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Musings from the Oil Patch - November 9, 2010

Musings From the Oil Patch
November 9, 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

Oil Industry Confronts Ghost Of Future Regulation (Top)

At the National Ocean Industries Association (NOIA) fall meeting held at the end of October, the audience of executives from oil and gas companies and oilfield service companies with a strong focus on drilling and producing in U.S. waters were treated to a presentation from Michael Bromwich, the new director of the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE, sometimes shortened to BOEM).  The conference program for that day was adjusted to squeeze in an extra 30 minutes of presentation time to accommodate Director Bromwich. 

The meeting room was filled by all the attending members in anticipation of the presentation.  There had been considerable speculation about what he would say and the tone he would use.  There were thoughts that Director Bromwich would use this conference of offshore industry executives to spell out more about his views on how quickly permits would be issued for drilling in the Gulf of Mexico.  There were other, more skeptical views suggesting that the presentation would be treated as more an obligatory necessity with little new and/or revolutionary information in his message. 

With great anticipation, the audience took its seats.  The session chairperson strode to the podium and began the introduction.  She forewarned the audience that Director Bromwich was on a tight schedule and only had 30 minutes with us, thus the reason why she was starting a bit early and wanted everyone’s attention.  After the requisite background comments highlighting Director Bromwich’s legal career and government service, including the highly-praised investigation of the Houston Medical Examiner’s Office, the introduction concluded.  Director Bromwich appeared from behind the stage and walked up to the podium.  After acknowledging the introductory comments and how he had met and gotten to know a number of industry executives in the audience as a result of the numerous hearings his organization had held with the industry dealing with the investigation of the Deepwater Horizon accident and the BP oil spill and the need for changes in offshore drilling procedures and safety rules, he launched into his prepared remarks. 

The opening thrust of the presentation was that there was a fundamental shortcoming in offshore drilling resources and capability to control a deepwater blowout compared to what the regulators had been led to believe.  The spill response effort was deemed inadequate and not acceptable.  He said neither the offshore industry nor the nation was prepared for the magnitude of the event that occurred.  The nearly 60 year safety and environmental record of the offshore oil and gas industry he attributed to luck!  If there was any statement that grated every member of the audience that was it.  All the advances in drilling, production and safety practices along with the technology developments were all the result of chance according to Director Bromwich. 

After swallowing that bitter pill, the audience waited for insights about when the first deepwater exploration drilling permits might be issued.  While the industry welcomed the lifting of the deepwater drilling moratorium, they have found it has only been replaced with a “permitorium.”  As the saying goes, a ‘rose by any other name is still a rose.’  A suspension of drilling activity, i.e., a moratorium, is still a suspension as long as the government won’t, or can’t, issue permits to drill.  Until permits start flowing, the Gulf of Mexico will truly bear the historical designation as the Dead Sea given it by long-time Tidewater (TDW-NYSE) Chairman John Laborde back in the late 1980s when oil and gas prices were severely depressed. 

Director Bromwich generated optimism among some in the audience with his comments about the timing of the granting of deepwater drilling permits.  He said he believed that a permit will be issued before year-end, but the reason for the timing was due to the agency having thrown all available resources on the issue.  But he acknowledged that the BOEMRE had only received one permit application so far.  We found in our discussions with attendees that virtually every major oil company was preparing an application, so it is hard to know who might be the lottery winner.

The optimism about the deepwater drilling permit situation was generated by the fact that Director Bromwich had not rejected the potential of an award before year-end.  Since he had previously said that the moratorium would likely be lifted early, which it was, his statement about a permit grant soon was treated as a positive prediction.  We understand the logic of this optimistic view, but would caveat that the decision to lift the deepwater drilling moratorium was driven by an entirely different set of circumstances, principally that there was an election and eliminating a voter irritant for some Gulf Coast Democratic Congressmen might help their re-election chances.  This action was just as politically motivated as the Environmental Protection Agency’s (EPA) decision to approve an increase in the percentage of ethanol that can be blended into motor gasoline from 10% to 15% for modern cars a few weeks ago.  One merely needs to note that there are some key Iowa and other corn-growing state congressional races that would be helped by improving the financial lot of farmers and ethanol plant owners. 

After discussing the reorganization of the former Minerals Management Service (MMS) into three separate and focused departments that eliminate the conflicts of interest and the potential for cozy regulatory relations, Director Bromwich went on to talk about his plans for the regulatory organization.  He would like to increase the regulatory staff by 200 inspectors and engineers.  To do that the agency has been contacting retired oil company offshore drilling and production engineers in hopes of getting some of them to return to the industry as a public service.  Of course, any returning retiree will present a huge conflict of interest management challenge for BOEMRE.  They certainly couldn’t oversee operations of their former employer or employers, but more importantly they would likely be conflicted from regulating any of their former employer’s joint venture partners, too.  The agency is also recruiting on college campuses where there are established petroleum education programs. 

While it is admirable seeing the effort of BOEMRE to attempt to recruit additional staff, one has to wonder how easily and quickly the effort will expand the capability of the agency.  Recent petroleum study graduates will certainly need extensive time and training before they will be prepared to do offshore inspections.  And recruiting retirees presents its own set of management challenges outlined above.  We had received an email from an industry participant two weeks ago pointing out that the BOEMRE web site listed only four job openings in the Gulf Coast region – one IT specialist, two interns and one engineer.  Last week, the listings had doubled to include two IT people, two interns and four engineers and inspectors.  At that recruitment pace it will take a while before 200 new engineers and inspectors are hired and trained.

At the end of his prepared remarks, Director Bromwich answered two questions posed by the session chairperson.  We assume that these questions had been previously prepared.  Then the session was opened up to questions from the audience.  The first question was somewhat unfriendly, although not presented that way, but its essence rested on certain premises that Director Bromwich took issue with.  The more insightful question involved the extension of leases due to the moratorium.  Director Bromwich said that there would be no blanket extension but rather they would be taken up on a case by case basis.  The determination would be whether the moratorium actually delayed drilling on the lease.  So while all drilling could be stopped by the moratorium, not all leases would be extended.  Although we don’t expect Todd Hornbeck and his team to be leading the charge to the courthouse on this issue, we certainly expect some producer will take the government to court over the inequity of this action.

After taking the two audience questions, Director Bromwich left the podium and exited by going behind the stage.  We were taken aback by this arrogant display by an industry regulator, but viewed it as part of the message he was delivering – we are here to regulate you and as such we will be judge and jury, which means we cannot mingle. 

We may be proven wrong, but it is our belief that Director Bromwich’s arrogant appearance at the NOIA meeting signals a more adversarial relationship between BOEMRE and the industry.  Clearly we are only just beginning to see the new offshore drilling and safety regulations.  But it was clear from Director Bromwich’s comments that more regulations are coming and they have yet to be written.  If you want to chill oil industry spending, create an environment where no one knows the rules.  We haven’t even addressed the impact on offshore activity from higher producer liability limits and other rules that will limit the number of oil and gas companies that can operate in the Gulf of Mexico.  It is hard to see any quick return to offshore activity levels that approach those that existed before the Deepwater Horizon disaster.  We see at best a long, slow recovery in Gulf of Mexico activity.

Energy Stocks Have Mostly Trailed Market This Year (Top)

The results of the November 2nd election and the recent Federal Reserve Bank’s announcement that it was embarking on another attempt to stimulate the economy by encouraging bank lending through a program to provide more liquidity to the banking system, known as the second quantitative easing, or QE2, have driven the stock market to levels that existed immediately before the collapse of Lehman Brothers.  Accompanying the QE2 announcement, the worth of the United States dollar among world currencies fell in value helping to boost the price of commodities including crude oil.  Natural gas prices in the U.S. have not benefitted from the weakening dollar as the product is truly a local one. 

When we look at the performance so far in 2010 for the overall stock market, as measured by the Standard & Poor’s 500 Stock Price Index, it has been solid.  The S&P 500 index is up nearly 10% through the end of last week, and is at a level exceeding that achieved in late spring this year.  But when we look at the performance of energy stocks, they have tended to lag the performance of the overall stock market despite the strong impetuous from commodity prices.

If we look at what has happened this year in energy markets, there have been two primary events that have shaped the business – the Gulf of Mexico oil spill disaster and the recovery in economy activity following the 2008-2009 recession.  While energy demand has recovered from the drastic drop experienced last year due to the recession, the combination of rising supply and continued subpar economic growth and energy demand in the industrialized economies of the world has muted the magnitude of the oil price rise.  Crude oil is denominated in U.S. dollars globally, and its price is impacted by the fluctuating value of the U.S. dollar.  At various points in time during the year oil prices rose or fell sharply in response to movements in the value of the dollar, however, there was no sustained move in any direction either up or down.  As a result, the price of oil on the futures market has remained within a trading range of $68 to $86 per barrel as shown by the straight lines bracketing the oil price line in the exhibit below.

Exhibit 1.  Energy Stocks Mirror Commodity Moves; Lag Market
Energy Stocks Mirror Commodity Moves; Lag    Market
Source:  Yahoo Finance, EIA, PPHB

When we look at crude oil prices during this year so far, it becomes clear there were periods when the price movements up and down were quite sharp.  These moves mostly coincided with economic data and political events that either helped boost or weakened the value of the U.S. dollar.  What also becomes evident when looking at the stock market performance of the various energy segments and the overall stock market index was just how correlated they have been with the price movements of crude oil, even though the stocks are indexed in value to the start of 2010 and crude oil prices are stated in absolute dollar terms. 

When we turn to the relative performance of the energy sector versus the overall stock market, we see that for most of this year energy has lagged.  The one sector that has outperformed all the other energy sectors along with the overall market was the OSX, or the Philadelphia Oil Service Sector.  This industry sector did well in the first third of the year until the Deepwater Horizon disaster in late April and the resulting BP oil spill.  From outperforming the overall stock market by nearly 10 percentage points in April, the OSX, at its low in the summer, underperformed the market by nearly 15 percentage points.  Today, the OSX is ahead of the overall stock market performance for the year, and is leading all other energy sectors.  Why is it the case?

We suspect that the over-performance is a combination of factors including: better earnings prospects through more global business exposure; small cap stocks that can outperform large cap stocks during periods of market volatility; merger and acquisition events; and strong balance sheets that can fund increased capital investments, higher dividends and more stock buybacks.  The importance of these characteristics cannot be underestimated as they have helped to overcome the weakness oil and gas companies have experienced in natural gas prices and energy demand that has impacted crude oil operations. 

As a result of the Deepwater Horizon disaster in late spring, those offshore contract drilling and supply vessel companies tied to the Gulf of Mexico by either their equipment capabilities or organizational structure suffered greater stock market price declines than their competitors with more global operating footprints.  Additionally, the offshore contract drilling and supply vessel companies suffered greater stock price declines than the broad-based oilfield service companies with large international operations.  Wall Street perceived that international oilfield activity would continue to grow even while the offshore industry was suffering and that Gulf of Mexico-centric companies would be hurt the most.

The relative performance of small cap versus large cap stocks seems to be shifting in favor of the oilfield service stocks, although this trend is somewhat a function of the risk trade investors are willing to assume.  The stock market oscillates between periods when small caps are in investor favor and they outperform their large cap peers, and vice versa.  The types of stocks that do well at any particular point in time are largely a function of their earnings prospects and their financial strength.  In times when business is deteriorating, investors favor companies with large and strong balance sheets in order to offset the economic and financial risks from a weak economy.  On the other hand, when investors focus solely on how fast companies can grow their earnings, then small caps become the preferred investment vehicle.

The oilfield service industry appears to be in the midst of a restructuring of its business.  So far this year we have seen two major service companies disappear – BJ Services and Smith International – as they were gobbled up by larger competitors.  In the past week we had two offshore drilling companies signal the possibility that they might be sold – either to another contract drilling company or possibly to private investors.  We have also seen a number of smaller companies acquired by larger strategic industry buyers, which has reduced the number of companies available for money managers seeking a presence in this investment space.  Companies such as Dresser-Rand (DRC-NYSE), Allis-Chalmers Energy (ALY-NYSE) and Superior Well Services have all been the subject of acquisition transactions either closed or underway.  All of these transactions mask significant acquisition activity among small companies and demonstrate that the oilfield service industry is in a rapid restructuring phase.

Balance sheets of oilfield service companies are quite strong, a reflection of management lessons learned during past industry downturns.  Managers learned that financial leverage is an accelerant for growth in up-cycles, but can destroy businesses in down-cycles.  Low debt levels and meaningful cash balances have become the preferred operating philosophy for oilfield service companies.  As a result, managements are constantly weighing how much money to allocate for new capital investments to fuel future growth versus rewarding shareholders through increased cash dividends and stock repurchases. 

When it comes to dividends and share repurchases, understanding the role each plays in rewarding shareholders is important for managers.  Buying back shares is a way to shrink the denominator in the earnings per share calculation.  The theory is that when cash is used to repurchase shares, the lost interest earnings will be more than made up for by the boost in earnings per share from fewer shares and the resulting company valuation will increase.  In theory this exercise should lead to a higher stock price, but in practice share prices often do not benefit from the shrinking capitalization.  What happens is that shareholders seeking to exit from their holdings are rewarded as the stock price paid often does not appreciate sufficiently to offset the lost income from the cash used to effect the transaction.

Another negative about stock buybacks is that managers elect to do them when they have excess cash.  That often occurs at or near the top of business cycles when share prices tend to be highly valued.  As we have seen in the past, share repurchases in this cycle peaked in 2007 as the stock market was advancing steadily only to crash in 2008 with the financial crisis.  The net result was that the returns earned from the cash utilized to repurchase shares were negative.  The fall in the stock market was one reason stock buyback returns were negative, but this approach for returning cash to shareholders ignores the fact that the share repurchases were one-time events and there was little reason to remain loyal to the company.

Exhibit 2.  Stock Buybacks Often Come At Market Tops
Stock Buybacks Often Come At Market Tops
Source:  GMO White Paper

Historically, income from dividends and growing dividends have accounted for a meaningful share of the total returns earned by shareholders as shown for the period 1871-2009 in Exhibit 3.  Over this very long historical period, dividends accounted for nearly 90% of the return to investors.  On the other hand, in periods when stock prices are falling, dividends provide a positive offset to the negative returns from continuing to hold on to shares as was the case in 2000-2009.  Importantly, dividends, and especially dividend increases, represent positive statements by managers about the health and outlook for their companies.  Dividends tend to rise slowly as companies grow stronger and more profitable. 

Exhibit 3.  Dividends Are Important In Total Return
Dividends Are Important In Total Return
Source:  GMO White Paper

Dividends are not just a U.S. phenomenon.  Since 1970, dividends have played a large role in returns earned by investors around the world as demonstrated by the chart in Exhibit 4.  In Europe, anywhere from 80% to 100% of the total returns earned by investors since 1970 has come from dividends when both the current yield and dividend growth components are considered.  The importance of dividends for investors was driven home this summer when BP (BP-NYSE) elected to stop paying its dividend while it was engaged in cleaning up the oil spilling from its Macondo well in the Gulf of Mexico.  Prior to the dividend elimination, BP’s payment accounted for £1 ($1.62) of every £6 ($9.72) paid out in dividends to British pension holders, or nearly 17% of their dividend income. 

Exhibit 4.  Dividends Worldwide Are Important
Dividends Worldwide Are Important
Source:  GMO White Paper

As we start the 11th month of the first year of the new decade, energy stocks in general have lagged the performance of the overall stock market.  The energy business has entered a new phase following the strong growth period that marked the decade of the Aughts.  We continue to believe this decade may prove as challenging for energy companies relative to the Aughts as the 1980s were for those companies riding the rocket powered by high energy prices in the 1970s.  While it was impossible at the start of the 1980s to envision the total collapse in global oil prices that occurred merely a few years hence, it is equally as impossible to envision the scenario that would mirror the collapse in the coming decade.  For those of us who have lived through these great industry cycles, we try not to look too far ahead when walking to avoid stepping into a pothole.  Our hope is that any pothole we do step into doesn’t turn out to be a chasm. 

Future Of The Gulf Of Mexico Oil And Gas Industry (Top)

The overriding topic of interest at the recent National Ocean Industries Association (NOIA) conference was the future of the offshore industry operating and depending on work in the Gulf of Mexico.  Several sessions of the conference were devoted to topics related to the question: When will we get back to work?  Besides a session with Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) Director Michael Bromwich, there was a panel of four senior executives from producers and an oil service company discussing changes confronting the offshore industry.  Another session reviewed the activities of joint industry task forces set up to address various issues arising from the Deepwater Horizon disaster and the resulting oil spill.  There was also a session dealing with the future of oil spill management. 

The general consensus from these sessions was that the world of offshore oil and gas has changed and will never return to the way it was in the past.  As a result, industry participants will need to be open to making organizational and operational changes in how they conduct their business in the future. 

One presentation dealt with the establishment and operation of the Marine Well Containment Company, the joint venture of four major oil companies operating in the Gulf of Mexico, which will design, build and maintain ready for deployment equipment for capping and containing a spill from a deepwater well.  It was the absence of this capability that drew the greatest criticism from the Federal government, national and local politicians and the media.  The equipment being designed and built by this company will be able to handle a well blowout in 10,000 feet of water and oil spewing at a rate of as much as 100,000 barrels per day.  These capabilities comfortably exceeded the well depth and daily spill rate of BP’s (BP-NYSE) Macondo well. 

The four oil company partners in this venture have pledged an investment of $1 billion to create the non-profit company, design and build the equipment, contract additional spill clean-up equipment and provide for a permanent professional management team to maintain the equipment in a state of constant readiness.  This new company will be the Gulf of Mexico’s equivalent of your local “fire department” – always ready to respond but hoping never to be called upon. 

The presentation described various aspects of the equipment being designed and built, but that is not the thrust of this article.  The company will be open to all operators in the Gulf of Mexico who can become members and pay a pro-rata share of the investment and operating expense.  It will also provide a structure to accommodate the use of the equipment by non-members for a premium fee.  The non-profit company should be established before the end of the year, but it will take 18 months before all the well capping and spill containment equipment is built.  The company anticipates striking a deal, hopefully by January 1st, to assume control of some of the oil spill equipment and vessels currently under contract to BP. 

The establishment of the Marine Well Containment Company and the contracting of some of BP’s oil spill equipment may be critical in the determination of when permits will be issued to the oil and gas industry so it can resume working in the Gulf of Mexico.  Director Bromwich cited the growing availability of spill response equipment following the successful capping of the Macondo well as part of the reasoning behind lifting the government-imposed deepwater moratorium.  One of the issues with securing new deepwater drilling permits is detailing how the oil company will deal with a worse-case well discharge.  There is a huge difference between capping and containing an unconstrained well compared to a constrained one.  It is possible that an unconstrained deepwater well could generate a flow rate that would exceed the capability of the Marine Well Containment Company’s equipment.  On the other hand, it is most likely that well blowouts will involve constrained wells, ones that have a blowout preventer, albeit probably damaged.  The Marine Well Containment Company believes that the equipment and systems it is building could be readily expanded to deal with double the stated containment capacity.

While the spill response equipment is a critical part of satisfying the concerns of the BOEMRE with regards to granting new deepwater drilling permits, satisfying other aspects of the permitting process may become difficult hurdles for producers to overcome.  If the pace of permitting doesn’t accelerate soon, it is only a matter of time before operators and service companies reach the conclusion that the grass really is greener on the other side of the ocean and exit the Gulf of Mexico.  Among the panelists discussing how to get the offshore industry back to work, the issue of the lack of support from BOEMRE for extending deepwater leases that were subject to the deepwater moratorium was considered a significant disappointment, especially after Director Bromwich’s earlier comments. 

Another operator with both Gulf of Mexico and North Sea experience noted that the latter’s regulatory system often becomes quite bureaucratic, which slows down the permitting process.  Based on comments from other attendees who have secured well workover and plug and abandonment permits, the review process has become bureaucratic with all decision-making authority having been stripped from the regional offices of BOEMRE and consolidated in Washington, D.C.  There were also observations that questions asked during the permit review process stopped the review until the answer to the question was supplied.  This back and forth process clearly is slowing the permitting process and there is little producers can do to help speed it up.  There is also no understanding whether the questions being asked by BOEMRE inspectors are designed specifically to slow the permitting process (the conspiracy theory).

A representative from Shell Oil (RDS-A-NYSE) pointed out that his company was preparing permit requests that comply with the new rules and that they hope will lead to the company returning to drilling before the end of the year.  But he pointed out a possibly serious impediment – the elimination of environmental exclusions.  Rather than being able to rely on a regional environmental impact statement, the oil company will have to go back to BOEMRE on a well or lease basis.  This will slow the process, and significantly retard the pace if the oil company has to prepare a supplemental environmental impact statement.  That process can consume up to a year of time.  All of these permitting issues could put at risk the timing of two Gulf of Mexico lease sales scheduled for 2011.  Ultimately, the combination of these issues could, according to Shell, put at risk as much as 400,000 barrels per day of future oil production planned to offset an equal volume that will be lost to depletion out of the 30% share of U.S. oil production that comes from the Gulf of Mexico.  That body of water also accounts for 10% of the nation’s natural gas production, but the success of onshore gas shales minimizes the risk of falling offshore gas production.

He also pointed out that Shell has been able to handle the costs related to the deepwater moratorium so far, but at some point if permits aren’t granted, the cost of idle rigs will become too great.  Another speaker pointed out that rig certification is an issue compounding rig contracting.  Getting a permit is one thing, but an operator can’t be assured the drilling rig under contract can be certified.  That risk will impact well timing and drilling costs.

The impact of these permitting problems will also fall on the offshore oil service industry.  As a speaker from Hornbeck Offshore (HOS-NYSE) put it, the future Gulf of Mexico market will be characterized by more risk, higher costs, a slower work tempo and a “compliance culture” that will drive regulatory costs much higher than the Federal government’s $183 million estimate.  In Hornbeck’s estimation, it will be 18 months before the Gulf of Mexico is back to normal permitting time and the industry is operating 33 drilling rigs as it was before the Deepwater Horizon accident.

He also said there will be other impacts on the offshore oil service industry.  The increased risk profile of producers is likely to drive them toward quality equipment and crews.  That means higher spec vessels, which will further drive up costs.  Oil service companies will need to focus on ethics and safety to an even greater extent than they do today.  Until better times drive increased activity offshore, there is a risk of mariner shortages as workers go abroad for work.  The shoreside and shipyard infrastructure in the Gulf of Mexico will be weakened as investment slows down.  How much of this capability might be lost and what will be the impact on future operating costs?  Lastly, he thinks the compliance culture will spread across the world raising costs everywhere; just one more example of how the oilfield service world has been changed by this disaster. 

We believe one of the great unknowns for the Gulf of Mexico is the impact of these regulatory changes on capital flows within the oil and gas industry.  If oil spill liability limits are eliminated, it will make it almost impossible for smaller producers to obtain insurance.  Many of these smaller companies will be forced to abandon the offshore.  What happens to their existing leases?  What about their participation in operating consortiums?  Will the larger remaining companies have to pick up the share of the exiting company?  If so, how will that impact oil company budgets and their willingness to accept an involuntary increase in spending in domestic waters.  For companies with global exploration portfolios, there is always a struggle in the annual budgeting process over allocating spending on a geographic basis.  If one region begins to see its share of the company’s total spending growing disproportionately, will management slow down spending on other planned projects?

Another issue that hasn’t been discussed much so far, but will also impact oil producer spending is the mandate to remove “idle iron.”  BOEMRE has mandated that the pace of plugging and abandoning existing but non-producing offshore wells, which usually means removing the platforms and well caissons, too.  This work has been underway for a number of years, but the pace has been modest.  The pressure to accelerate this abandonment work will strain the equipment and personnel situation along with consuming a greater share of producer budgets.  Unless budgets are increased, more abandonment spending will force cuts in exploration and development spending.  Until the rules for operating in the Gulf of Mexico are spelled out, the 2011 budgeting process that is well underway in oil and gas companies will have to err on the side of conservatism and that doesn’t bode well for any quick recovery in offshore operations.  Of course, if there aren’t any permits granted there won’t be any spending.

April 20, 2010, marks the date the offshore oil and gas industry’s world changed.  It will never go back to what it was before the Deepwater Horizon disaster.  The big question is whether when the industry does resume operations will it be anything like it was before that date?  We fear it won’t.

J.D. Power Didn’t Get The Electric Vehicle Hype Memo (Top)

The road shows conducted by American automobile manufacturers to promote the impending introduction of their new electric vehicles (EV) are in high gear.  The result has been numerous newspaper, television and internet stories about the solid performance and attractiveness of these new EVs.  Recently, one news story discussed how General Motors’ Chevrolet division benchmarked its Volt EV model against VW’s Jetta sporty sedan for driving performance. 

The Nissan (NSSNY-NYSE) Leaf and the Chevrolet Volt are being highly touted by auto writers.  In fact, many of these auto writers have called these EVs “the real thing.”  The observations are partly driven by the fact that the vehicles drive well.  The problem is that the readers of these auto columns are not so sure they agree.

For the past 18 months various auto industry sales projections have focused on how much of the future American automobile market alternative vehicles will seize.  This was especially true in recent forecasts that became part of the EV hype.  An interesting article was written by Going-Electric.com that presented data on optimistic and pessimistic forecasts for EVs.  As the chart in Exhibit 5 shows, by 2030, the optimistic forecast calls for almost 30% of the market going to EVs, while the pessimistic forecast says the share will barely reach 10%. 

Exhibit 5.  Optimistic And Pessimistic EV Sales Forecasts
Optimistic And Pessimistic EV Sales    Forecasts
Source:  Going-Electric.com

What Going-Electric.com goes on to predict is that the sales curve will not be linear as suggested by all the other forecasts contained in the chart in Exhibit 6.  Rather, it believes that sometime after 2020 the sales curve for EVs will rapidly rise until it accounts for nearly 100% of auto sales.  Note that the projected sales curves do not forecast the number of EV auto units to be sold, but instead forecast only the proportion that will be EVs.  The reason why Going-Electric.com believes EVs will approach 100% of car sales at some point in the future are because high production volumes and technological improvements in batteries will reduce EV prices to the point they will become highly competitive with ICE vehicles.  It also believes that within 10-20 years, oil prices will be much higher deterring purchases of ICE vehicles.  Lastly, and probably the most controversial assumption, is that it believes that once EVs are accepted by consumers, local governments will restrain the use of ICE vehicles within city limits to reduce urban pollution and noise along with offsetting their damaging health effects. 

Exhibit 6.  Expected Soaring Acceptance Of EVs
Expected Soaring Acceptance Of EVs
Source:  Going-Electric.com

Another of the optimistic forecasts for EVs was made by Bloomberg New Energy Finance that said it expects plug-in EVs (PHEV) to make up 9% of auto sales in 2020 and increase its market share dramatically to 22% by 2030.  These market share forecasts imply that there will be 1.6 million and 4.0 million PHEVs sold in 2020 and 2030, respectively.  PHEVs represent only a portion of the EV industry, so this forecast implies a much greater EV fleet.  It is clear that this and other optimistic EV forecasts have prompted the Obama administration to provide $8 billion in loans, grants and financing help for EV battery plants in the U.S. and further battery research and development efforts. 

With all these optimistic forecasts, the support of the Obama administration and the conviction of automobile manufacturers, how can EVs not be the next great clean energy success?  All these supporters obviously haven’t read the J.D. Power & Associates report on EVs.  The firm is the leading chronicler of the automobile industry and the keeper of the best data on automobile customer buying habits and attitudes. 

J.D. Power believes that battery powered cars will ultimately drive the electrification of the alternative vehicle segment of the auto fleet.  However, because of consumer attitudes and the host of critical issues EVs must overcome, J.D. Power does not believe that EVs will capture as much market share as other auto sales forecasters.  In the recent study, the firm estimates that the global sales of EVs will total 954,000 units or about 2.2% this year.  They see EV sales rising to 5.2 million cars in 2020 out of global sales of 70.9 million vehicles, or a 7.3% market share. 

The study listed a handful of reasons and challenges to rapid success of EVs.  Among the issues J.D. Power identified include: range anxiety; lack of support infrastructure; lack of power and performance; questions about the true fuel economy of EVs; limited battery life and battery replacement cost; overall cost of vehicle ownership; and the extensive time required to recharge battery packs.  Consumers will be very upset the first time they realize that they forgot to plug in their EV overnight as they confront a car with little or no battery charge.  This will be especially challenging whenever an emergency arises and the car is not charged.  As we wrote in our last Musings, there is also the issue of battery degradation that shortens the maximum battery performance of EVs due to weather conditions. 

Exhibit 7.  Current State Of The EV And ICE Markets
Current State Of The EV And ICE Markets
Source:  J.D. Power and Associates

EVs will suffer initially from a problem of industry profitability.  The new EV models will have very limited sales in 2011, which will boost their cost.  Moreover, EVs will be competing against ICE vehicles with low prices driven by high sales.  Because traditional ICE vehicles have outstanding gasoline mileage and current gasoline prices are low, this cost/volume issue will be a limiting factor restricting rapid growth of the EV fleet even with hefty government subsidies. 

Exhibit 8.  Cost Of EVs Reduces Consumer Interest Level
Cost Of EVs Reduces Consumer Interest Level
Source:  J.D. Power and Associates

Despite these challenges, the firm believes there is a future for EVs.  The study was based on existing knowledge and in-house data along with recent surveys of auto buyer attitudes.  The firm found that prospective auto buyers were highly interested in EVs until they were confronted with the economics of their buying decision.  According to the study, 61% of prospective buyers were interested in purchasing HEVs, but that interest dropped in half (30%) when the customers were informed that the price differential with a conventional ICE vehicle was $5,000.  Similarly, 17% of those surveyed were in favor of BEVs, but the percentage of support fell to 5% after buyers learned that the cost could be as much as $15,000 more than a traditional ICE vehicle.  PHEVs also experienced a nearly 50% drop in buyer interest when consumers were informed of the $7,500 cost premium.  The most interesting cost premium comparison was for clean diesels.  There the cost differential was only $1,800, which minimized the drop in buyer interest from 35% to 31%.  As Mike Omatoso with J.D. Power put it, “People definitely think with their wallet.” 

Mr. Omatoso said that the survey shows that the main reason consumers consider a hybrid is lower fuel costs.  The main reason to reject a hybrid is the cost premium.  He went on to state that “as long as gasoline prices remain below $4 per gallon, there’s not going to be a true demand for hybrids, plug-ins and battery electric vehicles.”  At the same time, cost premiums for hybrids range between $2,000 and $10,000 per car while for plug-ins it is $15,000.  The cost premium for EVs ranges from $15,000 to $20,000.  For EVs to be successful they will need government subsidies or automakers will need to eat part of their cost.

Exhibit 9.  What Appeals To EV Buyers About EVs
What Appeals To EV Buyers About EVs
Source:  J.D. Power and Associates

The principal reason why auto buyers favor EVs is for their better gasoline mileage (90%/40%), their positive environmental impact (70%/10%) and their advanced technology (70%/32%).  On the other hand, auto buyers in general favor certain characteristics in their vehicles that don’t rank as highly in the selection process for EVs.  For example, overall buyers look for durability in their cars (63%/57%).  General buyers consider interior comfort higher than EV buyers (50%/36%) along with exterior vehicle styling (47%/24%).  The interest or lack thereof in certain vehicle characteristics by EV buyers conveys an image of them as Geeks – more interested in technology and less in creature comforts.  The true test of their “Geekiness” is how willing they are to sacrifice comfort and styling over technology.  It looks to us as though EV buyers don’t necessarily shun comfort and styling, but they do favor EV technology much more than the overall car buying public. 

Exhibit 10.  What Auto Buyers Favor That EV Buyers Don’t
What Auto Buyers Favor That EV Buyers Don’t
Source:  J.D. Power and Associates

One of the most interesting things we found in the J.D. Power study was its brief history of EVs and the auto industry.  They pointed out that in the early 1900s, EVs were more common vehicles than they are today.  In fact, in 1918 there were 50,000 EVs in the United States, but due to technological improvements and logistical developments in the early 1900s, ICE vehicles eclipsed EVs.  The particular events J.D. Power cited for the success of ICE vehicles over EVs was Henry Ford’s introduction of the Model T in 1908.  That car was one-quarter the cost of a battery powered EV.  In 1911, Charles Kettiring invented the electric starter that eliminated the hand crank needed to start ICE vehicles.  The final straw that broke the back of the EV industry was the passage of the Federal Highway Act of 1921 that started the nation on a highway building program that opened up easier and faster routes of travel for autos.  The greater range of ICE vehicles coupled with a growing national highway system was the key to the demise of EVs.  Is there a set of industry conditions that will drive EV growth at the expense of ICE vehicles?  So far those conditions involve government subsidies and mandates, not free-market conditions.

Third Quarter Wind Speed Data Shows Variability (Top)

The latest data on wind speeds recorded in the United States and Europe and presented by 3Tier shows great variability.  The variability reinforces the challenge wind energy has for establishing its role in the global energy spectrum.  As countries around the world add to their wind generating capacity, the issue of what role wind energy will pay in meeting overall energy supplies becomes more challenging.  A number of countries are attempting to push wind energy as an alternative for coal-fired power.  The challenge is that wind power, by the nature of its variability and intensity, tends to disappear as a reliable energy source exactly when the electricity demand escalates.  

The wind data reported for the third quarter in the United States shows that wind speeds of 10% or above the average were experienced across a wide band of the country stretching from Texas through the Great Lakes and into eastern Canada.  The data showed that there was less of a patchwork of wind speed variability than normally experienced in the U.S.  The wind performance data will be seized upon by wind energy advocates to show that this power source is so consistent it should be able to fulfill the role of baseload power in place of coal-fired power plants.  

Exhibit 11.  North American Wind Speed Variance
North American Wind Speed Variance
Source:  3Tier

In contrast to the U.S. wind picture, Europe experienced a subnormal performance that was reflected in a large patchwork of below average wind speeds along with some areas experiencing above average wind speeds.  The primary force influencing the wind speed performance for the quarter was a prolonged high pressure system over Russia that caused the extreme heat wave that destroyed a large portion of the country’s wheat harvest along with depressing wind speeds in neighboring regions.  The blocking high pressure system depressed wind speeds below their long-term averages across most of central and northern Europe.

There were isolated areas of Europe that experienced better wind conditions, or more than 10% or more above average.  These areas included the United Kingdom, southern Sweden, a band from the Balkans through Romania and to almost the entire Mediterranean coast along France and in northern Italy. 

Exhibit 12.  European Wind Speed Variance This Fall
European Wind Speed Variance This Fall
Source:  3Tier

This wind speed variability compared to the average wind speed for different regions of Europe and America points up the difficulty in planning the location of wind farms.  Moreover, it highlights the risk of dependence upon alternative energy supplies when cheap and consistent energy supplies are available.  Wind energy remains a favorite of environmentalists and politicians because they see all the benefits and none of the challenges.  In particular, politicians believe that wind power will add “green jobs” something they believe makes economic sense.  The problem is that the jobs claimed to come from wind energy projects have not materialized. 

Debate Continues About Volt’s Status As An Electric Vehicle (Top)

We discussed the electric vehicle (EV) industry in the last Musings, and made reference to the emerging debate over whether the Chevrolet Volt was an EV or a plug-in hybrid EV.  Auto writers who have been touting the outstanding driving performance of the Volt all say it is an EV.  They adhere to the explanation from Pam Fletcher, General Motors’ global chief engineer for the Volt power train, who said that the car cannot run without the battery but it can run without its gasoline engine.  Therefore, she and her company designate the Volt as an EV. 

The Society of Automobile Engineers conducted a survey of its membership asking the question of whether the Volt was an EV or not.  An overwhelming 67% of those surveyed said the Volt was a plug-in hybrid EV while only 7% said it was an EV.  The more interesting outcome from the survey was that 25% of those surveyed said the Volt was whatever General Motors wanted to call it.  I guess we shouldn’t be surprised by the high percentage of SAE members who have either no idea what the difference is between these models or lack the conviction to state their opinion.  This is probably the same proportion of media people who believe black is white and vice versa.

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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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