Musings From the Oil Patch, October 23, 2012

• BSEE Vs. Offshore Service Industry: A Compromised Policy?
• Does Rebound In Price Signal Return To Health For Gas?
• Thoughts About The Changing Energy Industry Landscape
• Politics Hampers Efforts For Correcting Energy Imbalances
• Energy Poll Backs Obama But By People Without Knowledge
• Global Economic Growth Continues Slowing: Hurts Energy
• Everyone Loves Wind Energy Except For Its Neighbors

Musings From the Oil Patch
October 23, 2012

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 October 15th deadline passed for appealing the final drilling rule promulgated by the Bureau of Safety and Environmental Enforcement (BSEE) that includes a statement justifying the extension of offshore regulation beyond lessees to include all service contractors working for an operator.  There was considerable discussion amongst some service companies and their lawyers about appealing the ruling through the internal process at BSEE, but two primary considerations influenced the decision not to appeal.  One consideration was the belief there is statutory language in the Outer Continental Shelf Leasing Act (OCSLA) that can be construed as granting BSEE regulatory authority over the service industry but which it has never exercised until now.  This consideration is called the “dead on arrival” argument.  The second consideration was twofold.  First, service companies don’t want to upset their customers by challenging the working relationship with BSEE, or the “don’t rock the boat” argument.  Secondly, the industry has a long-standing positive working relationship with Admiral James Watson, retired, who now heads BSEE, or the “trust me, I’m from the government and I’m here to help you” belief.  We think the industry may be making a serious miscalculation. 

To us there are only two issues: does BSEE have the statutory authority to regulate offshore service contractors, but even if it does, has it followed the established rulemaking procedure that allows the service companies input into the final rules they will be required to work under?  On the first point, we understand extensive legal research has been conducted by outside lawyers for one of the large service contractors that has uncovered information in the government’s archives showing that specific language directed to the service contractors was originally included in the draft OCSLA bill when it was being debated in Congress.  This language, we understand, was removed from the final bill’s draft after the respective House and Senate versions of the bill were passed and then sent to a joint Congressional committee to negotiate the final compromise language for what now forms the OCSLA law.  As we were taught in our constitutional law course, the courts oftentimes will look to the legislative history of a bill to help understand the intent of Congress with respect to issues that are unclear in the language.  The legislative history uncovered by these lawyers suggests that the inclusion and subsequent removal of language directed to service contractors indicates that Congress did not want them included in the offshore regulatory process.  Rather, the Congress wished all regulatory dealings to be between the federal government and the operator/lessee.

But even if the courts uphold the interpretation that BSEE has always had the authority to regulate service contractors, there are serious questions about whether the agency has followed the proper procedures for creating those rules and regulations.  Therein lays the true issue.  If a service contractor is going to be regulated, shouldn’t it want input into the creation of these rules and regulations as provided for under the law?  The service company idea that fighting for this right would upset the operator/lessees (their customers) seems shortsighted.  Ultimately, the rules will impact service company costs that lessees will have to pay or lose the use of these contractors.  These rules will also impact the cost of insurance for both the service companies and the lessees, and quite possibly even the ability of service contractors to secure insurance if the operational risks are considered too great.  Won’t that have a potentially huge impact on lessees?  Shouldn’t lessees want the offshore operational landscape resolved?

The idea that the service companies can rely on their positive relationship with Admiral Watson, while noble, is a high risk strategy from multiple perspectives.  First, the current goodwill could change, and change suddenly.  Admiral Watson could conceivably be hit by the famous bus while crossing the street.  Or, he could retire or be replaced by a new administration.  Secondly, to expect Admiral Watson to reach down several layers in his organization to overturn the actions of an offshore inspector would violate all the rules of standing for managing a bureaucracy.  For a life-long military man to violate the chain of command is a stretch in our view.  Lastly, to think that the service companies can influence, or seek special treatment is a retreat to the old days of how the industry worked with its former regulator, the Minerals Management Service (MMS).  The problems within the MMS became a scandal that ultimately led to its reorganization that created BSEE along with two other regulatory organizations.  Coddling the offshore petroleum industry was considered at the root of the regulatory failure that permitted the Macondo disaster.  Attempting to resurrect a failed playbook for dealing with offshore regulation could be a huge mistake.

The extension of BSEE’s authority to regulate the offshore service contractors is, in our mind, a significant watershed event for the entire offshore oil and gas industry.  The service companies are now part of a regulated industry, to the extent it does not fully appreciate.  While the regulations haven’t extended to determining allowed financial rates of return restrictions, who’s to say that couldn’t happen.  For service company CEOs, who are responsible for controlling the risk/reward balance within their companies, this new regulatory landscape has changed the old risk/reward balance.  The idea expressed by some CEOs that since the Gulf of Mexico is only a small portion of their business and if the risks become too great they will leave is short-sighted.  What would be the reaction to that move by their customers – especially the international ones?  What happens if more of the OCS waters are opened for exploration and development, significantly expanding the market opportunity they have elected to abandon? 

The offshore service industry needs to challenge the BSEE regulatory extension, if for no other reason than to be able to help define the future rules and regulations.  Working offshore cannot be treated as a pickup football game where the goal line is determined to be between a telephone pole and tree.  We hope service company managements give serious thought to all the unintended consequences of not fighting for their rights under the law.

Natural gas prices have been on the move – higher!  They are up based on less gas in storage than people feared would be there at this point in the lead up to winter, which is largely a result of increased gas consumption by electric utilities and a slowing of the growth rate for gas supply.  A falling rig count targeting natural gas has also helped, but that has been offset by large gas volumes associated with liquids-rich exploration targets and the reduction in the backlog of drilled-but-uncompleted natural gas wells. 

A new ingredient helping lift natural gas prices was the recent winter heating demand forecast by the National Oceanic and Atmospheric Administration (NOAA).  While NOAA didn’t project a colder than normal winter, it did forecast a colder than last year winter, which is perceived by the natural gas industry as good news for consumption.  The problem the gas industry has experienced with winter gas consumption in recent years is summarized in Exhibit 1.  It shows that while the winters of 2009-10 and 2010-11 were colder than normal, last year was markedly warmer, which set the industry on a course for a surge in gas storage that contributed to low gas prices.  Now, NOAA sees a winter heating demand somewhere between the recent colder winters and last year’s warm one that should help soak up gas production since the volume of natural gas used to generate electricity continues to grow.

Exhibit 1.  Winter Temps To Be Colder Than 2011

Source:  EIA

Recently, Wunderlich Securities exploration analyst Jason Wangler conducted an informal poll of oil and gas producers to sample their views on natural gas prices.  The consensus of these producers was that gas prices would remain in the $3.50 to $4.50 per million British thermal units (mmbtu) range for the foreseeable future.  A million btus is just about the energy equivalent of a thousand cubic feet of natural gas (Mcf), which is the price measure most people focus on.  Probably the more significant number, however, is the consensus view on the price that makes the industry more aggressive in drilling.  It appears the operators view is that they will not step up gas drilling activity significantly until prices reach the $4.50-$5.50/mmbtu threshold and demonstrate that the price level will be sustainable or can go higher. 

When we look at what has happened to natural gas prices so far this year, it has been a volatile time with the prognosis for the future fluctuating wildly.  When gas prices were sliding from the $2.75/Mcf level as experienced in the midst of winter (January) to close to $2/Mcf in the spring, the lack of an appreciable slowdown in gas production growth in the face of a sharp fall in the rig count created fear that gas storage would reach full capacity this summer and generate gas-on-gas price competition.  That scenario could have driven prices to the $1/Mcf level, or below.  Gas sales at pennies were envisioned (they’ve happened before) due to the pressure on storage operators to move natural gas volumes in and out of the reservoir to meet contractual requirements and for physical necessities. 

A funny thing happened on the way to this calamitous scenario – some summer heat arrived, more electric utilities switched from coal to natural gas, and the growth rate of gas supply slowed marginally.  Gas traders, including investment fund speculators, perceived that these drivers would not reverse quickly and that supply and demand would begin moving toward equilibrium.  Those analysts with long-term histories of the natural gas market grasped that a positive outlook would take control of pricing when the disaster scenario failed to materialize.  This newly established trend will likely continue for some time. 

Exhibit 2.  Gas Price Optimism Is Unbounded

Source:  EIA, PPHB

We also noted that some old timers even began predicting gas prices would reach or breach the $4/Mcf level by year-end – something virtually no one would have given odds on earlier in the year.  In making that prediction, there were a number of caveats embedded in the estimate.  As we draw toward the end of 2012, even with those caveats, the $4/Mcf scenario is beginning to look increasingly possible, although the near-term futures curve doesn’t fully support that conclusion.  A late season hurricane or an early cold snap could be the catalyst to take gas prices solidly above that magical number, but unless and until it is supported by further improvement in demand fundamentals, it is hard to see any material response by the operator community.

Exhibit 3.  Gas Price Forecasts Are On The Rise

Source:  EIA, PPHB

When Mr. Wangler reported on his informal poll of operators, the energy communications firm, EnerCom, decided to take a look at how the gas market was changing.  They noted that without higher natural gas prices, producers were left with three strategies if they wanted to step up their gas drilling: 1) take on debt; 2) issue equity; and 3) reinvest incremental cash flows.  We would note there is a fourth strategy that is to sell non-core assets or even small amounts of core assets if necessary to support the company’s higher gas drilling.  Another key trend would be for operators to become more efficient and successful through the use of new technology to reduce the breakeven point for their gas production.

EnerCom turned to its database to find the breakeven prices for major gas shale fields in 2008 and to see how those prices have changed over time.  The definition of breakeven was a 10% rate of return on investment based on the EnerCom projected decline curves and company data on finding and development costs.  The analysis focused on the following four formations: Woodford, Fayetteville, Haynesville and Marcellus Shale.  What EnerCom found is that between 2008 and 2012, the breakeven price had declined by double digit percentages for three of the four formations.  The Woodford went from a breakeven price of $6.45/Mcf down to $3.93/Mcf, or a 39% decline.  The Fayetteville formation’s breakeven price has declined by 22%, from $5.39/Mcf to $4.19/Mcf.  The Marcellus Shale’s breakeven price is now $2.88/Mcf, which is 16% lower than the $3.62/Mcf it was in 2008.  The smallest breakeven price decline was experienced by the Haynesville Shale, which saw its breakeven price drop by only 3% to $3.51/Mcf from $3.62/Mcf.  In almost all cases, the breakeven price decline is significant.  To demonstrate the significance, the chart in Exhibit 4 shows how the breakeven prices have changed between 2008 and today.

Exhibit 4.  Shale Gas Economics Improving

Source:  EnerCom

EnerCom went on to think about what would happen to the natural gas industry if gas prices actually found themselves in that $4.50-$5.50/Mcf range.  First, producers would rush to hedge their future production in order to prevent pain if the industry promptly drilled itself into a $3.00/Mcf gas market.  Remember, it was the ability of producers to hedge their future production at $6/Mcf to $8/Mcf that enabled them to undertake the land grab and commence the drilling boom that created the $2/Mcf natural gas market. 

If we assume that gas prices rise to the threshold that triggers producer interest in reallocating their capital from liquids-rich plays to gas-shale plays, several things would need to happen.  Even with West Texas Intermediate oil trading at about 28-times the value of Henry Hub natural gas, well above the energy content, producers need to be convinced these economics would be sustained.  They also need to believe that U.S. natural gas plays are more productive than crude oil plays.

Exhibit 5.  Gas Economics Trump Oil Economics

Source:  EnerCom

EnerCom examined the economics of gas shale versus oil.  They pointed out that a $9.8 million Bakken oil well, with an economic ultimate recovery (EUR) factor of 600 million barrels of oil equivalent (MBOE), which translates into 3,600 million cubic feet equivalent (mmcfe), compared to a $9.2 million Haynesville well with a EUR of 8,700 mmcfe (1,450 MBOE), suggests that shale gas is more productive than oil.  In another example, EnerCom points out that a Haynesville well is two and half times more productive than any of the oil wells such as those in the Bakken, Eagle Ford or Mississippian formations and comparable in drilling and completion costs.

Natural gas optimists are cheering that gas prices are moving higher.  Their optimism may be slightly overdone as production continues to grow faster than consumption growth.  There is little doubt that gas use in generating electricity is continuing to grow due to the relative economics of gas versus coal, but those economics may be shifting slightly against gas as coal prices weaken.  If we get, as NOAA suggests, a colder winter than last year, that too will help gas prices.  Gas prices in the $4/Mcf range appear to be a real possibility that will help drilling and oilfield service activity.  The key will be whether producers read higher prices as the dropping of the green flag for the gas shale race to begin.

The impact of the shale revolution on the future of the energy business cannot be understated.  So far it has produced a glut of natural gas despite a sharp reduction in the drilling of dry gas wells.  It is also responsible for the increase in domestic oil production primarily due to the abundance of new oil output from the Bakken formation in Montana and North Dakota, as well as in the Eagle Ford formation in South Texas. 

To appreciate the impact on the energy business, one only needs to contemplate the shale resource buying spree ExxonMobil (XOM-NYSE) has been on in recent weeks.  Two weeks ago, ExxonMobil announced it was buying Canadian producer Celtic Exploration (CLT-TSX) for cash and stock worth C$24.50, a 35% premium to the company’s closing share price the night before the deal was finalized.  The $3.1 billion value of this transaction exceeded the $2 billion price tag ExxonMobil paid for the Bakken shale resources of Denbury Resources (DNR-NYSE) only a few weeks earlier.  So in a span of about 60 days, ExxonMobil spent $5 billion on large acreage holdings in the U.S. Bakken and the Canadian Duverney and Montney shale formations. 

It was only about 90 days ago that ExxonMobil Chairman Rex Tillerson spoke to the Council on Foreign Relations in which he commented how his company was losing money on its shale efforts.  What he said was, “What I can tell you is the cost to supply is not $2.50. We are all losing our shirts today. You know, we’re making no money. It’s all in the red.”  So how did the industry get into this money-losing position?  It has to be especially galling for Mr. Tillerson because in 2010 he had ExxonMobil wager $35 billion on a leading shale producer, XTO.  The problem has been the early successes of the shale plays.  The current low gas prices were “because the industry overshot when we had those $6, $7, $8, $9 prices, and we overdeveloped the supply,” said Mr. Tillerson. 

The oversupply of natural gas is due to the technological improvements that have occurred as a result of the American gas shale revolution.  As Mr. Tillerson put it, “We underestimated just how effective that technology was going to be, and we also underestimated how rapidly the deployment of that technology would occur — again, all in response to fairly high prices.”  The old saying that the cure for low gas prices are low gas prices hasn’t remedied the situation due to these technological breakthroughs.  While we are likely destined for many more months of low natural gas prices, it hasn’t dissuaded ExxonMobil from taking advantage of the market turmoil to add to its shale holdings.  We understand the company may be looking at ten more shale-oriented acquisitions.  These moves appear consistent with a massive restructuring of the domestic oil and gas industry that seems well underway and will last for some more years.  Smaller and under-capitalized producers are being snapped up by the global integrated producers.  The face of the domestic oil and gas business is changing and how it operates in the future will be different from the past – a lesson the oilfield service industry still needs to figure out.

One of the more significant trends emerging from the surge in U.S. domestic oil and gas production is the problem of our existing transportation infrastructure.  In a nutshell, the problem can be summed up as “too much supply and too little pipeline capacity.”  While this infrastructure challenge is greater for natural gas, it also has an impact on how producers can transport oil to consumers.  In turn, these transportation issues are having an impact on the price producers can realize for their oil and gas, which impacts the economics for the continued drilling and development of shale resources.  Natural gas is gathered from the producing wells through a network of small diameter, low pressure pipes and consolidated at a central point in the field.  It is then usually moved to a natural gas liquids plant where the heavier molecules of gas are stripped from the gas flow before it is then deposited into a large-diameter pipeline for shipment to consuming markets.  The natural gas liquids stripped from the gas flow are usually shipped via a pipeline to consumers.  Crude oil can be collected in storage tanks at a well site and moved to a gathering location by truck if there are not sufficient volumes to justify building a gathering pipeline system.  If a pipeline does not exist to ship the crude oil to refineries, the liquid can still be moved to consumers by truck, barge or railcar.  These alternative transportation systems involve more handling and potentially create a greater environmental risk.  As a result, these alternatives are less efficient and therefore more costly, however they do provide an alternative way to ship liquids to market as compared to gas. 

The imbalance between the location of the new domestic oil and gas production and our existing pipeline infrastructure has often translated into a lower price at the wellhead for these new supplies.  Once sufficient volumes of oil and gas are produced, or there are clear prospects of increased future flows from these new producing regions, the petroleum industry will begin constructing new or

Exhibit 6.  Growing Network Of Oil Pipelines

Source:  Platts

Expand the transportation systems to serve the increased demand.  A developing problem is the lack of pipeline capacity to move the increased Bakken production in North Dakota and Montana.  Additional pipeline capacity could come from the construction of TransCanada’s (TRP-NYSE) Keystone XL pipeline, along with some other proposed projects.  In the interim, the use of railcars to ship oil is growing. 

In August, Statoil ASA (STO-NYSE) announced it had secured 1,000 new railcars to move upwards of 45,000 barrels per day (b/d) from the Bakken to refineries.  The roundtrip for the railcars is 14-15 days including loading and unloading.  Marathon Oil (MRO-NYSE) moves about 14% of its daily Bakken oil production by railcars.  According to the state petroleum authority, North Dakota moves about 325,000 b/d of its production by railcars due to the lack of adequate pipeline capacity. 

The result of inadequate pipeline capacity is that land-locked crude oil has been forced to sell at a meaningful discount to world oil crude oil prices due to the increased cost and time required for moving oil to consumers.  This price disparity has manifested itself in the U.S. only in the past couple of years.  The chart in Exhibit 7 (next page) shows the 25-year record of the price of West Texas Intermediate (WTI) and Brent North Sea crude oil, which is a proxy for world crude oil prices.  As can be seen, the prices for these two price-setting crude oils moved virtually together from 1987 until 2010 when, due to the growth of oil supplies in the U.S. Midwest region without corresponding access to refining capacity, WTI prices began to fall relative to Brent prices.  That gap was initially quite narrow, but during the past two years it has widened.  While the chart ended in June 2012, the price gap between WTI and Brent crude oil was slightly over $24 a barrel as of mid-October.

Exhibit 7.  WTI And Brent Prices Out Of Phase

Source:  Casey Research

The regional price disparity is more evident when U.S. oil prices are compared to those of the Western Canadian Sedimentary Basin (WCSB).  The chart in Exhibit 8 shows how the traditional price disparity between WTI and Western Canadian Sweet (WCS) has widened in recent times.  That widening is due to the pipeline bottleneck for moving oil from the central portion of the U.S. to the refining complex on the Gulf Coast.  As Canada ramps up its oil sands, tight oil and conventional oil output, the volume of oil wanting to move into the United States is growing.  Without additional U.S. oil pipeline infrastructure and additional refining capacity, especially for heavy oil, it is hard to see the WTI/WCS price gap narrowing soon. 

Exhibit 8.  Canada Oil Sells At Discount To U.S.

Source:  Casey Research

During World War II, to manage the petroleum industry and the nation’s use of refined petroleum products, the federal government established a regional structure for regulating the industry.  The U.S. was divided into five geographic regions or Petroleum Administration for Defense Districts (PADD).  The PADDs are set out in the map in Exhibit 9. 

Exhibit 9.  World War II Established PADDs

Source:  EIA

The flow of crude oil from Canada comes largely into PADD II, the Midwest region, as that is where the central receiving point for U.S. oil flows is located at Cushing, Oklahoma.  The chart in Exhibit 10 shows these flows, although Canadian oil does go to all five U.S. PADDs.

Exhibit 10.  Most Canadian Oil Goes To Middle U.S.

Source:  Casey Research

Canadian oil production, as projected by the Canadian Association of Petroleum Producers (CAPP), should more than double from 3.0 million barrels per day (mmb/d) in 2011 to 6.2 mmb/d in 2030.  The forecast, which includes growth from the oil sands, shows an increase of 0.8 mmb/d from last year to 2015, and a further 0.9 mmb/d increase during each of the next two five-year periods.  Almost all the projected increase in output comes from rising oil sands production.  As shown by the chart in Exhibit 11, oil sands production is estimated to grow by 0.7 mmb/d between 2011 and 2015, and then by 0.9 mmb/d and 1.0 mmb/d in each of the succeeding five-year time intervals.  Particularly significant is that Canadian oil production is projected to grow faster in the new CAPP forecast than in its 2011 outlook. 

Exhibit 11.  Canadian Oil Production To Grow

Source:  CAPP

Faced with growing U.S. production, Canadian producers and pipeline companies are wrestling with how to increase their capacity to ship more oil to the United States and eventually to world markets.  Gaining access to world markets is particularly important for Canadian producers if they wish to ensure that their output commands world oil prices.  The first major pipeline expansion effort was TransCanada’s Keystone XL pipeline, which has been the focus of a political firestorm in the U.S. due to opposition from environmentalists who have successfully swayed President Barack Obama to delay the line’s approval.  While the environmentalists have objected to the pipeline’s route through a portion of the Ogallala aquifer in Nebraska, the primary opposition is to the pipeline’s cargo – bitumen from the oil sands – that they consider the dirtiest of all the world’s oil supplies.  The U.S. delay in approving Keystone has energized shippers, and the Canadian federal government, to seek additional outlets.

One of the first alternative pipeline proposals came from Enbridge (ENB-NYSE) to construct a pipeline from the Edmonton, Alberta area to the West Coast port of Kitimat in British Columbia enabling

Exhibit 12.  TransCanada Plans Oil Expansions

Source:  TransCanada

the crude oil flow to be exported to world markets.  The Gateway pipeline proposal is at the center of extensive political infighting in Canada between the British Columbia and Alberta provinces, the First Nations people, environmentalists and the federal government.  Unfortunately, the Canadian oil sands and conventional oil producers are caught in the middle of this political battle, primarily only interested in seeing that they have an outlet for their increased production when it arrives.

Exhibit 13.  Proposed West Coast Oil Export Line

Source:  Enbridge

Given the possibility that approval for the cross-border connection for the Keystone XL pipeline might not be granted by the Obama administration, should it be re-elected, TransCanada has put forth a new proposal for increasing Canada’s oil pipeline export capacity.  Their proposal involves converting one of the company’s mainline gas pipelines that is no longer needed, along with constructing some additional pipeline segments in Eastern Canada, in order to allow oil to flow to the East Coast, both to service the Irving refinery there and for export to world markets.  To understand how this would work, we have presented the map of TransCanada’s gas pipeline network in Exhibit 14.  The long green pipeline labeled Canadian Mainline extending from Alberta would have one of its pipes converted to oil use and the line would be extended from Montreal to Canada’s East Coast.  Besides the new segment, the company would need to build various pumping stations along the line to help move the oil. 

Exhibit 14.  Possible Oil Export Pipeline

Source:  TransCanada

In judging the two proposals, it would appear that the political battle over the Gateway pipeline proposal and the oil spill problems Enbridge experienced in Michigan this summer makes it a long-shot.  While TransCanada’s pipeline would be much longer, the effort to convert an unneeded gas pipeline is easier than new construction.  However, TransCanada will still need to seek construction permits for the new line segments in the Quebec region, which tends to be more liberal and environmentally concerned.  We understand TransCanada already has much of the new pipeline right-of-way, reducing the political problems of seeking approvals. 

We remain convinced that a re-elected President Obama will not favor the Keystone XL pipeline permit.  That would put increased pressure on Canada to find alternative oil export outlets.  We think the environmental battle over Gateway makes that pipeline proposal less likely.  Therefore, we think the TransCanada pipeline conversion and extension proposal is the more likely, but it will be several years before it can be put into service.  That means the price disparity for WCS oil will continue, sapping cash flow from Canadian producers.  That lost cash flow will impact the level of oilfield activity in Canada’s WCSB over the next couple of years compared to what the activity level might have been. 

The University of Texas at Austin Energy Poll recently released has a surprising conclusion – the public believes President Barack Obama has a better energy plan for the country than his Republican challenger Mitt Romney.  The poll, part of a multi-year series and designed by the McCombs School of Business’ Energy Management and innovation Center, was conducted nationwide between September 6th and September 17th, and involved sampling opinions about energy topics of 2,092 respondents who were selected based upon population and geographic weightings taken from the U.S. Census Bureau. 

Energy is considered an important issue by the respondents.  Two out of three people surveyed say that energy is the third most important issue following job creation and the economy.  The surprise in the poll, at least to us, was that President Obama was considered by 37% of the respondents to have a better energy plan than Mr. Romney who only garnered 28% support.  Maybe the fact that nearly as many people were undecided or not sure as supported President Obama’s position helps explain the outcome.

Not surprisingly, the support for each candidate’s energy position was about even among those respondents with similar political identities, but President Obama was marginally ahead among those who identified themselves as independents (27%-23%).  The most shocking statistic was that Libertarians favored the Obama platform by more than a 2-1 margin over the Romney plan.  For a group of

Exhibit 15.  Obama Leads Romney On Best Energy Plan

Source:  University of Texas at Austin

people whose political views are predicated on the principal of freedom from government regulation, we are hard pressed to understand how an energy program constructed on government mandates and subsidies promoting specific fuels along with legal attacks on other fuels not based on economics but rather on their social desirability can be favored so overwhelmingly. 

Exhibit 16.  Costly Gasoline Remains Top Issue

Source:  University of Texas at Austin

When people were asked about their view of a presidential candidate, the top-ranked support was for someone who will promise to make gasoline less expensive.  In fact, almost 93% of Americans polled were concerned about the cost of gasoline.  It was also interesting to see that the percentage of respondents who favor a candidate that supports the development of natural gas is equal to those that support someone who will fund renewable energy.  There were also fewer than half the people polled who support the construction of the Keystone pipeline, which surprisingly would contribute to lower gasoline prices in the long-term.

Maybe all these results suggest that President Obama has actually done a better job telling a “story” to the American public during his term in office than he recently lamented during an interview.  Or, possibly, the poll results reflect the lack of knowledge and understanding among Americans about energy issues.  When the pollsters asked whether respondents considered themselves knowledgeable about energy, only 45% of men and just 20% of women said yes.  Does this statistic support the conclusion that the views of an uninformed electorate can be more easily manipulated by politicians and the media?  Yes.

The issue for worldwide energy demand, and derivatively crude oil and natural gas prices, is the health of the global economy.  The latest estimates for growth, however, are coming down reflecting the continuing impact of the financial crisis in Europe, the pedestrian economic recovery in the United States and Japan, and now concern about a possible downturn in China.  For much of the past two years, energy markets have been supported by the growth of developing economies.  The developed economies, on the other hand, have experienced slow economic growth for several years along with financial problems that have restricted efforts to boost growth.  During this period, developing economies have experienced sharply higher growth rates and rising personal incomes, which drive up living standards along with energy consumption.

The latest economic projections by the International Monetary Fund (IMF) presented at its annual meeting with the World Bank a few weeks ago suggest that global growth is slowing.  The global estimate calls for 3.3% growth in 2012, half a percentage point lower than experienced in 2011.  The latest estimate has been reduced by 0.2% from the growth rate projected just last July.  For 2013, the IMF expects global growth to increase to 3.6%, although the latest projection has been reduced by 0.3% from what the agency expected in July.  The reason for the lower growth expectation is declining economic growth in emerging and developing economies.  As a group, those economies are expected to grow by 5.3% in 2012, down from the 6.2% rate experienced in 2011 and the 7.4% rate of 2010.  The 2012 estimate was reduced by 0.3% in this latest forecast.

In the advanced economies, the overall growth rate for 2012 has only been reduced by 0.1% to 1.3%, which is down from the 1.6% rate in 2011.  The latest 2012 projection is about a quarter of the 3.0% growth recorded in 2010.  Advanced economies are projected to grow at a 1.5% rate in 2013, but that estimate has been slashed by 0.5% since the IMF’s July forecast.  The primary reason for the reduction lies with the half point cut in the Eurozone’s growth projection for 2013.  Now the IMF sees the Eurozone growth at 0.2% next year, but that is considerably better than its -0.4% growth projected for this year. 

Exhibit 17.  Slower Growth Worldwide Says IMF

Source:  IMF

With growth rates for advanced economies very low, or negative as for the Eurozone this year, it is not surprising that global energy demand is growing very slowly.  That trend has been captured by the continued ratcheting down of oil demand forecasts by the three primary forecasting bodies – the International Energy Agency (IEA), the Energy Information Administration (EIA) and OPEC, although the reductions have not occurred in lock-step. 

The IEA recently cut its oil demand forecasts for both 2012 and 2013 by 100,000 barrels per day (b/d), each.  Overall, it expects oil demand in 2012 to be 0.3 million b/d lower and down 0.4 million b/d the following year.  It is quite interesting how the IEA now sees global oil demand increasing from 89 million b/d in 2011 to 95.7 million b/d in 2017, yet it sees the market being better supplied in five years.  The IEA is projecting 2017 global oil supply to reach 102 million b/d, some 1.5 million b/d greater than previously anticipated suggesting that production growth is accelerating.  While that appears true today, the question is whether it will continue to grow as rapidly in the future, if it continues at all.

In the United States, the EIA hasn’t changed its oil demand forecasts materially in recent months but the trend for the year has been lower.  On a worldwide basis, since the beginning of 2012 the EIA’s estimated demand growth has dropped from a projected gain of 1.3 million b/d for 2012 and 1.5 million b/d in 2013.  Now, according to the agency’s October report, global oil demand will only rise by 0.8 million b/d in 2012 and 0.9 million b/d in 2013.  These roughly half a million barrels per day consumption reductions reflect slower economic growth globally, but especially for Asia.  In the United States, the EIA believes that oil use in 2012 will now fall by 30,000 b/d versus its beginning of the year expectation for a 90,000 b/d increase.  For 2013, the EIA’s view now has increased from early year expectations of only a 45,000 b/d increase to an expectation for a 110,000 b/d rise.  The most telling aspect of this boost in the oil consumption forecast for next year is that it is driven by an increased use of natural gas liquids (NGLs) in industrial applications and expectations of a colder than prior-year winter that boosts heating oil and propane usage.  You will notice the absence of any increase in gasoline or diesel demand.

Recently, OPEC lowered its 2012 oil demand forecast by about 0.1 million b/d, but elected to leave unchanged its 2013 forecast that calls for a 0.8 million b/d boost in consumption.  In the press release announcing its latest forecast, OPEC summarized the challenges oil producers face when it stated, "Economic uncertainty in the US, EU and China is determining the fate of the world’s energy use not only for the rest of this year but also throughout next year."  Slower industrial production, along with high fuel prices, which contributed to lower mileage in the transportation sector, were among the main reasons behind the drop in oil use, especially in Europe, China and North America.  OPEC warned that in 2013, uncertain economic growth, high fuel prices and the weather "could reduce the world oil demand growth forecast by 20 percent next year." 

In making its 2013 forecast, OPEC specifically cited the risks in the United States and China as potentially major contributors to the demand uncertainty.  Many economists and investors were heartened by the latest economic statistics from China that showed third quarter gross domestic production grew at a 7.6% rate, which was close to the second quarter’s 7.8% rate.  China’s National Bureau of Statistics also reported that fixed asset investment excluding rural homes increased by 20.5% for the first three quarters of 2012.  It also said that September retail sales increased 14.2%, the most since March 2012.  Industrial production grew by 9.2%, outpacing economists’ forecasts calling for a 9.0% increase.  September’s industrial production rate was the highest since the 3-year low recorded in August of an 8.9% advance. 

Exhibit 18.  China’s Economy May Be Bottoming

Source:  National Post

While many observers were cheering the view that the worst of the Chinese economic contraction is behind it, one lousy statistic that may signal that all is not well in the country was its monthly electricity forecast.  In September, nationwide electricity consumption only increased 2.9%, which is below the nine-month rate of 4.8%.  For the same three quarters in 2011, national electric demand increased by 11.7%.  The September figure also highlighted that industrial usage of power only increased about 1%.  So while the overall economic statistics emanating from China suggest a bottoming in its economic slowdown, the September electricity figures point out that the bottom might be shaped more like a saucer than a “V”.  Given the slow growth in the U.S. and the economic contraction underway in the Eurozone, this China economic scenario is not encouraging for oil demand in 2013.  And things in the Arab world could still deteriorate further.  The big, unanswered question remains: Can global political tensions keep oil prices elevated in the face of weakening economic fundamentals for energy?  If so, petroleum companies will be encouraged to step up their spending on new exploration and development.  If not, then prices will be heading south sapping the industry’s cash flow and reducing activity. 

Anyone who watched the second presidential debate at the campus of Hofstra University on Long Island, New York, learned that both candidates like wind energy.  One candidate likes it more than the other and wants eventually to power the entire country by wind, solar and biofuels, even if it causes utility bills to “skyrocket.”  Of course that last phrase was spoken by then-Senator Barack Obama during the 2008 campaign when he was appealing to environmentalists opposed to the use of coal to generate electricity.  With the recent Chevron (CHV-NYSE) refinery fire in Richmond, California, Californians must have thought President Obama’s skyrocketing comment was referring to gasoline prices. 

Before Congress returned home for the fall election campaign, renewable fuel producers were hopeful they would have passed a bill extending the production tax credit (PTC) that reduces the cost of these renewable energy sources to be more competitive with power generated from fossil fuels and nuclear power.  That wish was not fulfilled.  Now those producers are hopeful that the lame-duck Congress will address the issue, or that the new Congress will pass legislation extending the credits retroactive to January 1, 2013.  The Wind PTC has been in place since 1992, although it has expired seven times and been renewed.  The value of the Wind PTC is estimated at $1 billion a year.  Due to the uncertainty about the Wind PTC’s future, manufacturers of power generating facilities are cutting workers due to the fact that their utility customers are stopping efforts to develop new plants.  In the case of solar power facilities, the companies are being forced to shed workers because they are filing for bankruptcy due to competitive pressures that have made the business model unprofitable. 

While there were 85,000 wind energy workers at the industry’s peak in 2009, the number is now probably closer to 50-60,000 with these plant cutbacks.  One wind turbine manufacturer reported that orders were off 24% in the first half of 2012 and that it was shifting its focus to wind farm projects in less developed countries.  One of the more interesting developments is that wind facilities are being attacked by anti-wind activists in, of all places, Vermont.  In August, six activists were detained during a protest effort to halt construction of 21 industrial-sized wind turbines on the ridgeline of Lowell Mountain in the state’s Northeast Kingdom.  Last December, 17 protesters were arrested including a local newspaper publisher.  The August protest marked the fourth protest against these wind turbines since the effort started in November 2011.

Civil disobedience against environmentally-friendly power seems to be such a contradictory notion.  The protesters reflect growing dissatisfaction with the technology and its side effects, especially if you happen to be a neighbor.  Complaints about wind energy range from shadow-flickering and jet-engine-type noise that keep residents awake, turbine blades that slice up eagles, bats and other migratory birds, ruined sightlines, turbines that fall over or catch fire to decreased property values.  We have seen cases in Rhode Island and Massachusetts this summer where wind turbines exceeded the mandatory noise level and they had to be turned off – initially for only part of the day, but now completely. 

Kenneth Kimmell, commissioner of the Massachusetts Department of Environmental Protection said, “I do think that some of our experiences are guiding us to be a little more cautious about where wind turbines are sited.”  Massachusetts Governor Deval Patrick is backing statewide legislation that would set minimum public safety standard for wind farms.  Our thought is that it is about time safety standards are enacted, but it is not surprising that only minimal standards have been in place until now because wind power has been sold to the public with the perception that it is similar to the Dutch-style windmills in the countryside that we see in iconic photos.  Unfortunately, the reality doesn’t match the image.  Will wind ever find love if it depends on tax credits and mandates?

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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.