest portion of the cost of power from natural gas combined-cycle power plants is the fuel price.  That is in sharp contrast to the cost for a coal-fired power plant.  With natural gas prices less than half what they were in 2008, one can see how gas plants have gained an economic advantage on coal and why gas is gaining market share in the power generation market.  The question for gas producers is: Will this market share hold if, and when, natural gas prices rise?

Exhibit 8.  Natural Gas Can Be Larger Share Of Power Market

Source:  EIA

When we look at the fuel source structure of the electricity generating market, we find an interesting fact.  Natural gas power plants represent a much greater share of the industry’s generating capacity than of its consumption.  According to EIA data, in 2008 natural gas could fuel 39% of the nation’s power generating capacity during the summer (Exhibit 8), yet it actually only fueled 21.4% of the power market. 

What this difference reflects is the large amount of peak-use gas-fired capacity that is seldom called upon.  Some of this capacity is on standby in large population markets to meet summer heat wave demands from increased air conditioning load, while other is for backing up the intermittent wind energy supplies. 

Exhibit 9.  Natural Gas Fuels 21% Of Electricity

Source:  EIA

What the natural gas producers need to figure out is how to increase the use of gas-fired combined-cycle power plants.  Assured low gas prices are likely the answer, but not the scenario producers want to live with as it means low earnings and potentially greater restrictions on their ability to fund future drilling and development activity, which will limit their future growth.  Given the sharp production declines experienced by newly drilled gas shale wells, producers are forced to sustain a certain level of drilling or they will be unable to meet their gas supply commitments.  These conflicting forces are what insure future gas price volatility. 

In the distant past when natural gas sales in interstate markets were regulated by the Federal Power Commission (FPC), to solve the problem of increasing supply, pipeline companies were allowed to make advance payments to producers for future gas volumes.  These advances enabled producers to go out and drill wells, hopefully finding new gas supplies, and then deliver the volumes to the pipeline against the payment.  The pipeline company was allowed to include the advance payment in its rate base upon which the company was allowed to earn a regulated rate of return by the FPC.  That return was priced into the tariff it charged customers who got the gas.  In the event the producer was unsuccessful in finding new gas supplies, he was not obligated to repay the advance payment. 

This mechanism was employed in the late 1960s and early 1970s for companies operating in the Gulf of Mexico at a time when gas supplies were running low and there were serious concerns that interstate pipeline companies would not be able to meet their supply commitments to customers in the Midwest and Northeast regions of the country.  Unless some form of regulation is imposed on gas buyers guaranteeing a rate of return to the pipeline customer, it is difficult to see how a variation of this system could be used today to help reduce gas price volatility.  The scary thought is that the Obama administration is unafraid of getting involved in owning and regulating large segments of our economy.  Might this be a model they would find attractive, especially if it enabled them to make sure that any spike in gas prices (consumer inflation) could be avoided? 

Recently the Gallup Poll organization released the results of its latest survey ranking the top eight environmental issues facing Americans.  The poll focused on the percentage of Americans who were “very worried” or worried “a great deal” about these issues.  The surprise seems to be that among the eight issues, global warming ranked last among American concerns.  “Americans are now less worried about a series of environmental problems than at any time in the past 20 years” concluded the Gallup Poll.  The poll results and the percentage of Americans ranking the issue a significant concern are listed below. 

Exhibit 10.  Gallup Poll Of American Environmental Concerns

Source:  Gallup Poll organization

The global warming ranking has fallen steadily since it peaked in importance in 2007 at 41%.  Surprisingly, global warming was at 40% in 2000 but only increased by one percentage point in the following seven years despite the best efforts of the UN’s Intergovernmental Panel on Climate Change reports and former Vice President Al Gore’s movie, book and Nobel Peace Prize for raising the conscience of the public to the calamity that would befall civilization if we didn’t control and reduce the amount of carbon emissions being released into the atmosphere.

As we have found out from the hacked emails of environmental priests at the University of East Anglia in the UK and the faulty temperature data series being used to drive the rudimentary climate models, the world has actually experienced a decade of global cooling despite the increase in carbon dioxide in the atmosphere.  Could it really be that natural forces rather than humans are the primary cause of our periodic warming and cooling?  Unfortunately, that conclusion would go against the catechism of the global warming religion.

In the Gallup Poll results, American concerns over every environmental issue have declined since its prior poll.  The range in the declines is from a high of nine percentage points for “Pollution of drinking water” and “The loss of tropical rain forests” to a low of four percentage points for “Maintenance of the nation’s supply of fresh water for household needs.”  The conclusion of the Gallup Poll organization is that the decline in American’s concern about environmental issues “could be due in part to Americans’ belief that environmental conditions in the U.S. are improving.  It also may reflect greater public concern about economic issues, which is usually associated with a drop in environmental concern.” 

Despite the reduced concern of Americans about environmental dangers, we suspect the current administration and Congress don’t agree.  Now that health care reform has been put in place, the politicians are likely to move on to energy and the environment.  If the energy industry thinks it is not in the sights of the government it is sadly mistaken.  The long-term restructuring of our energy sector is about to begin and we fear the changes may be much more dramatic than anyone imagines.

A recent report issued by Britain’s power regulator, Office of the Gas and Electricity Markets (Ofgem), concluded that the country is heading for a “cliff edge” when it comes to having sufficient electricity generating capacity to meet demand after 2015.  By 2016, many of the country’s older, dirtier coal-fired plants will be forced to close under the European Union’s Combustion Plant Directive.  The EU’s Industrial Emissions Directive will result in further closures by 2020.  Many of Britain’s nuclear power plants have already been shut down and more will have to be closed over the coming decade as they reach the end of their economic lives. 

The Ofgem report concludes that if demand grows as expected Britain faces a growing gap between the electricity it will need and the amount it will be able to generate in the second half of this decade.  The Ofgem report says the county will need upwards of £200 billion ($267.7 billion) of investment in new generating capacity and offers a range of possible options to meet this goal. 

At the “mild” end of the spectrum of options offered in the report are “targeted” reforms: 1) a minimum carbon price to stimulate investment in low-carbon generation; 2) stronger encouragement for demand-side response from energy users through better price signals; and 3) sharper signals in the gas and electricity wholesale markets to encourage suppliers to ensure they have better access to back-up supplies especially at periods of high demand.  At the ”mad” end of the spectrum is the proposal to establish a central buyer of energy and capacity that would determine the amount and type of new electricity generation needed and could also tender for new gas infrastructure.  These Ofgem proposals were developed while acknowledging the challenges the energy industry confronts due to the credit crisis, the tough environmental targets in place and the increasing dependency on natural gas.

Last fall, Ofgem produced a report illustrating four scenarios for resolving the power generation capacity issue.  The report showed that the country’s power supply margin was comfortable for the next few years but then drops sharply into a range that is troubling – in other words there is a high risk for power outages and shortages.  It is not Ofgem’s role to make the decision as to which plan to follow; the government must determine the country’s energy policy.  And that is the challenge the UK government must meet. 

Exhibit 11.  Electricity Spare Capacity Shrinks Dangerously

Green Transition     Green Stimulus        Dash for Energy        Slow Growth

Capacity margin is an indication of how robustly an electricity system is likely to be able to meet demand peaks.  It is a measure of how much extra generation capacity there is on the system than would be needed to meet expected peak demand, such as during an average cold spell.  De-rated capacity takes account of how available installed capacity is likely to be under normal circumstances.  For example wind power capacity is only available when the wind is blowing, so its de-rated capacity will be a fraction of full capacity (perhaps 35%).  Because in exceptional circumstances not all de-rated capacity will be available (perhaps due to maintenance of breakdown) there needs to be significantly more capacity on the system than that needed to meet peak demand, to ensure security of supply.  While there is no ideal number, capacity margin in GB has tended to be around 20% in recent years.  Figures below about 15% start to look worrying.
Source:  Ofgem, European Energy Review

European Energy Review interviewed Professor Jonathan Stern of the Oxford Institute for Energy Studies, who observed that “…the era of free energy markets in the UK has now passed.  Liberalization has finished.  We’re going back to more intervention, more central direction, more government decisions and fewer market decisions about what’s going to be built.  And that is being driven by a carbon agenda and not an energy agenda.”  One wonders whether these same comments will be applied to the U.S. energy legislation currently moving through Congress.  We already know that the Obama administration is not a friend of the oil and gas industry – actually viewing it as a target.  They perceive the oil and gas industry as too big, makes too much in profits, enjoys too many tax benefits, and destroys the environment.  As a result, the industry has been targeted as a source for government tax revenues.  This is understandable when one considers that politicians and bureaucrats in Washington barely know the difference between oil and gas and electricity!

A new report from the International Energy Agency (IEA) and the Nuclear Energy Agency (NEA) addresses the cost of generating electricity in regions of the world.  This report is the 7th in a series that have been issued by these two organizations every five years.  The study was prepared by 50 representatives from 19 OECD countries and is based on cost and operating data from 200 power plants worldwide.

The report examines by geographic region of the world the cost in dollars per megawatt-hour (MWh) of nuclear, coal and gas-fired power plants, and offshore wind power projects based on both 5% and 10% discount rates.  The analysis also includes a carbon price of $30 per ton.  It does not include the cost of transmission and distribution or the additional costs of balancing and back-up power that wind energy requires.  It also assumes that the European natural gas price is $10.30 per million British thermal units, which is twice the current spot price.  Nuclear power’s cost estimate does not include the cost for refurbishment, waste treatment and decommissioning following the plants estimated 60-year lives.

Below we have published the two charts showing the range of power costs per megawatt-hour of output for each fuel by the three major regions of the world and at the two discount rates.  In both discount scenarios, nuclear power is the lowest cost source for electricity, except for Europe under the 10% discount case.

It is interesting to note that in the 5% discount scenario, onshore wind power in North America is potentially competitive with nuclear, but we wonder what happens when various other costs are factored in.  But the chart also shows that coal is cheaper than natural gas, although with very low gas prices that gap has shrunk and in some regions even flipped in favor of natural gas.  When we shift to the higher discount scenario, the gap between the median cost for all four fuel choices narrows substantially.

Exhibit 12.  Nuclear Power Is Low Cost Choice Worldwide

Source:  IEA-NEA

Exhibit 13.  NA Power Choice Costs Narrow At High Discount

Source:  IEA-NEA

Potentially the most significant point made by the IEA-NEA report is its statement that “offshore wind is currently not competitive with conventional thermal or nuclear baseload generation.”  In the report, it cited the range of offshore wind power costs at a low of $101/MWh for a project in the U.S. to a high of $260/MWh for one off Belgium.  The study also stated that solar PV power was not economic and suggested that its cost ranged between $225 and $600/MWh.  We wonder what impact the conclusions of this study will have on the energy policy of the Obama administration and Congress, as it is the most authoritative prepared on the subject.

As the calendar grinds slowly toward the end of April and the supposed decision date for Secretary of the Interior Ken Salazar to decide the fate of the Cape Wind farm project planned for construction in Nantucket Sound, several new twists have emerged.  The first twist was the announcement of five people who will form an Advisory Council on Historic Preservation to the Interior Department.  The five members include its chairman, John L. Nau II, the head of Silver Eagle Distribution, a leading beer distributor in Houston; Julie King an anthropologist; John Berry, chairman of the Quapaw Tribe of Oklahoma; Stephen Ayers, architect of the capitol; and Linda Lawton, director of the Department of Transportation’s Office of Safety, Energy and Environment. 

The panel held a hearing March 22nd on Cape Cod to assess the situation.  The panel has promised to have its report ready for the Interior Secretary by April 14th.  We are not sure what this panel’s report is to accomplish since both the federal government and Massachusetts have had experts review the situation and the Interior Secretary held a mediation discussion with the various parties involved in the dispute.  It looks to us like more cover for whatever is decided.  Given that the Interior Department has had a history of poor handling of Native American issues, we wonder if Sec. Salazar wants someone else to make this decision for him.

At about the same time the panel was being introduced, a number of environmental groups and organizations opposed to the construction of the 130 wind turbines standing 440 feet tall in a 24 square mile section of Nantucket Sound that comprise the Cape Wind project filed a 60-day notice of violations of the Endangered Species Act.  The notice was sent to Massachusetts Secretary of State William Galvin along with the U.S. Department of the Interior and all other federal agencies that have reviewed the Cape Wind proposal. 

The primary objection to the Cape Wind project is that it may harm birds, especially the piping plover and the roseate tern.  The objectors claim that the federal government study on the potential harm to these birds was not properly prepared and should be redone.  They are likely hoping that a redo of the study will produce contradictory conclusions from the original study.  The problem is that both the U.S. Fish and Wildlife Service and the Massachusetts Audubon Society agree with Cape Wind that the birds will not be harmed by the wind farm.  The complaining groups may be hanging their hats on statements from some agencies that their reviews were rushed due to political pressure, although all of them stated that their conclusions were not impacted by the hurried nature of the studies.

The environmental groups and organizations opposed to Cape Wind have said that they will likely file suit if the project is approved.  So while we are about a month away from the supposedly final regulatory approval, the prospect of a lengthy court battle now looms.  We still don’t know whether the protesting Indian tribes will sue if the project is approved over their objections.  The clock for seeking approval of the Cape Wind project now stands at nine years.  Part of the delay was due to the Minerals Management Service not having prepared rules and regulations to approve offshore wind farms.  That process required nearly a year to accomplish.  The prospect of continuing objections from nearby residents for close-to-shore wind turbines may suggest that the only wind farms to be built off the U.S. coast will be located much further from shore and thus out of view from the shore.  That will make them much more expensive to both build and operate and increase the challenge getting the power to shore. 

At the end of last week several Rhode Island officials traveled to Washington, D.C. to participate in a two-day conference sponsored by the Transportation Research Board, an arm of the nonprofit National Research Council, addressing the establishment of standards for offshore wind farms.  The board is researching possible regulations for the Minerals Management Service.  Some of the issues addressed included how to build and anchor to the ocean floor wind turbines that could withstand hurricanes and what the minimum standards for blades and turbines should be.  Part of the problem is that the U.S. has never constructed offshore wind farms and those in Europe do not have to withstand the same storm conditions as experienced in the Atlantic Ocean and Gulf of Mexico.  We must say that we are surprised that the federal government is only now looking at the standards for offshore wind turbines.  What may the proposed standards do to current wind farm cost estimates and their economics? 

Wind maybe the favored alternative energy source of the Obama administration, but increasingly wind projects are meeting local objections.  Additionally, the further remote these wind projects get from the power consuming markets, the more costly they become as power transmission becomes a more significant challenge.  Recently, power analyses are showing that when the carbon emissions from the required back-up power sources are included, wind is not as clean an alternative fuel as advertised.

The idea that electric vehicles will gain a large share of the new car market soon is probably overly optimistic.  Several news stories are pointing out shifts in automobile company strategies with regard to the introduction of new electric cars.  According to a story in the Mainichi Daily News, Nissan Motors (NSANY.PK) has established a price in Japan for its new all-electric car model, Leaf.  The car will be priced at 4 million yen, or about $44,000 at current exchange rates. 

This puts the model’s price between the $40,000 price for the Chevy Volt and the $51,000 for the Mitsubishi (MMTOF.PK) i-MiEV model. 

It is understood that Nissan will market the Leaf in a campaign designed to convince auto buyers that the total cost to own and operate the car will be comparable to that of a conventional gasoline-powered vehicle after the federal tax credit, state and local incentives and the spread between the future price of gasoline and electricity are taken into account.  We are not convinced this type of marketing program will be that successful beyond those buyers who are already predisposed to purchasing an expensive electric car for environmental reasons.  Nissan is aggressively working with local governments, including the City of Houston, to get them to buy some cars to help jump-start the community’s interest in electric vehicles and to provide a stimulus for the locality to construct auto charging facilities.  Nissan is also working with car rental companies, utilities and corporations who are concerned about their “green” image and not the economics of buying and operating the vehicle.

The other news story reported recently by Bloomberg News was that BYD Company Ltd. (BYDDY.PK), after having sold 48 F3DM plug-in hybrid vehicles to government and corporate customers in 2009, has given up its ambitious plans to mass manufacture electric vehicles in China by the middle of this year.  Instead, BYD will build 100 taxis for its hometown of Shenzhen. 

It appears BYD may have decided that it needs more user-data before beginning commercial production.  This strategy would seem to be more consistent with the traditional manner in which new automobile models employing new technologies are introduced.  First, you build a few cars and give them to customers to use while monitoring their positive and negative reactions.  Once the initial testing program is complete, you make any necessary adjustments based on the first customer reactions and give the next model to a second group of consumers to drive.  The iterative process is much like that used by the Federal Drug Administration as they supervise the testing of new drugs before granting final approval for their sale to the general population.  It is believed that BYD’s strategy change came after management considered the risk of lawsuits from possible defects in early models that had not gone through rigorous consumer testing before being sold. 

Given the high selling price established for the three new electric vehicles that are targeted for introduction in the next one or two years and the decision to slow down introduction of BYD’s vehicle, one has to wonder about the pace of battery manufacturing capacity.  Could the lithium-ion battery industry be headed for a bubble? 

To address that question, Roland Berger Strategy Consultants prepared a report titled “Powertrain 2020 – Li-ion Batteries – The Next Bubble Ahead?”  They prepared a chart in the report showing the announced capital spending for the 20 largest Li-ion battery manufacturers in the world.  Total investment by this group of companies through 2015 is estimated to be €8.2 billion ($11.2 billion) and the manufacturing capacity will be able to produce 2.6 million electric vehicle equivalent battery packs, which are defined as equal to 25 kilowatts of power. 

Exhibit 14.  Is A Bubble In Li-ion Batteries Developing?

Source:  Seeking Alpha

The three most aggressive battery manufacturing companies include AESC, who will be producing batteries for the Leaf, LG Chemical, who will supply the Volt, and BYD.  Will these aggressive plans be needed if the cars are only niche vehicles?  Possibly the most interesting observation from the chart is that the most modest expansion plan is proposed by Panasonic EV Energy, a unit of Toyota Motors (TM-NYSE).  This is interesting since Toyota is the inventor of hybrid electric vehicle technology and the dominant manufacturer in that space.  Do they believe electric vehicle penetration will not be what the forecasters expect?  Given the pace of electric vehicle developments in light of the vehicle pricing, there is a strong likelihood that the only battery manufacturing plants that will be built will be those financed by the $1.2 billion in battery manufacturer grants given out by President Obama under the American Recovery and Reinvestment Act of 2009.  Is this another case of government trying to pick winners and losers when the free market will do it better?

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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.