Musings from the Oil Patch – January 19, 2010

• Electric Or Natural Gas Cars In Our Future?
• GOM Ultra-Deep Discovery Reflects Historical Pattern
• UK Goes For Wind, But What If It Doesn’t Blow?
• Stock Market Guru’s Predictions Could Impact Energy
• Wind Energy Enters New Phase: A Breeze or Gale?
• To Know Clean Energy Industry; Follow The Money

Musings From the Oil Patch
January 19, 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

The 2010 Auto Show held in Detroit recently concluded after generating photo ops for our politicians and much speculation about the future of the U.S. auto industry.  There was extensive media coverage of the electric vehicles displayed by various auto manufacturers, however, no car company provided a timetable for when its vehicle would be in dealer showrooms.  The show coincided with the introduction of the latest version of the Pickens Plan for U.S. energy policy designed to build public pressure for natural gas-powered vehicles and to convince legislators to mandate them into a greater share of the vehicle market.

As a result of all this publicity, debate over what course the U.S., and in fact the global, auto industry should set was heightened.  When we look at some of the more recent data and auto industry trends, we are inclined to think the U.S. auto industry will not make the seismic shift in vehicle power trains the optimists anticipate.  This conclusion is driven by examining the impact of government financial incentives and policy actions that push vehicle manufacture into steps actually contrary to the incentive’s original intent.  For example, the push for electric cars, which are costly, limited in range and make us more dependent on fewer foreign governments for battery materials than crude oil, sets us on a course that is likely to fail.  The American public is not in favor of electric cars and will not buy them.  They may, however, be left with no choice due to manufacturer actions in response to government incentives. 

The most important industry trend is the changing American love-affair with the automobile.  Partly in response to the severe recession, but also due to social and demographic trends, the automobile market is changing.  A recent study by the Earth Policy Institute (EPI) demonstrates that for the first time since World War II, the U.S. auto fleet shrank last year.  The EPI crunched numbers from the Federal Highway Administration and R.L. Polk, the auto research firm.  Their analysis showed that 14 million cars were scrapped last year versus only 10 million in new sales.  While the decline in the size of the U.S. vehicle fleet was only about 2%, the fact that it did decline was notable.  It may have been more notable than the decline in the cumulative number of vehicle miles driven in this country, which has largely been attributed to the rise in gasoline pump prices above $2.50 per gallon. 

Exhibit 1.  U.S. Auto Fleet Fell In 2009 For First Time

Source:  FHWA; Energy Policy Institute

One of the key demographic trends impacting the auto fleet and its usage is the shrinking teenage population and teenagers’ attitude towards cars.  The number of teenage drivers has declined from a peak of 12 million in the late 1970s to about 10 million in 2007.  Importantly, the share of driving-age teenagers with licenses has declined from 69% to 56%.  As the EPI pointed out, teenagers are more likely to socialize using electronics – Facebook, Twitter and text messaging – rather than the automobile.  The cruising scenes from the movie American Graffiti are truly a relic of the past.

According to the EPI analysis, we have a fleet of 246 million vehicles and 209 million licensed drivers.  That means we have five vehicles for every four drivers.  That ratio is likely to shrink in the future due to the fallout from the recession and the realization that gasoline prices are likely to rise in the future rather than retreat to recent lows.  As local transit options increase and improve, a shift away from the suburbs to more urban living will grow and with it comes a reduced need for people to own any vehicle much less multiple vehicles. 

Exhibit 2.  Interest In Autos Among Teens Is Declining

Source:  , FHWA; Energy Policy Institute

The EPI examined the Japanese experience with autos following that country’s saturation in 1990 when new car sales peaked.  That peak coincided with the first year of that nation’s economic funk.  Since then Japan’s annual car sales have fallen by 21%.

Exhibit 3.  More Cars Than Drivers Dictates Smaller Fleet

Source:  Energy Policy Institute; Agora Financial

So from 49 million cars in 1950, the domestic vehicle fleet grew to 250 million units before shrinking by four million units last year.  After examining the trend in scrapping based on a 15-year life for vehicles, EPI believes it will be many years before new car sales approach the implied scrapping rate.  Between 1999 and 2007, the U.S. auto industry sold on average 17 million vehicles per year.  Last year, due to the recession and the bankruptcies of GM and Chrysler, new car sales fell to 10 million.  The auto industry is forecasting about a 1.5 million unit increase in sales this year followed by a 2.0-2.5 million unit sales increase in 2011, bringing annual car sales near 14 million.  If 10-14 million car sales becomes the new normal for the industry, then scrapping rates of 13-15 million units guarantee the fleet will shrink every year well into the future.  The EPI estimates the fleet will shrink 10% by 2020, or to 225 million units. 

Something that could hasten the fleet shrinkage is government policy.  The Obama administration is determined to have auto companies build smaller, greener vehicles.  This is being partly accomplished through the Environmental Protection Agency’s recent mandate for higher average fleet fuel efficiency.  Since the U.S. government retains control over GM and Chrysler, it is able to influence the types of vehicles made, although the administration will adamantly claim it is not running the auto companies.  However, as pointed out by Holman Jenkins in an op-ed article in The Wall Street Journal, GM wants to become profitable, which means it needs to make and sell vehicles the public wants to buy and ones that carry meaningful profit margins.  Those vehicles are pickups and SUVs, neither of which are particularly fuel-efficient.  The trick will be to push small and electric cars onto the public with the help of the government so GM can make and sell more profitable pickups and SUVs.

The government (taxpayers) will assist GM by keeping in place the $7,500 tax credit for buyers of electric cars, even though research has shown them to be a bad deal for consumers, our goal of reducing foreign oil consumption and the environment.  We will also help by providing $25 billion in direct loans to automakers to retool their plants dedicated to “green” cars.  So will we be driving hybrids, compressed natural gas-powered or fully electric cars in the future?

A December 31, 2009, article in Forbes, titled “System Overload,” questioned whether the lithium-ion battery industry was overbuilding global manufacturing capacity?  It quoted research from Deutsche Bank (DB-NYSE) that by 2015 there would be the ability to produce 36 million kWhs of battery capacity, enough to supply 15 million hybrid vehicles or 1.5 million fully electric cars.  The article then went on to question whether there would be enough buyers for all these hybrids and electric cars.  With government subsidies and/or mandates, there will be sufficient demand for these vehicles.

Exhibit 4.  How The Future U.S. Auto Fleet Might Look

Source:  EIA

What hasn’t been questioned is whether these are the right vehicles to be brought to the market.  In America, the average car owner drives 12,000 miles annually.  With a conventional internal combustion engine for power, the driver will consume 400 gallons of gasoline a year.  With a Prius class hybrid, an owner will need 240 gallons of gasoline to drive the same distance, and none if he drives a fully electric vehicle.  Hurray for electric vehicles!

But wait, while 1.5 million electric vehicles will save 600 million gallons of gasoline a year, the 15 million Prius class hybrids will save approximately 2.4 million gallons of gasoline.  So score one for the hybrids!  Now, if we look at the environmental balance, the internal combustion engine releases 20.35 pounds of CO2 annually.  The fully electric vehicle is cleaner but not CO2 free.  The power plants that generate the electricity release a national average of 9.68 pounds of CO2 per equivalent gallon of gasoline.  Therefore, the 1.5 million fully electric cars would cut CO2 emissions by 2.9 million tons.  On the other hand, the 15 million Prius class vehicles would reduce annual CO2 emissions by 24.4 million tons. 

What about Boone Pickens’ favorite vehicle – those powered by compressed natural gas?  Mr. Pickens has come out pounding the table for natural gas-powered vehicles as the way to reduce the amount of money being sent abroad to buy oil.  But with the current low natural gas price and the possibility that gas prices will remain low for an extended period of time, the economics of gas-powered vehicles is still not favorable.  Based on natural gas at $5.60 per million British thermal units (Btu), the equivalent price of a gallon of gasoline would be $1.86, well below the current pump price of $2.64.  The problem is that compressed natural gas lacks the infrastructure necessary to make it popular with consumers.  Other technologies such as hybrids or even electric cars can achieve lower costs without the bulky tanks and limited refueling challenges. 

According to an analysis done by the Financial Times, a Prius costs $801 to drive for a year while it costs $926 to drive for a year the only gas-powered car available, a converted Honda Civic.  Add in that the Prius will travel 526 miles on a single fueling against 202 miles for the Honda.  The Financial Times concludes that with various models of electric vehicles coming to market, “the moment for natural gas cars has come and gone.”  Since Mr. Pickens’ energy plans have morphed from wind power (Plan A) to natural gas-powered vehicles (Plan B), the Financial Times wonders what is Plan C?

On the basis of fuel savings and environmental benefits, the hybrid is the better vehicle choice.  The 15 million Prius class cars save 1.8 million more gallons of gasoline and reduce CO2 emissions by 21.5 million more tons of CO2 than the 1.5 million electric cars.  The coup de grace in favor of the hybrid comes when you factor in the price of a Prius versus that of an electric car.  The base sticker price of a 2010 Prius is $22,400.  The base sticker price for the planned GM Volt will be about $40,000.  While federal tax credits will help lower that cost to $32,500, it will still cost the consumer $10,000 more than a Prius.  Therein lays one of the great challenges for the Obama administration and our Congress: How to reduce the cost to consumers of electric cars or figure out how to compel us to buy them.  The government’s uncontrolled spending spree will continue under this scenario because taxpayers will not only have to continue to subsidize the purchase price of electric cars (for environmental reasons and to hopefully earn a return on our auto investments), but also for rebuilding the electric power grid.  Of course, that expense might be mandated and left to the utility companies and the utility regulators to figure out how to get consumers to fund that investment.  The bottom line is these trends are not positive for petroleum consumption.

Last Monday, McMoRan Exploration Co. (MMR-NYSE) announced it and its partners had drilled a successful ultra-deep natural gas discovery in 20-feet of water in the Gulf of Mexico off the Louisiana coast and one of the largest finds in decades.  The prospect, known as Davy Jones, was drilled to a measured depth of 28,263 feet and marks the second ultra-deep discovery announced in the past four months.  BP plc (BP-NYSE) announced a discovery at its Tiber prospect in 4,000-feet of water and a well depth of close to 30,000 feet last September.  That oil discovery is thought to be one of the largest oil discoveries ever in the United States.

The Davy Jones discovery well is located on South Marsh Island Block 230, which is one of four contiguous blocks indicating that the areal extent of the field could be large.  The well encountered 135 feet of net pay in four zones in the Wilcox section of the Eocene/Paleocene formation.  The existence of hydrocarbons was determined by a resistivity log, but a flow test will be needed to determine the ultimate hydrocarbon flow rate of the well.  McMoran plans to deepen the well to 29,000 feet to test additional horizons.  Estimates are that Davy Jones possibly contains 1 trillion cubic feet (Tcf) of gas, or twice what experts thought likely.  After more time spent assessing what is known about the discovery and the deep geologic trend, estimates about potential gas reserves are growing.  Some now believe the discovery may contain as much as 3 Tcf, but we have seen another estimate saying it could be twice that amount.  We caution that many of the higher estimates come from Wall Street analysts who have a tendency to see things more optimistically than the cautious estimates. 

In a conference call with Wall Street analysts, McMoRan Chairman James R. “Jim Bob” Moffett said, "The Davy Jones log results confirm our geologic model and indicate that the previously identified sands in the Wilcox section on this large ultra-deep structure encompassing four OCS lease blocks (20,000 acres) provides significant additional development potential which, upon confirmation development drilling, could make Davy Jones one of the largest discoveries on the Shelf of the Gulf of Mexico in decades. The geologic results from this well are important and are redefining the subsurface geologic landscape below 20,000 feet on the Shelf of the Gulf of Mexico. The results from this well will be incorporated into our models as we continue to define the potential of this promising new exploration frontier." 

According to the Energy Information Administration (EIA) there were 27.6 Tcf of proved natural gas reserves, both dry and wet, located in the federal waters of the Gulf of Mexico with 55% located in water depths of less than 200 meters (650 feet) at year-end 2007.  Davy Jones’ potential reserves of 1 Tcf represent more than 3.5% of that 2007 proven gas reserves figure.  (The impact on total gas reserves will be much larger if the more optimistic estimates of Davy Jones’ reserves prove accurate.) 

But is it surprising that such a discovery would be made now, or that BP’s discovery would have occurred?  One might point out that in 2007 ExxonMobil (XOM-NYSE) abandoned an ultra-deep well on the Shelf after drilling to nearly 90% of the target depth and spending an estimated $180 million.  Our reaction at learning of the McMoRan discovery (and the BP one) was this is the typical pattern for the international petroleum industry.  Whenever oil and gas prices spike up, within a relatively short time there always seems to be a jump in announced oil and gas discoveries, and often times very significant discoveries.  To refresh our memory, we dug back into the 1987 edition of the “Brown Book” published by the UK’s Department of Energy.  Actually, the volume in titled: “Development of the oil and gas resources of the United Kingdom 1987; A report to Parliament by the Secretary of State for Energy; May 1987.” 

Exhibit 5.  UK Oil & Gas Discoveries Jump After Price Rise

Source:  UK Department of Energy, PPHB

The book contains a listing of every discovery made in the UK sector of the North Sea from the time drilling began in the early 1960s until the beginning of 1987.  The listing is of “significant” discoveries, which is defined by the Energy Department as the well’s initial flow rate and not its potential reserves.  We plotted the number of oil and gas discoveries in each year from 1965 through 1986 against crude oil prices.  One might question why include natural gas discoveries.  European gas contracts are priced off the British thermal unit (Btu) equivalent oil price, tying gas economics to oil prices. 

We combined annual spot oil prices for West Texas Intermediate (WTI) for the first five years of the period with the official export price posted by Saudi Arabia for its light crude oil (34.0° – 34.9° API gravity) for the balance of the period to capture the volatility of global

Exhibit 6.  High Oil & Gas Prices In 2007-8 Drove Exploration

Source:  EIA, PPHB

oil markets.  People need to remember that U.S. crude oil prices were controlled in the 1970s distorting the impact of free market trends.  Whenever we experienced a sharp increase in oil prices such as occurred in the 1970s there was a corresponding increase in oil and gas discoveries in the very near future. 

Thus, after crude oil hit $147 a barrel in mid 2008 and natural gas was trading at $13 per thousand cubic feet (Mcf), it is not surprising to see significant discoveries within two years of those highs.  That just seems to be the history of the oil and gas business.

This winter has brought some unusual weather to North America and Europe.  Early in the winter, Canada’s West Coast had great snowfalls offering the prospect of wonderful conditions for the Vancouver Olympics starting February 12th.  Unfortunately, the winter has turned warm and rainy for the British Columbia coast, a condition referred to as a Pineapple Express, which is creating concern about snow conditions at several venues for the Winter Olympics, although there are snowmaking facilities available.  Vancouver recently had temperatures of 11°C (51°F) that has forced the Olympic venues to shut down snowmaking efforts until colder temperatures arrive.  As the balmy weather in northern Canada has displaced the traditional January arctic temperatures, the cold weather has migrated south to the United States.  Freezing temperatures have been experienced as far south as the Gulf Coast and Florida.  The arctic temperatures and shifted jet stream have contributed to numerous snow storms moving across the Plains and Midwest states and into the Northeast and even Mid-Atlantic region creating great havoc. 

Winter weather patterns in Europe also have deviated from normal as the region has been impacted by a weather pattern referred to as the warm-ocean cold-land phenomenon.  The result is that cold places remain cold because of the lack of wind, while warm places are kept warm because local winds are constantly coming off warmer seas.  Many people may have seen the NASA Terra satellite picture of January 7, 2010, and publicized throughout the UK, of the country completely covered by ice and snow.  This is an unusual event given that the island country’s weather is normally influenced by the warm waters of the Gulf Stream.  The fallout from this unusually cold weather pattern, however, has created challenges for companies managing the UK’s natural gas supply for generating electricity and heating homes.  Since the beginning of the New Year and the blast of arctic temperatures, National Grid (NGG-NYSE), the UK’s primary gas utility, has been forced to issue four (through January 13th) gas balancing warnings – the company’s first ever warnings.  The warnings came as temperatures across the country fell.  On January 8th temperatures reached lows of -21°C (-5°F).  UK gas demand during the cold snap soared to levels surpassing the previous record demand days experienced during January 2003. 

National Grid reported gas demand so far this year through January 13th is running about 28% above normal.  Early in the cold snap, National Grid estimated the country’s average daily gas consumption had increased from an average of 350,000 cubic meters to 435,000 cubic meters, or 24% higher.  As cold temperatures continued, gas demand has climbed higher.  On January 7th, National Grid said the nation’s gas demand reached 456,700 cubic meters compared to the prior record day’s demand of 449,000 meters (January 7, 2003). 

To help manage the demand for more natural gas for home heating and generating electricity, National Grid issued its gas balancing warnings.  These warnings force customers with interruptible supply contracts to switch to other fuels.  Some 95 manufacturing plants in Northwest England, East Anglia and East Midlands were impacted by the warnings.  According to media reports there were no problems for these customers to switch to alternative fuel supplies.  National Grid’s gas supply problems have been compounded by the shut down due to bad weather of Shell’s (RDS.B-NYSE) Ormen Lange gas field offshore Norway and frozen pipes at Gassco’s Norwegian plant that reduced its output.  Some of the North Sea gas supply shortfall has been offset by increased use of liquefied natural gas (LNG).

Exhibit 7.  The UK Buried By Ice And Snow

Source:  BBC.com

As cold weather gripped the country, UK Prime Minister Gordon Brown unveiled the award of a host of development contracts for the construction of a new generation of offshore wind farms.  The government plans for wind power to be supplying a third of the country’s energy by 2020.  To meet that target, the UK is embarking on an aggressive plan to construct nine enormous offshore wind farms on ocean locations auctioned by the Crown Estate, the owner of the UK’s territorial seabed.  On January 8th, the Crown Estate announced the awards of the development contracts.  The winners have already signed exclusive Zone Development Agreements with the Crown Estate.

Exhibit 8.  Planned Wind Farm Locations

Source:  Timesonline.co.uk; PPHB

Mr. Brown lauded the prospects for the country at the time of the awards announcement.  The British Wind Energy Association estimates the developments will create 60,000 jobs, although we wonder how many of them will be permanent after completion of the construction.  Additionally, the construction of these nine projects will not begin until at least 2015. 

A significant challenge for these wind farm developments is their size and location.  Each of the wind farms will be larger than any offshore wind farm presently in operation.  Additionally, they will be located in deeper water and farther offshore than any operational wind farm, which will present construction and maintenance challenges.  For example, the Dogger Bank wind farm in Zone 3 is located 100 km (62 miles) off the coast.  This wind farm is planned to generate nine gigawatts (GW) to as many as 13 GW of power.  At its designed standard, the wind farm would be nine times larger than the total global offshore wind power capacity in operation today.  Of course, it will be expensive to construct.  Based on current prices, Dogger Bank is estimated to cost £35 billion ($57 billion). 

The bet on offshore wind power the British government is making has raised some eyebrows.  Offshore wind power is still a generally untested power source and, even though offshore winds tend to be stronger and steadier, the power generated is still intermittent.  Putting these wind turbines in the North Sea, one of the harshest bodies of water especially during the winter months, raises other

Exhibit 9.  Locations Of Round 3 Offshore UK Wind Farms

Source:  Crown Estate

questions.  How will these turbines be maintained and what is the risk to them from a 100-year storm?  As Andy Cox, energy partner at KPMG said, “There remain a lot of issues that are still not fully understood.  Reliability has got to be the biggest.  If a gearbox goes down in November, it [the turbine] is going to be shut down for the whole of the winter.” 

Offshore oil and gas structures are built to withstand waves generated by a 100-year storm (50-feet high), which is achieved by providing a 50-foot air-gap between the surface of the ocean and the bottom deck of the platform.  Offshore wind turbines will need to have similar air-gap clearances between the supporting structure and the ocean.  Because large offshore wind turbines have long blades, the creation of the air-gap for the tip of the blade at the bottom of its revolution means a taller structure to hold the turbine.  That means the weight of the unit will be higher, thus exposing it to greater structural stress from the wind during storms.  Additionally, there is the turbine’s maintenance challenge by the greater distance workers will have to be lifted to work on it.  That is not to say turbine units can’t be designed and built to withstand 100-year storms, but their cost will be likely be substantially more than for smaller turbines along with the extra cost for equipment needed in the turbines’ maintenance efforts.  

The maintenance challenges are further highlighted by the need to lay hundreds of miles of undersea cables to connect the turbines to the power grid, which in turn will need to be upgraded to handle the inconsistency of wind power.  The latter issue becomes of paramount importance when the population is counting on the wind for power and it fails to blow as happened earlier this month during the height of the cold snap.  On January 4th, the UK met its electricity needs by relying almost totally on fossil fuels.  Some 48% of the country’s electricity was generated by coal-fired power plants, 29% came from gas-fired ones and 20% from nuclear units.  Wind power, which represents an installed capacity of 4 GW of electricity, or four percent of the UK’s capacity, was only able to supply 0.4% of the country’s power. 

We have seen the result of intermittent wind in Texas when the power grid was counting on its supply.  During the evening of February 26, 2008, the Electricity Reliability Council of Texas (ERCOT) ordered power blackouts when there was a sudden drop in wind power coupled with a surge in customer usage and several natural gas-fired power plants were slow coming on stream.  A report later that year by General Electric (GE-NYSE) pointed out that when Texas gets to 15,000 megawatts of wind power, drops of 2,400 megawatts of wind power in a span of 30 minutes will become a regular occurrence.  In contrast, the drop in wind power that February 2008 day was only 80 megawatts.

To address the challenge of managing intermittent power supplies, nine countries in Europe and Scandinavia are planning to join together to develop a plan to link all their clean energy power projects.  The nine countries involved in the discussions – Germany, France, Belgium, the Netherlands, Luxembourg, Denmark, Sweden, Ireland and the UK – hope to have an agreement in place by fall to begin building a high-voltage direct current network within the next decade.  Plans are to hopefully include Norway with its many hydro-electric power stations that could function as a giant 30 GW battery for the rest of Europe’s clean energy output. 

There are two aspects to clean energy that are driving the planning for this integrated power network.  First is the intermittent nature of clean energy.  It is highly dependent on when the sun shines, the wind blows and ocean waves crash.  Second is that clean energy producing facilities tend to be highly decentralized and are often built in inhospitable places, far from population centers.  A super-grid connecting all the countries’ clean energy facilities, and which is also linked to Norway’s hydro-electric plants, would provide a secure and reliable energy supply from renewable fuels.  At the present time there are proposals to construct approximately 100 GW of offshore wind power around Europe, equal to about 10% of the European Commission’s (EC) electricity demand, and the equivalent of 100 large coal-fired power plants.  This surge in potential wind power is forcing the electricity industry to begin examining the need to upgrade and adapt the continent’s power grid.  Last year, the European Wind Energy Association (EWEA) produced a study that outlined where the cables might be built.  The EWEA study will likely become the starting point for the discussion by the nine governments.

The idea of tying in the Norwegian hydro-electric power plants with the renewable power grid is to allow the electricity produced when European power demand is low to be used to pump water uphill, ready to let it rush down again, generating electricity when demand is high.  Justin Wilkes, the head of EWEA, believes there are great benefits to this integrated approach.  He said, “The benefits of an offshore super grid are not simply to allow offshore wind farms to connect; if you have additional capacity, which you do within these lines, it will allow power trading between countries and that improves EU competitiveness.” 

The EC has been examining proposals for a renewable-electricity grid in the North Sea.  A working group within the EC’s energy department is scheduled to produce a plan by the end of 2010.  The UK’s energy and climate change minister, Lord Hunt, said, “We recognize that the North Sea has huge resources, we are exploiting those in the UK quite intensively at the moment.  But there are projects where it might make sense to join up with other countries, so this comes at a very good time for us.”  Lord Hunt said that the EC’s working group’s findings would be fed into the nine-country grid plan.

The cost of a North Sea grid has not yet been calculated, but a study by Greenpeace in 2008 put the price of building a similar grid utilizing 6,000 km (3,728 miles) of cable by 2025 at €15 billion – €20 billion ($21.8 billion – $29.0 billion).  The EWEA’s 2009 study suggested the cost of a grid to connect the 100 GW of offshore wind farms and with additional interconnectors into which future wind and wave power farms could be plugged would probably push the cost to €30 billion ($43.5 billion). 

“The North Sea grid would be the backbone of the future European electricity super grid,” said Lord Hunt.  This super grid, with backing from scientists at the EC’s Institute for Energy and politicians such as French president Nicolas Sarkozy and Britain’s Gordon Brown, would link huge solar farms in southern Europe producing electricity either through photovoltaic cells, or by concentrating the sun’s heat to boil water and drive turbines, with clean energy projects elsewhere on the continent.  The electricity would be transmitted along high voltage direct current cables, which are more expensive than traditional alternating-current cables, but they lose less energy over long distances.

The North Sea grid could also link into other grids such as one proposed by a German-led plan for renewables called Desertec Industrial Initiative (DII).  The DII aims to supply 15% of Europe’s electricity by 2050 or earlier via power lines stretching across the desert and the Mediterranean Sea.  This is a roughly $400 billion plan to use concentrated solar power in southern Europe and northern Africa to produce electricity that would be shipped to Europe.  The technology uses mirrors to concentrate the sun’s rays on a fluid container.  The super-heated liquid then drives turbines to generate electricity.  Plants using this technology have been running for decades in the United States.

Exhibit 10.  Proposed 900 Megawatt Plant For PG&E

Source:  BrightSource Energy; cnet.com

As we envision these schemes we see their great value in overcoming one of the greatest shortcomings of clean energy – its lack of consistency.  On the other hand, we are left with a couple of questions, besides the technical aspects of making these grids work and the economic issue of its cost.  We wonder how many citizens are going to be happy having these huge power lines strung overhead or buried in their town.  Secondly, we can’t wait for the next Ian Fleming-like author to give us a mad man or terrorist who holds all of Europe hostage with a threat to black out the region unless it meets his demands.  We sure hope Britain’s MI6 is grooming the next James Bond to protect us because this may not be a fictional story.

Byron Wien, the 76-year old vice chairman of Blackstone Advisory Services and long-time stock market strategist, recently issued his list of ten surprises for 2010.  A number of his surprises could have an impact on global energy markets, along with energy stocks.  Mr. Wien has been publishing his list of annual surprises since 1986.  Last year he was very accurate with the direction of most of his predictions.  For 2009 he foresaw a second-half recovery for the U.S. economy and the S&P 500 stock index climbing to 1,200.  He also foresaw U.S. Treasury bond yields rising to 4% from 2.24% at the start of 2009, and that gold would hit $1,200 an ounce and oil reach $80 a barrel. 

When Mr. Wien makes his predictions he cautions readers he places at least a 50% chance of them occurring at some point during the year.  We have only focused on a few of his ten predictions because they are the most meaningful for their potential impact on global energy demand, prices and stock prices.  He makes three predictions about the health of the U.S. economy and the resulting impact on interest rates that in turn impacts the value of the U.S. dollar.  All will impact energy demand and prices.

First, Mr. Wien sees the U.S economy growing at a stronger than expected 5% real rate during the year and that unemployment will fall to 9%.  That would suggest increased U.S. oil and gas demand that should support current high oil and gas prices.  He also sees the Federal Reserve gauging the economy strong enough for them to move away from the zero interest rate policy of the past several years meaning that short-term interest rates will be rising as he sees the Federal funds rate hitting 2% by year-end.  At the same time, he thinks the heavy government borrowing and some reluctance by foreign central banks to keep buying U.S. government notes and bonds will drive the yield on the 10-year U.S. Treasury bond above 5.5%.  All of these trends will combine to help boost the value of the U.S. dollar that Mr. Wien believes is significantly undervalued. 

Higher interest rates would tend to slow the pace of economic growth from what it would otherwise be, thus restraining energy demand growth.  The strengthening U.S. dollar value will also depress the price of oil, which had a strong inverse correlation with the value of the dollar throughout most of 2009. 

Mr. Wien sees the Obama administration desiring to become a global leader in climate control initiatives.  He believes President Obama will announce a goal of reducing U.S. consumption of coal used to generate electricity near 50% now to 25% by 2020.  Besides pushing his existing renewable fuels agenda, Mr. Wien believes President Obama will endorse legislation to spur construction of new nuclear power plants – because they are good for the environment and create jobs.  We suspect Mr. Wien thinks President Obama has a difficult time supporting any fossil fuel, even the cleanest with the greatest domestic supplies – natural gas.  The biggest problem with this energy prediction is that even if it happens, new nuclear power plants will have little or no impact on the electricity market by 2020.

His last prediction impacting oil is for civil unrest in Iran reaching a crescendo and Mahmoud Ahmadinejad being pushed out of office by the leader of the regime and replaced by a more public relations adept leader.  Although geopolitical tensions are reduced, Iran still remains a nuclear threat.  While this prediction may carry weight in the stock market and on the front page of newspapers, as we saw during most of last year, developments dealing with Iran had little impact on crude oil prices.  The risk for oil prices is probably to the downside in 2010 as this surprise might defuse the push for sanctions against Iran and allow it to open up its oil and gas resources to foreign oil company (primarily Chinese) development. 

That might not have an impact in 2010, but it certainly could impact global energy markets in 2011.

The greatest question about Mr. Wien’s surprises for 2010 is whether any of them are sufficient to move energy markets significantly one way or the other.  We think not.  The biggest challenge for energy industry players (and especially forecasters) will be to not become blinded to underlying industry trends as the breezes separate wheat from the chaff.

The nation’s first planned offshore wind project has just been forced to jump over another hurdle by people opposed to it.  Resolution of the current conflict may prove interesting as it will force the Secretary of the Interior to make the final decision, but will he make it in time to enable the project to take advantage of federal stimulus money that could lower its cost?

Exhibit 11.  Artist’s Rendition of Cape Wind Project

Source:  Cape Wind

Cape Wind’s 130 turbine wind farm, planned for a 24-square mile block of Nantucket Sound, was tripped up by a determination of the National Park Service, an organization of the Department of the Interior, that all of that body of water can be designated a national historic landmark.  But also challenging Cape Wind is a growing opposition to the potential price for the surplus power the project plans to sell to Massachusetts’ electric utility, National Grid.  Despite optimism for the nation’s first-ever offshore wind farm happening, the goal line to start construction continues to be moved further down the field.

Exhibit 12.  “People of the First Light” Ritual View

Source:  Associated Press/The New York Times

In early November we wrote in the Musings about the efforts of two Massachusetts Indian tribes to get the Massachusetts and federal governments to list Nantucket Sound on the National Registry of Historic Places.  The two tribes – the Mashpee Wampanoag of Cape Cod and the Aquinnah Wampanoag of Martha’s Vineyard – sought the listing to protect their spiritual ritual of greeting the sunrise and their ancestral burial ground.  The Wampanoag are known as the “people of the first light” and their spiritual ritual requires an unobstructed view of the sunrise.  Tribal representatives also claim their ancestors hunted and walked on the Nantucket Sound seabed when it was dry land thousands of years ago and that tribe members are buried there.  Previous archeological studies of the seabed from when it was dry land during the last ice age and the coast was 75 miles further away from today’s shoreline found evidence of submerged forests six feet under the mud, but they never discovered signs of Native American camps or other signs of human life. 

Last November the Massachusetts State Historical Preservation Officer ruled in favor of the Indian tribes.  But since the Minerals Management Service (MMS), who has jurisdiction over the leasing of the land, had ruled for the wind farm developers, the issue was referred to the National Park Service.  Nantucket Sound, which covers 500 square miles, vastly exceeds the size of other bodies of water previously awarded the historical designation such as Walden Pond in Massachusetts, which covers about 60 acres, and Zuni Salt Lake in New Mexico, which is about 6,500 feet across.  Given the size differential and potential implications for other large bodies of water in the U.S., people were shocked when the National Park Service ruled for the Indians.

Interior Secretary Ken Salazar hosted a series of meetings last week with various interested parties involved with the disputed wind power project in an effort to get them to agree.  Sec. Salazar said a memorandum of understanding drafted last year might act as a starting point for a resolution, but the tribes and the anti-Cape Wind group, the Alliance to Protect Nantucket Sound, said they would not agree to any plan that kept the wind farm in the Sound.  They suggested the turbines could be relocated to an alternative site south of Tuckernuck Island that was already part of the MMS’s review.  Sec. Salazar said that would necessitate starting the permitting process all over again, a view disputed by the Alliance spokesperson.  The Aquinnah tribe representatives said they would have to study that site before they could commit to supporting it.  Cape Wind representatives said the site had been considered and ruled out as being more expensive and creating greater environmental harm. 

Exhibit 13.  Cape Wind Location

Source:  The New York Times

Sec. Salazar has given the parties until March 1st to reach a settlement.  Failing that he said he would make a decision within three months or likely before the end of April.  While Sec. Salazar has not tipped his hand as to which way he might rule, he is known as a big fan of alternative fuels and wind power in particular.  On the other hand, he heads the department overseeing Indian affairs that has recently reached a settlement with many of the tribes over the government’s stewardship of the income derived from the development of the natural resources on tribal land.  Additionally, the Obama administration is seen to favor the rights of minority groups.

Compounding the historical designation dispute are two other issues – the electric power contract and funding under the American Recovery and Reinvestment Act (ARRA).  Under ARRA, there are federal incentives for projects such as wind farms.  It is estimated Cape Wind could be eligible for funding that would reduce the project cost by up to 30%, which for a $1+ billion project is a meaningful amount.  The biggest hurdle is that ARRA requires construction of the wind farm to begin by the end of 2010 and be complete by the end of 2012.  As late as early December, Cape Wind director of communications, Mark Rodgers, said, “That works in with our planned time line, but it requires us moving expeditiously.”

The project’s lack of final federal government approval will certainly place more pressure on Cape Wind to meet the ARRA time line assuming Sec. Salazar’s decision is favorable, or the parties negotiate a resolution on their own.  A condition for moving forward is having a long-term electric power supply contract negotiated and approved in order to secure financing for construction of the project.  Cape Wind has begun contract discussions with National Grid that operates Massachusetts Electric Company and Nantucket Electric Company, which serve 1.2 million electric customers in the state.  The first step in the process is for the two parties to negotiate the terms of the contract.  Then they must file with the Massachusetts Department of Public Utilities (DPU) a “memorandum of understanding” (MOU), which details the rationale for the contract, along with the methods by which the two parties will pursue negotiating the contract and a deadline for completing the process.  Negotiations would formally commence after the DPU signs off on the MOU. 

The DPU must then review and approve the contract.  That process would likely take 60 days.  Because the contract process will at one point involve “a full adjudication process” by the DPU, there needs to be a formal public hearing.  The public review will serve to answer one of the long-standing questions: How much will the power generated by Cape Wind cost consumers?

Customers of National Grid, and especially industrial customers, are concerned about the cost of Cape Wind-generated electricity following the recent announcement of the terms of the contract National Grid negotiated with Deepwater Wind in Rhode Island for power from the wind farm to be built off Block Island.  The price was set at 24.4¢ per kilowatt hour (kWh) for electricity for 20 years, which will be escalated at a 3.5% rate per year over the life of the contract.  That price was three times the current price for electricity generated by natural gas-fired power plants.  The Rhode Island contract is estimated by Rhode Island officials as adding $16.20 per year, or roughly $1.35 per month, to the bill for an average customer using 500 kWh per month.

Officials in Massachusetts hope National Grid can negotiate a price with Cape Wind of 13¢ to 15¢/kWh, or roughly double today’s cost of 6¢ to 8¢/kWh for natural gas-generated electricity.  At debate is Cape Wind’s assertion the wind farm will generate $25 million a year in power cost savings.  According to Cape Wind representatives, energy costs in the area are determined on an hourly basis, with the price-per-hour set by the generation facility with the highest cost of generating energy for that hour.  All generators in the region are paid based on that amount, so facilities with very low operating costs, such as natural gas-fired plants, make a greater profit.  With the addition of wind power to the region’s available power supply, all other plants in the region would reduce their respective outputs meaning lower production costs and thus lower customer costs.  This position is supported in a study done last year for the region’s governors by the New England ISO.

Cape Cod residents who are looking to Cape Wind to supply up to an average of 75% of the region’s electricity hope to reap an additional benefit if the Canal Mirant power plant in Sandwich, Massachusetts does not have to be used as backup.  Since 2005, the plant has operated as a standby system for the New England grid, running during off-peak hours, at 17% of capacity, ready to fire up in the event the two transmission lines that carry power to Cape Cod fail simultaneously.  Cape Cod consumers are paying an “uplift” charge of 1.5¢/kWh for this insurance.  With the addition of wind power, the plant would need to run even less than in the past.  Over the past two years, to keep the Canal Mirant power plant on standby has cost residents of Cape Cod and southeastern Massachusetts more than $200 million, or the equivalent of 5% to 7% of the typical customer’s bill.

As the final push begins to get Cape Wind over the goal line, all eyes will be trained on Washington, D.C.  Will the attraction of the nation’s first offshore wind farm, which has the potential to boost the Obama administration’s global environmental standing following the failed Copenhagen climate conference prevail over the desire to preserve the rights of an important minority group who social scientists believe have been abused? 

Despite those governments assembled in Copenhagen last December being unable to cobble together a binding global warming agreement to follow the Kyoto Protocol, the private sector sees the search for clean energy technologies expanding.  That view is supported by the dollars committed to clean energy technology deals by venture capitalists last year.  According to a report by the Cleantech Group and Deloitte, more than $5.6 billion was invested in clean technology through 557 deals across North America, Europe, China and India.  That is down from 2008’s record investment but in line with 2007, the second-best year for the sector.

Once investors announce their final activity, the preliminary total is expected to increase by 5% to 10%.  If this additional money is forthcoming, then 2009 will rank as the record year for the number of cleantech deals, and about equal with 2007 for the amount of money invested. 

According to Nicholas Parker, chairman of the Cleantech Group, about a quarter of all the global venture capital investments were in clean technology.  That was more than the total amount of money invested in software, biotech or any other sector.  A stimulus for the venture capital cleantech investment surge was the influence of government spending worldwide in pursuit of businesses that could foster economic growth.  Anything with “green” in the description was favored.

Geographically, North America’s share of clean technology investments in 2009 fell to 62% from 72% in 2008.  That was a four-year low.  On the other hand, the share for Europe and Israel rose to 29% from 22% in 2008.  That was a five-year high.  Clearly cleantech investing is becoming a global phenomenon.  That view was reinforced by an analysis of the distribution of initial public offerings in the cleantech sector.  Some $4.7 billion was raised via 32 cleantech IPOs during 2009.  Of that total, some 72% was raised in Asia.  The average amount raised in Asia over the past three years was less than 10%. 

Another interesting trend was that the amount of money invested in solar energy companies was down 64% from 2008, while investing in energy efficiency-related companies increased 39%.  This trend, at least for solar investing, is consistent with the financial troubles many solar energy related companies experienced last year as solar panel prices plunged due to overcapacity in the industry and cutback in solar energy projects.  On the other hand, investors are recognizing the potential for capturing significant market opportunities by developing products and services that help address increasing energy efficiency.  Dallas Kachan, managing director of the Cleantech Group, says his group expects 2010 to be another strong year for cleantech investments and for cleantech IPOs.  He also sees the trend of investing shifting away from solar energy continuing this year when he said, “Energy efficiency will in fact eclipse solar.” 

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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.