Musings from the Oil Patch – July 5, 2011

• Natural Gas Shale Debate Becomes Front Page News!
• Maybe Offshore Rhode Island Wind Moves Forward
• Encana-PetroChina Deal Collapse: Canary In The Gas Well?
• Being Green Or Creating Green Economy Not Easy
• Politics Of Oil Rises To A New Level With Oil Release
• Clueless RI Media Lauds Opposition To Hess LNG Terminal

Musings From the Oil Patch
July 5, 2011

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

A week ago last Sunday, the technical energy business debate over the volume, productive capacity and economics of natural gas shales moved from obscure industry journals to the mainstream media with the publication of a major investigative article on the front page of The New York Times.  Reaction to the article’s premise that the industry has been obscuring the “true” picture of this important new energy supply was not only swift and extensive, but also emotional and in some cases vitriolic.  The responders ranged from energy company executives and academics to politicians and regulators.  As often happens when a significant and contentious issue explodes into the mainstream media, reactions are often shrill and quickly shift away from fact-based arguments to emotional outbursts employing ad hominem attacks on the doubters.  In this case, the gas shale debate has moved from reasoned discussions over the interpretation of well production and well cost data to attacks upon the supposed motivation of the critics.  What we know, having been involved in the energy business for over 40 years, is that time will be the only determinant of who is right.  In the mean time, we hope the heat of the debate will be turned down and civility will be restored.

We have been deep in the weeds of this gas shale debate for the past several years.  Our interest was initially piqued when several natural gas company executives, whose companies were totally committed to exploiting gas shale resources, pressured the management of an industry journal to silence one of its columnists over his questioning of the assumptions underlying the economics of gas shale plays.  Having spent much of our career as a Wall Street analyst where critical analysis based on obscure and doggedly-obtained data coupled with questioning of conventional conclusions is supposed to be prized, we found it refreshing and telling that people were willing to quit their jobs rather than compromise their integrity. 

The emergence of gas shales as the “silver bullet” for this nation’s energy supply challenge has increased the importance that the economics of this “revolution” be soundly based.  If not, investors, the government and our citizens are exposed to severe misallocation of our nation’s capital, which, as we are finding in today’s ongoing battle over raising the debt-ceiling and how to properly stimulate economic growth, could prove critical for our future.  Whether it is increased use of natural gas rather than coal for generating electricity, the development of a compressed gas automobile fleet or possibly the exporting of gas to the rest of the world, this fuel will play an important role in the nation’s energy mix with potentially positive results, but also huge costs if we invest in an infrastructure for a fuel supply that proves disappointing.  We will never know the correct answer to the question of how much gas there is as we move forward in committing to increased natural gas usage, which highlights the reason why it is important to have an honest and rigorous investigation of the physical and fiscal aspects of the gas shale business.

We sincerely believe that the gas shale revolution is real, but our concern remains its economics.  The tedious experimentation in horizontal drilling and hydraulic fracturing undertaken by George Mitchell and his company’s E&P staff back in the early 1990s to try to figure out how to extract gas from the shale underlying the Barnett Basin has to be acknowledged as a major milestone in industry history.  What is often lost on people is that Mitchell Energy was literally forced into this effort because it was desperate for additional gas reserves to fulfill long-term pipeline supply contracts it had entered into some years earlier.  Mr. Mitchell and his team demonstrated perseverance during the early 1990s and finally benefitted from rising natural gas prices by the end of the decade, but it still took 18 years to prove this technology successful.  Skill is always important in the energy business, but luck and timing often plays a critical role in success.

Other industry leaders saw Mr. Mitchell’s success and recognized that gas shales not only were ubiquitous in this country and, as we are now discovering, equally ubiquitous in various global regions, but now the ability to extract the gas was established.  As natural gas prices soared in the early years of the new century due to supply shortages and rising demand, gas shales became an attractive potential source of new supply despite their more costly wells.  Various industry and government agencies offered estimates of gas shale resources that began soaring.  Producers became confident further improvements in drilling and completion techniques would help boost returns to more than offset any modest future declines in natural gas prices.  Since gas shales were believed to be uniformly deposited throughout basins, the idea that a single rig could be positioned in an area and able to drill anywhere from a small handful of horizontal wells to as many as a couple of dozen led to the idea that drilling sites would become “drilling factories.”  This would facilitate the development of the potentially large gas shale reserves and lead to reduced well costs since rigs would be working more productively.  Additionally, since the existence of shale resources is already established by previous oil and gas drilling, there is essentially no finding cost associated with this resource, which would also contribute to reducing that cost component in the gas shale economics analysis. 

Exhibit 1.  Drilling Length Up: Time Needed Down

Source:  Southwestern Energy

The evidence of the improvement in the ability to drill horizontal gas shale wells is shown by the data presented by Southwestern Energy (SWN-NYSE) for its work in the Fayetteville play.  These improvement trends have been reported by other producers in other shale formations.  As shown in Exhibit 1, there has been a significant improvement in the drilling of horizontal wells – both a reduction in the number of days needed and an increase in the average length of lateral well sections drilled.  The reduction in the days needed to drill wells has had an immediate impact in reducing well costs.  Longer laterals mean more of the reservoir is exposed, which should mean increased production and possibly a greater volume of gas extracted from the formation. 

Another technology revolution in these formations has been the increased use of hydraulic fracturing in horizontal wells to unlock the gas trapped in the shale rock.  Exhibit 2 shows data regarding the increased use of hydraulic fracturing in gas shales from Trican Well Service Ltd. (TCW-TSX) for its operations in Canada.  Between 2008 and 2010, the percentage of wells drilled either horizontally or deviated has increased from 18% to 65%.  The data shows that from about five fracture intervals per well in the first quarter of 2008, Trican is now performing about 15 treatments in this year’s first

Exhibit 2.  Canada Wells Becoming Fracturing Intensive

Source:  Trican Well Service Ltd.

quarter.  While this data relates specifically to Canada, the same trend has been observed in the United States.  The combination of longer well laterals and more fracture intervals per well plays a role in the growth in average initial well production.  As a result, gas shale wells drilled and completed in 2011 are not the equivalent of typical gas shale wells drilled in 2010 or 2009 or even earlier.  To some degree, the difference in well generations is equivalent to the difference between Babe Ruth and Barry Bonds as home run hitters.  

The biggest problem for the success of the gas shale revolution has been the collapse in natural gas prices just as the drilling boom boosted production.  Historically, producers respond to falling commodity prices by drilling fewer wells.  The combination of reduced new gas production and depletion in existing well production should eventually restore a more balanced supply/demand relationship that should lift gas prices.  Why hasn’t that happened so far?  Primarily because producers have not cut back their drilling.  Although they have shifted from drilling dry gas wells in favor of drilling more wells in gas shales that are known to have greater liquids content, this shift has only marginally impacted the growth in gas supply.  In recent years, producers have been engaged in a land grab to snap up as much acreage in gas shale basins as possible in order to establish their future growth.  Most of the land acquired has carried commitments to drill wells and initiate production in order to be able to hold the acreage by production.  Absent that production, the producers are at risk of losing their initial investment in leases.

At the heart of the gas shale debate is the issue of well performance and what that may be saying about the ultimate recovery of gas volumes and the implied economics of the wells.  Just as the nature of the latest generation of wells has changed from earlier ones, producers who are publicly traded have benefitted from a regulatory change that may be helping to improve the perception of gas shale well economics.  One of the principal industry objections to The New York Times article was its somewhat glib comparison of gas shale developers to people engaging in Ponzi schemes or the infamous Enron fraud.  Unfortunately, publishers are, and always have been, in the business of selling newspapers – and sensationalism sells! 

While the hair on the back of our neck bristled when we read The New York Times’ references to Ponzi schemes and Enron as characterizing the operation of the gas shale industry, but under a more critical analysis there actually are some similar attributes.  If a producer is drilling gas shale wells that are uneconomic – losing money on production in the early years with the hope of making it up later – but by continuing to tap Wall Street for new money to continue drilling wells, the process is somewhat similar to a Ponzi scheme. 

The Enron comparison has similarities at two levels.  Enron engaged in conscious behavior designed to mislead analysts and investors, for example when it put together a fake trading room for telecommunications capacity to show analysts during an investor meeting or when the company booked an estimated decade’s worth of earnings from a joint venture to develop a system to deliver movies to homes electronically when the software didn’t exist and the business was merely a concept. 

The more important similarity to Enron, however, comes when one compares the recent Securities and Exchange Commission (SEC) change in reserve accounting rules for oil and gas producers to the mark-to-market rules Enron was able to help engineer that allowed it to pump up earnings.  Accounting for oil and gas reserves historically has been a highly conservative practice as exemplified by the only adjustments allowed being downward.  The value of reserves is determined based upon multiplying the estimated volumes by the end-of-year oil and gas prices.  If the reserve value was below either the cost or the prior year’s value the producer had them on its balance sheet, the difference had to be written-off and charged against current period earnings.  But whenever oil and gas prices went up, and theoretically the value of the reserves increased, the positive increment could never be added to the producer’s balance sheet. 

Over the years, the oil and gas industry argued with the SEC that improvements in its geological and engineering capabilities should allow them to recognize greater reserves than under the old accounting system.  The rules were recently changed after years of discussion, and now larger areas surrounding wells can be recognized as productive, meaning producers can bring greater volumes of reserves onto their balance sheet.  The total cost for getting these known reserves is now being spread over a larger volume of reserves leading to lower per-unit finding and development (f & d) costs.  Suddenly, producers who didn’t look as efficient in finding and developing their reserves can suddenly look quite profitable without doing anything different.  Is this shift in accounting a problem?  No.  Could the shift in accounting rules lead to less rigor in determining f & d costs?  Sure.  However, that possibility is not a reason to indict the entire industry, but it should be considered a red flag warning, especially for individual companies who have a record of significant write-offs of shareholder wealth over the past several years. 

The oil and gas industry is known for its long business cycles.  This is due to the long-term productive life of oil and gas wells.  In some cases there are oil wells still producing after 50 years in operation.  In other cases, wells may be depleted in a matter of only a few years or less.  The length of time a well produces may or may not influence the total volume of ultimately recovered reserves.  On the other hand, an early demise of a well may mean the reservoir was not large or the ability to extract the volume is difficult.  From an economic issue, the speed with which reserves are produced impacts the profitability of wells.  It is this issue that is the heart of the debate over gas shales.  Are the wells economic when wellhead prices are in the $4-$4.50 per thousand cubic feet (Mcf) of gas or lower? 

Most producers who are active in gas shales contend that the high initial production rates from their wells support their use of hyperbolic decline curves to predict ultimately recoverable reserves.  The higher the recoverable factor the greater the value attributable to the wells.  The problem is that in many of the older gas shale basins, where there are significant numbers of wells with long production histories making it easier to assess this decline curve assumption, the data is challenging that view.  As a result, when the actual production history is plotted, the data suggests ultimate well recoveries well below producer claims.  The issue becomes whether producers have overstated their well performance data because they are trying to secure additional funding to complete their strategic gas shale positioning, or whether the later months of production will demonstrate better performance than currently being experienced, making up the near-term shortfall. 

Recent producer financial results reflect their challenge of trying to make money with low natural gas prices and high crude oil prices.  Several analyses of the financial performance of conventional natural gas companies versus unconventional gas companies, i.e., gas shale producers, shows a significant difference in financial performance.  One study was published in the newsletter of the European Association of Geoscientists and Engineers (EAGE) and it shows that unconventional producers were reporting negative

Exhibit 3.  Well Data Fails To Support Claims

Source:  Art Berman

margins.  These companies are largely ones actively involved in exploiting gas shales.  The study compared these companies against large conventional gas producers who, in this case, happened to be some of the world’s largest oil companies.  What is interesting in the study was the positive margin performance of XTO Energy, the unconventional gas company recently purchased by Exxon Mobil Corporation (XOM-NYSE).  The relative performance of XTO versus its peers may partially explain ExxonMobil’s willingness to acquire it at such a high valuation. 

Exhibit 4.  Margin Performance Gas Producers

Source:  FirstBreak.org

Another analysis done by a writer on the financial web site, SeekingAlpha.com, of producers active in the Eagle Ford shale in South Texas shows very interesting financial performance statistics.  The producers in the study include: Petrohawk Energy Corp. (HK-NYSE); Newfield Exploration Co. (NFX-NYSE); Pioneer Natural Resources Co. (PXD-NYSE); Anadarko Petroleum Corp. (APC-NYSE); SM Energy Company (SM-NYSE); and Forest Oil Corp. (FST-NSE).  When one examines the data in Exhibit 5, the performance of the companies on certain critical financial measurements does not reflect well on most of the producers. 

Exhibit 5.  Eagle Ford Shale Producers Financials

(continued on next page)

Source:  SeekingAlpha.com

For example, the six producers are selling at between 1.78 and 3.5 times book value.  Because most E&P companies are valued more on the value of their reserves, the price to book calculation is not really that meaningful.  That said, however, it shows the importance for producers to increase their reserves and do that as efficiently as possible.  On the price to cash flow measure, the producers are trading in a range of 9.2-13.4 times.  Based on their trailing 12-month earnings growth rates, other than Pioneer who was up over 93%, all the producers experienced earnings declines of between -34.3% to -70.4%.  Most of the producers are fairly well levered with debt as their capital spending over the past several years has been larger than their cash generation.  The total-debt-to-total-capital ratios of the producers range between 36% and 57.8%.  Despite the higher than average leverage, the low natural gas prices have contributed to producers only being able to generate returns on equity of between 1.3% and 8.75%, not particularly successful performances.  Collectively, these financial results reflect the impact of ongoing low natural gas prices, large capital investment programs and the need to resort to increased borrowings to fund the shortfalls between cash generation and capital spending.  At some point these earning and spending parameters will change.  But will the change come due to higher gas prices producing higher cash flows and earnings or will the capital investment programs need to be cut back?  We suspect most investors buying the stocks of these producers are counting on change coming from higher gas prices.

As mentioned above, it took George Mitchell and his team 18 years to solve the mystery of how to drill and stimulate gas shale wells in the Barnett Basin in Texas.  Since then, the industry has drilled roughly 8,000 wells in that field, yet petroleum engineers and geologists will freely admit that they have not solved all the problems associated with producing natural gas from shale rock.  The more gas shale basins that are discovered and exploited, the more we are learning about how different the shales are.  The different make-up of shales is forcing the industry to experiment with modifications to the accepted technology and techniques for extracting this gas.  We need to acknowledge that the industry still has a lot to learn about gas shales, so we must accept the fact that there may not be a single “right” answer to the gas shale challenges. 

As we found that gas shale formations are not uniform throughout basins, we have largely disproved the drilling factory model.  From studying well production data, it slowly became evident that different parts of shale formations produced greater volumes of gas than others.  For many, the idea that gas shales had sweet spots was an uncomfortable concept.  The most recent example was the disappointing performance of three wells drilled recently by Penn Virginia (PVA-NYSE) in the Marcellus formation in Pennsylvania.  The wells were drilled on the company’s acreage in Potter and Tioga Counties, which are located in the middle of the line of counties along the New York State border.  In the maps below, these wells would be located in areas colored in blue, which suggests below average well performance.  Those three wells have forced the company to change its program for assessing the balance of its acreage.  They will now drill vertical wells (much cheaper) to assess the quality of the formation in the remaining acreage.  A preliminary look (Pennsylvania only releases data every six months) at the performance of wells in the Marcellus yields the maps in Exhibits 6 and 7. 

Exhibit 6.  Cumulative Production Shows Sweet Spots

Source:  Lynn Pittinger

Exhibit 7.  Well Data Shows Emerging Sweet Spots

Source:  Lynn Pittinger

In other basins, for example the Haynesville, we can see the better developed sweet spots contrasted with poorly performing areas.  This data confirms that not every well in a field produces similar volumes of gas.  In turn, that means that high well costs will make some wells uneconomic and discourage the drilling of others outside of the sweet spots. 

Exhibit 8.  Haynesville Sweet Spots

Source:  Art Berman, Lynn Pittinger

None of this information condemns the gas shale revolution, but the idea every gas shale well will be a bonanza is also wrong.  The hype associated with gas shales as the “silver bullet” for resolving our nation’s energy supply problems is overdone.  We have substantial gas shale resources, but not all of them are, or maybe ever, economic.  It is important for the nation that we get a solid understanding of just how many of those resources can be turned into reserves, which is the important consideration of just how important a role gas shales will play in our energy mix.  Let the debate go on with greater civility and respect for thoughtful questioning.  This is too important an issue for the nation for it to degenerate into schoolboy antics.

Wishing and hoping in Rhode Island!  Last Friday, the state’s Supreme Court handed down its ruling in the suit brought by two industrial companies challenging the legality of the 20-year Power Purchase Agreement (PPA) approved by the Public Utilities Commission (PUC) between Deepwater Wind, the developer of the demonstration 5-turbine offshore wind farm, and National Grid (NGG-NYSE), the state’s primary electricity provider.  In a unanimous decision, the court ruled for the contract despite expressing some reservations about aspects of the project. 

Justice Gilbert Indeglia wrote the 75-page decision for the court and rests the decision on some interesting grounds due to the new law that the PPA was to be evaluated on.  The PUC heard testimony that there was a huge cost to be borne by the ratepayers due to the high price of wind power under the PPA compared to the cost of other renewable energy supplies readily available to National Grid.  That cost was recently updated from in excess of $300 million to $415 million.  There was also testimony about the economic benefits of the project for Rhode Island – estimated at $129 million over the life of the contract.  This same testimony, however, established that the wind farm will only create six permanent jobs. 

Despite the testimony, the PUC ruled favorably on the PPA.  The court said that the PUC was not required to balance the costs of the project against the benefits.  Rather, the PUC only had to consider the potential positive effects.  Based on this rationale, any amount of positive benefits from the project – even merely the cost of a postage stamp – would count and require the PUC to find for the PPA.

The justice likened the approval of the wind farm to the purchase of Alaska, yet we think that analogy fails on its face.  The justice wrote, “It is this Court’s fervent hope that our Legislature’s William Seward-esque policy decision championing this amended purchase-power agreement proves as lucrative and majestic as the Alaska Purchase of 1867.”  While Alaska has many positive qualities, its greatest value came with the discovery of oil and gas.  Wind has yet to prove the energy equal of fossil fuels.  Prior to that, Alaska was the answer to the trivia question – which U.S. state is the largest?  Texans have always contended that if all the snow and ice in Alaska melted, the Lone Star State would retain its number one position.

Deepwater Wind is now free to try to raise the $205 million in financing to build the project, which may be more challenging since the federal government’s renewable energy subsidy program has had its funding cut.  There remain lots of technical issues about the installation and operation of the wind turbines, and since the company has yet to collect the necessary wind data to fully engineer the project, we wonder what operational issues will surface over the next few months.  Rhode Island may now become the top state in one category – offshore wind power – after having fallen from 49th to 50th in the recent CNBC ranking of the best states for doing business.

On June 21st, Encana (ECA-NYSE) announced it was ending negotiations with a subsidiary of PetroChina Company Limited (PTR-NYSE) for a $5.4 billion joint venture to develop the tight gas resources in the Cutbank Ridge field within the Montney shale trend along the border of British Columbia and Alberta.  The joint venture was initially announced in June of last year with additional terms disclosed in February.  There were a number of theories about what happened in the negotiations that caused them to fail.  We have our own view. 

In 2001, Encana began exploring an area marked by the star on the map in Exhibit 9 some 50 kilometers (31 miles) southwest of Dawson Creek within the Montney shale formation located in the Alberta-British Columbia foothills.  Over a 12-month span, the company acquired 500,000 acres, spent $500 million on drilling and land purchases, examined 300 well logs and drilled 25 wells to establish production profiles.  This effort became known as the Cutbank Ridge play that Encana expects will support production of several hundred million cubic feet per day of long-lived natural gas production from the Lower Cretaceous Cadomin formation.  The Cadomin formation is about 100 feet thick and lies about 8,000 feet deep in the area. 

Over the initial 18-month period that Encana was involved in the region, it had acquired 150,000 net acres via land transactions, land swaps with other companies and Crown land sales.  In 2003, the company paid $369 million at provincial land sales for majority interest in 350,000 net acres.  At that time, Encana said it expected Cutbank Ridge to yield more than six billion cubic feet per section based on two horizontal wells per section.  It estimated that the wells

Exhibit 9.  Montney Shale Trend Contains Cutbank Ridge

Source:  Canadian Energy Research Institute

would cost about $4 million each for drilling, completion, sales tie-ins and production facilities.  The wells were expected to have steep first-year declines followed by further annual production declines that would average less than 15% per year for many years thereafter.  Given the expected production profile and well decline rates, Encana CEO Randy Eresman said, “We estimate full-cycle finding and development costs of approximately $1.50 per thousand cubic feet of gas.” 

It would seem that given this amount of definitive analysis and cost estimates, presumably all based on the wells drilled in the area, reaching an agreement with PetroChina would have been fairly straight forward.  But as Mr. Eresman put it in the company’s recent press release, “After close to a year of exclusive negotiations with PetroChina, we were unable to reach alignment on the planned transaction.”  This was after a February statement in which Mr. Eresman touted the ability of the joint venture to “ambitiously” accelerate the development of the Cutback Ridge field.  The reaction by many analysts and energy industry parties was that either Canadian nationalism had gotten in the way or there was a problem about the economic terms of the deal.  That latter sentiment seemed to be reinforced by the second sentence in Mr. Eresman’s statement that said, “The disciplined and determined process we undertook on this one initiative in our multi-faceted and ongoing joint-venture strategy has gone a long way to demonstrate the tremendous value that we have created at Cutbank Ridge and it validates our plans to accelerate recognition of that value.”  He went on to explain the company’s strategy now is to do smaller joint-venture transactions in the drilling and production area and separate ones dealing the company’s production, transmission and infrastructure assets in the area. 

The view that the deal was killed by Canadian government demands came from the structure of the deal – a fifty-fifty venture rather than a minority position – that required an extended review and that it meet the new “net benefit” test under the Investment Canada Act.  This new test was behind the government’s effort to block the BHP Billiton (BHP-NYSE) bid to purchase Saskatchewan-based Potash Corporation (POT-NYSE).  The Canadian government had delayed approval of this transaction twice, ostensibly because of the federal elections earlier this year, but possibly as a way to send a message to China that the federal government was growing concerned about the increased involvement of foreign government-controlled entities in Canada’s natural resource industry. 

The proposed joint-venture would have been the largest Chinese investment in the Canadian energy business and in North American energy assets.  Importantly, PetroChina has lagged behind its fellow Chinese energy companies in investing in North American energy assets and in gas shale assets, in particular.  The U.S. Energy Information Administration has estimated that China’s 1,275 trillion cubic feet of gas shale resources, 50% more than estimated for the United States, represents the largest volume in the world equal to 19.3% of the global total.  This huge potential has put pressure on the government to see to the exploitation of this resource, meaning that domestic companies need to gain knowledge of the technology to successfully exploit gas shale resources.  The Encana joint venture would have been a step in PetroChina gaining that knowledge.  The failure of the deal suggests that something or someone in China was more important than the technological information that would have been gained.  Could that have been return on investment requirements? 

Natural gas prices in China are regulated by the federal government and local rules.  Current prices are averaging about half the average global gas price as the country is trying to control inflation.  While the proposed Cutbank Ridge project would have been a likely candidate for exporting gas to the Pacific region through the proposed Kitimat LNG terminal, its volumes would have been available for sale through the Pacific market and not necessarily controlled by China regulators.  Thus, we don’t see local Chinese gas pricing controls as a factor in the decision.  It seems more likely that current economics of the project may have been a significant factor.  As the gas shale revolution has spread throughout North America, the cost of drilling and completing wells has increased.  In the Encana press release about the joint venture, there was a section updating the company’s earnings guidance.  In that paragraph, Encana made the following comment about f & d costs.  “Across Encana, we are relentlessly focused on driving down supply costs, which this year we expect to average about $3.70 per Mcf.  Over the next three to five years, we are targeting a supply cost of $3 per Mcf, based on 2011 cost structures.”  We don’t know where Cutbank Ridge’s well cost estimates are now, but when the project was outlined, they were supposedly in the $1.50 per Mcf range.  Have they risen to the company average?  Are they below the average and maybe closer to the target level? 

Even with prospects that natural gas prices in North America will rise in the future, it seems that the horizon for significantly higher gas prices keeps being pushed further into the future.  The uncertainty about when economically-attractive investment returns will materialize puts increased pressure on how poor investment returns will be in the early years.  Is it possible the failure of this joint venture is the equivalent of the canary in the coal mine about the health of the natural gas business?  Canaries were used in coal mines to tell workers when air quality conditions had deteriorated to a level that endangered their health.  Poor investment returns in the gas shale business eventually destroys the available capital but also the ability of the industry to attract new investment.  Poor returns become extremely dangerous for the health of financial institutions and their investors. 

In its July/August issue, The Atlantic magazine contained an article entitled “The Ten Biggest Ideas of the Year” that included one environmental idea on the list.  The subtitle for the article was “A guide to the intellectual trends that, for better or worse, are shaping America right now.”  The point the article made is that the idea that there is a green revolution underway in the United States is false.  On March 10, 1970, Jim Henson’s muppet, Kermit the Frog, sang his signature song, originally known merely as “Green,” on Sesame Street.  The song was a statement about racial and human differences, and began with what has become a famous line, “It’s not that easy bein’ green.”  The rest of the first stanza of the song went on to say: “Having to spend each day the color of the leaves; When I think it could be nicer being red or yellow or gold; Or something much more colorful like that.” 

Although Kermit wanted to be anything but green, he had already been green for over 15 years as he was one of the first of Mr. Henson’s muppet figures and made from one of his mother’s dresses.  Kermit’s song sums up the problem the Obama administration has had in basing its energy and jobs policy on making our economy green.  Every company is striving to create green products and Toyota Motors (TM-NYSE) has been very successful in marketing its hybrid vehicles, but President Obama would like us all to drive fully-electric cars that emit no greenhouse gases. 

The article went on to make the point that the Obama administration so far has launched a significant number of green initiatives promising lots of green jobs that are supposed to offset the pain from the higher energy prices inflicted on consumers.  The problem is that this strategy is not working.  Take electricity for example. 

Exhibit 10.  Hydro Is Bulk Of Renewable Fuels

Source:  EIA, PPHB

Last year, 10% of our electricity was produced by green and renewable fuels.  The contribution split was 60/40 between electricity produced by hydropower and renewables, largely wind.  Wind power has grown rapidly since 1997 helping renewable fuels double its contribution to powering electricity generation.  The problem is that hydropower’s output over the same time span declined by 40%. 

Exhibit 11.  Hydro Contribution Falling

Source:  EIA, PPHB

The decline in hydropower is the result of having dammed most of the rivers of this country and then slowly eliminating them due to concern about their environmental impact.  The Energy Information Administration forecasts that hydropower will not increase over the next decade.  On the other hand, renewable fuels such as wind and solar have a fundamental problem in that they are variable sources of power – the wind doesn’t blow all the time nor does the sun shine at night.  In Hawaii, solar has created problems for the power companies as passing clouds can cause sharp drops in the power being supplied to the electricity grid.  The result is that these renewable fuels require carbon-fuel backup power, and the variability of their operation makes them much more expensive power providers than if they ran continuously as they are designed.  Moreover, solar and wind create temporary jobs but not sustainable employment.  Being green, we are finding out is exactly as Kermit said – it’s not that easy!

On June 23rd, the International Energy Agency (IEA) called an emergency press conference to announce that its 28 member countries, in a coordinated action, will release 60 million barrels of crude oil from their respective strategic reserves during the month of July.  Under the arrangement, the U.S. will release 30 million barrels while the remaining 27 countries collectively will offer up an equal amount.  The volume of crude to be put onto the market equates to 2 million barrels per day (b/d), or about 2% of global demand.  The action is being done in response to the “emergency” situation that has developed as a result of the loss of the 1.4 million b/d of oil exports from Libya due to the civil war underway in the country and the 300-400,000 b/d lost from Yemen due to its recent civil disturbances. 

The immediate reaction to the announcement was roughly a $4 per barrel drop in crude oil futures prices from the mid-$90s a barrel to the low-$90s.  When the announcement was made that an emergency press conference was being called, analysts, investors and energy economists began scratching their heads trying to figure out what exactly was going on.  The most popular explanation was that the IEA decision reflected a decision by governments to counter faltering global economies due to high oil prices and the inability of global monetary authorities to boost economic activity through other stimulus steps.  This was an especially popular conclusion given that U.S. Federal Reserve Chairman Ben Bernanke had told reporters in a press conference the prior afternoon that the Federal Reserve had no idea why the economy was slowing and that the agency would sit tight and not implement another “quantitative easing” program.  Instead, he said that stimulus actions needed to come from the fiscal authorities, e.g., governments. 

The questionable emergency is becoming more questionable daily as analysts examine the past experience with coordinated oil releases and they look deeper into the current oil supply/demand balances.  In the United States, current crude oil inventories, excluding the oil stored in the Strategic Petroleum Reserve (SPR), are at the highest level they have been since 1980.  The high level of inventories is largely a function of increased U.S. oil production, the growth in oil imports from Canada, principally due to its expanded oil sands output, and infrastructure limitations that restrict the movement of this inventory from the midcontinent region to the refineries located along the Gulf Coast. 

Exhibit 12.  Oil Supplies Are Healthy

Source:  EIA

In the IEA’s May oil report, which was based on data through March, total oil stocks in the OECD countries had declined into the mid-point of the 2006-2010 range.  The IEA’s estimated outlook for 2011, based on the continuation of the output cut from Libya and rising demand consistent with a global economic recovery, projects a steady decline in oil stocks through the balance of the year.  According to the chart, in June total stocks would fall below the bottom of the recent past range of inventories suggesting that global oil prices would rise to ration the oil supply.  With the additional output cut from Yemen, the projected inventory decline could accelerate, however, as the global economic recovery is fading rapidly there would be an offsetting reduction in energy demand. 

Exhibit 13.  Global Oil Stocks Falling Absent Libya

Source:  IEA

While the total OECD oil stock inventory appears to be reasonably comfortable as of March, the story within two of the three primary markets – the U.S. and Europe – is significantly different.  As mentioned above, U.S. inventories are the highest they have been since 1980.  In Europe, however, inventories are at five year lows.  The lack of Libyan and Yemeni oil output, coupled with falling production in the North Sea, is putting increased upward pressure on petroleum product prices in Europe, which are already very high. 

Exhibit 14.  Europe Oil Inventories At Lows And Falling

Source:  IEA

While the IEA’s outlook may be behind its push for the release of oil stocks, another important consideration is that the lost Libyan oil supply is light in quality and therefore extremely important for the refineries in Europe.  Those refineries are configured to refine the lighter oil and cannot use the heavier, sour crude oil Saudi Arabia has said it will add to the global supply to help offset the lost Libyan output.  This is a reason why the IEA’s coordinated oil release will be primarily light, sweet crudes that can be refined by European and U.S. refineries that should boost the supply of gasoline and diesel, which will help reduce those product prices. 

Exhibit 15.  U.S. Divided Into Oil Districts For Control

Source:  EIA

It is this particular crude oil supply release in the U.S. that is creating more questions about the impact it will have on oil and product prices beyond the very immediate term.  The U.S. established a system of monitoring oil supplies during World War II.  Due to the history of where oil was discovered in quantity and thus became the center of the domestic industry, refineries were located nearby.  This has put the U.S. refining center in the Gulf Coast states that comprise PADD 3.  This region is also where the U.S. SPR is located so any oil released will be targeted at buyers operating refineries there.  According to Platts, more than 50% of the nation’s refining capacity is located in PADD 3.

Exhibit 16.  Half U.S. Refining Capacity In Gulf Coast

Source:  Platts, EIA

When we examine the EIA’s data on crude oil stocks in PADD 3, however, we find that inventories are nearly at a recent high suggesting the refineries are not desperate for additional oil supply.  This may mean that when the EIA seeks bids for the released oil, there may not be many takers.  The last time there was a release from the SPR following Hurricane Katrina when many of the Gulf Coast refineries were put out of service and then could not secure domestic oil supply due to the damage to offshore pipelines and producing facilities, only 37% of the estimated volume was taken.  That could happen in this situation, also.  Since the released oil has to be replaced by the buyers, we are essentially borrowing supply that will then boost demand in the future.  The decision buyers will need to make is what price they have to pay for the oil, what profit margin they can make from refining and selling it, and what price they will be able to buy the replacement oil.  As this is written, oil futures are just a couple of pennies under $92 a barrel.  They have subsequently jumped back up to the mid $90s.  If we assume that later this summer oil prices move above $95, will the incremental cost to replace the SPR oil be offset by profits from refining and marketing the output?  We are now hearing that some SPR oil buyers may merely store the oil on tankers parked in U.S. ports for redelivery later when the futures trades the buyers have entered into are settled.  All that has happened is that some oil traders are locking in profits and not helping the market.

Exhibit 17.  Gulf Coast Oil Supply Very Healthy

Source:  EIA

Another interesting issue about the PADD 3 situation is that the refineries there are largely geared for lighter crude oil supplies, which is what will be released from the SPR.  But an interesting comment from a webinar held by Platts was that oil output from the Eagle Ford formation in South Texas was at about 100,000 b/d and growing.  Projections are that Eagle Ford output will reach and possibly exceed 200,000 b/d by year-end.  This oil is particularly light with an API rating of 42 to 60 degrees with an estimated distillate yield of 39%.  According to Platts, some of this oil may be too light for Gulf Coast refineries, even though Valero (VLO-NYSE) is using about 40,000 b/d at one of its Gulf Coast refineries and Koch Energy is buying some oil for its Corpus Christi refinery.  Speculation is, however, that Eagle Ford oil may be the first oil to be exported from the United States since the late 1990s. 

At the end of the day, it seems that the IEA’s coordinated oil release is addressing a growing problem in Europe due to the loss of Libyan oil output and the slow ramp up of additional oil supply from Saudi Arabia.  Additionally, the oil to be released will immediately address the need for additional light, sweet crude oil for use in European refineries and to help boost gasoline and diesel supplies helping to hold down or actually reduce oil prices.  The problem is that this oil release may only have a marginal impact on industry dynamics (much of that impact may have already occurred) in the near term and add further challenges on the supply and demand situation longer term.  The biggest damage may be that governments (led by the U.S.) are becoming more involved in the oil market, much like they did in the 1970s.  That adventure was not successful, but for politicians and government bureaucrats with little knowledge of history and how the oil industry works, their willingness to get involved in a free market will create unintended consequences.  As the history of the 1970s governmental involvement in the oil business demonstrated, the unintended consequences led to greater involvement and regulation of prices and profits – not an attractive outlook, but a scenario we can envision happening again.

Two weeks ago, Hess Corporation (HES-NYSE) withdrew its application to construct a liquefied natural gas (LNG) receiving terminal at Weaver’s Cove near Fall River, Massachusetts.  Hess LNG, a joint venture with Poten & Partners, announced plans to construct the terminal at the junction of Massachusetts and Rhode Island in June 2004.  LNG tankers would have traversed Narragansett Bay from Newport, Rhode Island to Fall River, traveling up the Taunton River.  Opposition to the proposal was led by residents along the route and local politicians who applied every imaginable legal and regulatory tactic imaginable to prevent the terminal’s approval. 

When Hess announced it was giving up on the terminal and would instead concentrate on other LNG projects elsewhere that possess stronger economic returns, citizens, the local media and politicians were jumping for joy.  We were amused to read an extensive editorial in one of the local Rhode Island papers in which the editors took credit for their editorials helping to mobilize the opposition that killed the project.  It was evident from the editorial that the media has no concept of how the U.S. natural gas market has changed since the terminal was first proposed.  As a result, they discredited Hess’ argument that the project was no longer attractive.  In fact, the editors said they fully expected Hess to come back because it has deep pockets.  The celebration appeared to be a victory for the little guys over the big, bad oil company. 

The Weaver’s Cove terminal application was filed in June 2004.  At that time, the U.S. was mired in an extended decline in its natural gas production, so growing consumption was being satisfied by increased imports, primarily from Canada, but also some LNG.  At that time, the U.S. gas industry was actively building new LNG terminals and filing applications with the regulators to construct even more.  All the industry and government projections predicted an exploding demand for LNG imports, and Hess saw an opportunity to construct a receiving facility close to a large consuming gas market.

Between June 2004 and March 2011, much about the domestic gas business has changed due largely to the success of gas shale developments.  Over the time period that the terminal application was pending, monthly U.S. natural gas production declined by 17%.  On the other hand, over the same period, monthly U.S. natural gas consumption fell by 17.3% despite gas expanding its share of the electric power generation market.  We know the reason for the increase in domestic natural gas production – the gas shale revolution spreading across the country, the jump in gas well drilling and the high initial production rate of these new wells.  At the same time, natural gas prices have collapsed from high single digits to $4-$4.50 per thousand cubic feet of gas. 

The emergence of the gas revolution and its expected continuation at a high growth rate has created a radically different outlook for the domestic gas industry than existed in the first half of the last decade.  From a gas-short market, we are now trying to figure out where to send all the gas being found.  The 2011 Annual Energy Outlook issued last April by the Energy Information Administration calls for annual natural gas production to increase from 21.5 Quadrillion British Thermal Units in 2009 to 27.0 QBTUs in 2035.  If achieved, that would equate to a 25.6% increase.  At the same time, gas imports are projected to fall by 24.9% over the same time span. 

Given the change in the natural gas market, the economic decline ongoing in Massachusetts and Rhode Island and the emergence of more renewable energy supplies in this region, Hess is making the right business call.  After the announcement, politicians in the region were all taking credit for helping foil Hess’ plans.  When questioned about this opposition and its impact on Hess’ decision, Hess LNG President and CEO Gordon Shearer was quoted saying, “None whatsoever.”  We’d love to know what Mr. Shearer thought about the Rep. Barney Frank’s (D-MA) prepared statement that said in part, “I believed that we had driven a stake through this vampire’s heart several years ago, and I’m very pleased that it has finally laid down and died.”  What was it President Barack Obama said about promoting greater “civility” in political discourse?  When market conditions change, businesses shift their strategies; politicians seldom do.

Contact PPHB:
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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.