Musings From The Oil Patch, July 23, 2013 – Musings on the Energy Industry

Shale Alters Energy Market, But Players Face Challenges
Regulator Change At BSEE Might Become Industry Nightmare
Transportation And Developing Economies Drive Oil Use
Is It The End Of The Commodity Super-Cycle?
Is Barack Obama A Modern-Day Marie Antoinette?
Is Midland’s 58-Story Tower A Symbol Of The Oil Boom?
Visual Impact Of The Power Of Eagle Ford Formation

Musings From the Oil Patch
July 23, 2013

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

Shale Alters Energy Market, But Players Face Challenges (Top)

When domestic natural gas output grew like a phoenix from the ashes of an industry projected to be completely dependent on Canadian and liquefied natural gas (LNG) imports to meet future demand, the gas shale revolution was hailed for its role. Gas executives, analysts and investors were amazed by the volumes of gas being unlocked by shale wells as a result of the technical success of marrying horizontal drilling with hydraulic fracturing. The gas industry’s phoenix-like recovery, however, was halted by the global financial crisis in 2008. But prior to that time-out, it appeared the gas industry was going to enjoy an unusual era of high natural gas prices coupled with strong oilfield activity, i.e., substantial production volumes and high drilling rig counts. That view even led some industry participants to begin imagining a world in which gas demand might never be constrained by inadequate supply.

The siren song of unlimited, cheap natural gas unleashed by the shale revolution created a boom for land leasing and drilling activity. Demand for drilling and completion services was so strong that it outstripped supply, boosting service prices and attracting huge capital inflows. This boom, which some refer to as the gas shale traveling road show, drove players to scour the landscape in hopes of finding the next most promising shale and swooping in to establish a large land position cheaply before the rest of the industry caught on. What many of these promoters failed to anticipate was how the prolific gas supply being unleashed by this boom would negatively impact gas prices, and in turn the profitability of gas shale plays.

Students of the gas shale revolution are quite familiar with the chart in Exhibit 1 (page 2) that shows the recent history of U.S. gross natural gas production and U.S. land gas output component compared to the rig count for those targeting natural gas prospects since 2005. From the early 2000s until the summer of 2008 when the financial crisis exploded, there was a steady increase in gas-oriented drilling along with a steady rise in land gas output. Overall, U.S. gas output did not climb as steadily as the land gas output component since production trends offshore in the Gulf of Mexico and in Alaska often rose and fell due to local situational events.

The dramatic decline in the rig count as a fallout from the financial crisis can be clearly seen in the chart, but notice also that land gas output declined. Total domestic gas output also fell, but it declined at a faster rate than the land output suggesting that Gulf of Mexico output also suffered from the financial crisis fallout. The important trends to observe are what happened to output and gas-oriented drilling as the nation struggled to extricate itself from the 2009 recession, which undercut economic activity, energy demand in general, and natural gas output in particular.

Exhibit 1. Natural Gas Output Rises While Rigs Fall

Source: EIA, Baker Hughes, PPHB

Starting just about a year after the 2008 peak in gas output, production turned up, both for land output and overall U.S. gas supply. That production rise continued until the fall of last year when it appears that both total gas output and land gas production reached peaks. Shortly before the gas production upturn in late 2009, gas-oriented drilling began to recover. The rig count upturn lasted just about a year before flattening out and then declining until early fall of 2011, at which point the rig count began a steep slide that has only recently moderated.

To understand how the gas industry became convinced it had entered a new era of unprecedented prosperity, one needs only to look at the price of natural gas during 2005-2013 as shown in Exhibit 2 (page 3). In broad terms, the history can be divided into pre- and post-financial crisis periods. With the exception of two significant spikes in natural gas prices between 2005 and 2009, gas prices essentially traded in the $7-$8 per thousand cubic foot (Mcf) range, a very healthy price. As the financial crisis and resulting recession trimmed domestic energy and natural gas consumption, while at the same time gas output was growing, gas prices slid until they bottomed in early 2011 in the $3/Mcf range, or less than half what prices had averaged in the pre-crisis era. While natural gas futures prices have recently rebounded above $4/Mcf, they are now trading in the mid-$3/Mcf range. The average price for the post-financial crisis era appears to be in the $3-$4 range, which is about half the average price for gas before the crisis. What appeared so promising and profitable for the gas business at mid-decade now looks to be a distressingly difficult challenge.

Exhibit 2. Rising Gas Output Drives Prices Lower

Source: EIA, PPHB

From an economic viewpoint, the best explanation of what happened to the gas industry over the past few years is demonstrated in two charts presented by energy communications firm EnerCom at its London conference earlier this summer. The two charts show supply and demand curves from the pre-crisis era and the post-crisis era. The first chart (Exhibit 3, page 4) shows what would be expected in classical economic theory if the gas supply curve of 2007 remained stable while gas demand grew to 2012’s level – higher natural gas prices!

The reality was that as demand grew, largely due to increased consumption in the power generation market in response to gas prices being below coal prices, the shale supply boom grew faster resulting in falling natural gas prices. The questionable assumption with this analysis is that the marginal cost of gas supply fell. In this post-crisis era, the decline in marginal costs was driven by questionable assumptions influencing the mathematics of calculating

Exhibit 3. Gas Prices In Classic Economic Terms

Source: EnerCom

that cost. If you excluded “sunk” costs – largely lease acquisition costs, geological and geophysical costs and often G&A expense – and divide the remaining costs of finding and developing gas by a liberal estimate for ultimately recoverable gas volumes, the resulting cost per Mcf was low. That belief supported (deluded?) operators into continuing to drill more highly prolific gas shale wells. What if less liberal assumptions had been used? Maybe marginal costs wouldn’t have seemed so low, causing drilling to slow sooner.

Exhibit 4. Why Economics Didn’t Work For Gas

Source: EnerCom

The natural gas industry’s response to sliding prices in 2010 was traditional – stop drilling. Unfortunately, the gas shale revolution had imbedded in its DNA an impediment for halting the price slide. That impediment was the commitments producers had made in their leasing agreements with landowners that the companies would commence drilling wells quickly and bring them into production in order for the landowner to receive his royalty income. These clauses were used to convince skeptical landowners they would not be yielding future income by signing leases, when past industry practices saw leaseholders often sitting on the acreage until larger property tracts were assembled, or waiting for higher gas prices. There was always the risk for the landowner that his acreage could be condemned by a neighboring dry hole. While these drilling commitment clauses were inserted by companies with a marketing edge in mind during the land-frenzy, they were not considered a potential problem since conventional wisdom at the start of the shale revolution was that the gas was sealed in blanket formations extending over the entire area and that the wells would be universally productive throughout. If true, why would a company worry about having to drill a well in order to retain leases since every well would be productive and presumably profitable?

What we have learned about the shale revolution over the past few years is that all shale formations are not alike, let alone uniform in their productive capabilities. This fundamental truth lies at the heart of the problems and challenges now facing gas producers, service companies, pipeline companies and investors. That truth could also be extended to include governments who now face lower-than-anticipated revenues and higher-than-expected infrastructure costs. This reservoir truth about shale formation diversity also helps to explain why the traditional industry adjustment mechanism of stopping drilling hasn’t worked as usual.

As the geological challenges of shale haven’t derailed the shale revolution, although they have caused it to shift from a dry-gas to a liquids-rich and crude oil focus, understanding other key driving forces behind the shale revolution becomes paramount for understanding the future direction of the domestic oil and gas business. One of those forces is capital flows into the industry while another is technological improvements in extracting gas volumes. Both forces are critical to understanding why certain decisions are being made and what future decisions companies must make in order to position themselves in the fairway of the industry’s future. Side issues involved in shaping the industry’s future include the price of natural gas, the pace of gas demand growth and whether new markets for domestic gas can be created or exploited.

If we focus on money as the force that drives, and continues to drive, the shale revolution, one can almost start with George Mitchell and his Mitchell Energy Company that cracked the code to begin commercially unlocking shale gas reserves from the Barnett formation in Central Texas. The willingness to experiment with drilling the shale formation was in response to the need for Mitchell Energy to meet a gas supply contract. Without additional supply, Mitchell Energy might have become a victim of a contractual supply shortfall, rather than becoming the George Washington of the shale revolution. Once the shale revolution was established, corporations on the outside that wished to become involved began acquiring small producers who were early participants but lacked sufficient capital to undertake the drilling to which they had committed. The shocking move by ExxonMobil (XOM-NYSE) to buy XTO Energy for $41 billion in cash and debt assumption in 2009 in order to achieve overnight a significant position in this business set off a wave of copycat transactions. Demonstrating how important this acquisition was for Exxon’s corporate strategy was the decision to move Exxon gas employees into XTO’s offices in Fort Worth, along with retaining key XTO executives.

Since Exxon’s move, the industry has witnessed numerous transactions, including outright company purchases, equity investments and the formation of joint ventures. Much of this outside money came from foreign and national oil companies seeking to boost their gas reserves, but more importantly to learn about the shale revolution for potential export to their home markets. Exhibit 5 shows a history of the funds involved in these foreign joint venture investments.

Exhibit 5. Foreign Money Supported Shale Drilling

Source: Bain and Co.

Additionally, there has been a huge wave of private equity money seeking to participate in the shale revolution. New companies backed by private equity funds were formed. At one point several years ago, we had a discussion with an A&D professional (acquisition and divestiture of producing assets) who said that all the properties she had for sale were conventional oil and gas wells and prospects, including entire portfolios of private equity-backed companies who were convinced that unless they were 100% focused on shale, it would be impossible to tap public capital markets. The flood of private equity money into the oil and gas producing sector, as well as the oilfield service industry, is being driven by the promise of a future natural gas and crude oil bonanza. That may prove to be a risky strategy, however.

Exhibit 6. Private Equity Piles Into Energy Market

Source: PwC

Forecasters around the world have declared America to be the new Saudi Arabia and a disruptive force in OPEC’s and Russia’s future. Moreover, the supposed 100 years of U.S. natural gas supply suggests that new gas markets for vehicle transportation fuels and liquefied natural gas (LNG) exports offer huge profit opportunities. Rising global demand for American shale gas could lead to higher domestic prices bringing producers huge profits. Of course that potential bonanza has triggered a debate over whether the United States should allow natural gas exports, or whether by restricting them we ensure low gas prices for a long time and enhance a revival of the American manufacturing sector with its large job-creating power. Only time will tell. But we do know that piles of private equity money are resting on the sidelines awaiting new opportunities to invest in the shale revolution. How can they do otherwise given the promise of long-term rewards?

The love-affair with the shale revolution, even though its financial rewards have not been prolific, has created a dilemma for all oilfield service companies, but in particular the contract drillers. The decline in natural gas prices since 2009 has forced operators to focus on cutting costs in their shale programs. The first reaction of producers to falling prices was to shift from drilling dry gas wells in favor of crude oil and liquids-rich targets. Simply put, these latter outputs earn higher prices, thus providing greater profitability for producers.

For those who could not completely shift their business focus, the pressure of low gas prices has become a significant driver to lower field costs. Much can be, and has been, done to reduce drilling time through greater use of seismic data, better understanding of the various formations to be drilled through to reach the target formation through downhole telemetry devices, improved bits and drilling fluids, better directional drilling hardware, and the use of drilling pads to reduce rig moving time.

Significant improvements have been made in downhole drilling and completion software and hardware. Many of these improvements eliminate or reduce the input of humans. The same thing is going on above ground. Pad drilling reduces rig mobilizations and well stimulation setup times, saving time and expense. Additionally, the industry is working toward developing fully-automated drilling rigs, i.e., rigs without human control. While that goal still remains in the future, there have been significant improvements in drilling time – known as rig efficiency. There has been so much improvement that Nabors Industries (NBR-NYSE) even cited drilling efficiency for creating a problem for producer capital spending during the second half of this year. Since wells are being drilled much faster than in the past, producers are spending their budgets faster and will exhaust their authorized funds much earlier in the year than normal. A recent exploration and production company spending survey projects that instead of a 0.8% decline in U.S. capital spending in 2013; it will fall by 2.6%. If true, drilling activity in the fourth quarter could become a rarity. Another survey says spending will increase.

Faster drilling means that the cost of rig time per well is reduced, but the amount of money spent on drilling consumables along with drilling and completion services remains constant for each well. If a rig is on a term contract (one year, for example) there is no savings on this cost component when drilling wells faster, but since all other costs remain stable for each well drilled, the more wells, the greater the cost. This is why improved rig efficiency is consuming capital budgets faster. This is not good news for drillers who are finding that fewer rigs are needed to drill the same number of wells each year. Unless capex budgets expand, the drilling rig count is unlikely to improve during the balance of this year and it raises questions about the pace of drilling and the number of rigs needed in future years.

Longer term, the unanswered question for drillers is what will the rig fleet of the future look like? How big will it be? What types of rigs will be needed? If the future of North American drilling is truly all about shale, then a certain rig fleet profile is dictated. On the other hand, what happens to that profile should shale prove less successful requiring greater drilling for conventional resources? Can we learn anything from examining the history of the evolution of the domestic rig fleet? Has there been another time in history when the drilling industry confronted a similar market and equipment shift in response to changing market trends? To examine the rig fleet we have relied on the annual rig census now compiled by a subsidiary of National Oilwell Varco (NOV-NYSE). While the survey originated in 1955, it was not as detailed then as now. Additionally, the survey was not conducted in 2002; therefore we have a one-year break in all the charts.

Exhibit 7. Rig Gap Reflects Market Shift

Source: NOV

Since 1988 there has been a meaningful gap between the number of land drilling rigs available for work and those active during any particular year. That gap was wider in the late 1980s and early 1990s due to weak natural gas and crude oil prices. As prices rose in response to the late 1990s economic boom, the effective utilization of the fleet rose. What we noticed is that starting in 2006 the gap between available and active rigs widened and has remained wide through last year’s survey. Based on the current active rig count reported by Baker Hughes (BHI-NYSE), we suspect the gap has continued to be wide.

Exhibit 8. Current Rig Market Gap Vs. History

Source: NOV

When we look at the total fleet of active versus available rigs over the entire survey time period, we find a similarly wide gap existed during the 1980s industry depression. A noticeable gap also existed in the 1950s and 1960s, but not as large as today. What we also know about that earlier period is that Baker Hughes reported a peak active drilling rig count in 1951 of over 3,000 rigs, suggesting that the available fleet was similar to that reported in the NOV survey for 1955.

Exhibit 9. When Will Next Rigbuilding Boom Come?

Source: NOV

In order to see how the available rig fleet has changed over time, we calculated the unit change each year, which is a composite of new rigs built, rigs reactivated, rigs returned to the United States from abroad minus rigs lost due to accidents, rigs mobilized abroad and those retired. What is evident from Exhibit 9 is the great rig building boom of the late 1970s and the industry depression of the 1980s. We also see the fleet expansion in the early 2000s and its contraction in recent years, despite new rig building programs underway by several prominent land drilling contractors. Their new rig additions have been offset by rig retirements.

Exhibit 10. Rig Market Demanding New Types

Source: NOV

It is interesting to examine the types of drilling rigs that make up the fleet. While there are various power sources under the mechanical definition – diesel, gas and steam – their share of the entire fleet has shrunk in recent years. You will note that we started the chart in Exhibit 10 (page 10) with 1960 since the survey data suggests greater fleet information about rig power was not collected prior to then. Another way of looking at the evolution of the rig fleet is to examine the unit change by rig power as displayed in Exhibit 11.

Exhibit 11. Electric Rig Power Gaining Market Share

Source: NOV

What we see in the change in the rig fleet by power source is that during the 70s and 80s boom and bust cycle, mechanical rigs were preferred. There were a number of SCR/electric rigs added to the fleet in the early 80s but nearly a similar number were retired in the remainder of the decade. If we examine what has happened since 2000, although there were a number of mechanical rigs built, the power source mix has steadily shifted in favor of SCR/electric rigs. The reason for this shift is the greater power needs of shale drilling rigs and the greater control required over the drilling process.

Improving the drilling process has become extremely important for producers seeking to boost their financial returns. Improvements have manifested themselves in the rig design (taller masts to handle longer pipe sections reducing the number of pipe make-ups; modularization to reduce mobilization times), increased automation (top drives; automated pipe rackers; automatic iron roughnecks), drilling activity (pad drilling; multilateral drilling; pinnate drilling; using different size rigs to drill the shallow, intermediate and deep sections of the well) and the drilling process (MWD; LWD; TBL; synthetic drilling fluids; new drillbit designs; improved downhole drilling motors). All of these items have increased the efficiency of drilling and the accuracy of wells.

Drillers are wrestling with comprehending how the drilling process may change in the future. Will it involve more improvements in the rig design, the realm of the driller, or in downhole software and hardware provided by service and equipment companies? A paper several years ago by researchers at the Energy Information Administration (EIA) who were trying to understand the impact of drilling efficiency on the growth in reserves and production offered some insightful points. Horizontal drilling has become a significant portion of total drilling. In the 1990s, barely 9% of wells were drilled horizontally. By 2010, they accounted for more than 50%. There has been a steady reduction in the number of days needed to drill wells in all the shale basins. A chart on Haynesville wells illustrates this trend, but it is true for virtually every shale basin.

Exhibit 12. Well Drilling Time Has Come Down

Source: EIA

Another measure of rig efficiency improvement is demonstrated by the steady increase in the average amount of footage drilled per rig per year.

Exhibit 13. Footage Drilled Per Rig Is Rising

Source: EIA

Another way to observe the impact of drilling efficiency is to look at the long-term trend in the number of wells per year drilled per rig.

Although the data in Exhibit 14 ends in 2008, the chart shows a generally higher sustained number of wells drilled per rig in recent years compared to the 1950-1980 period. We suspect the wells-per-rig number is higher today than shown in the chart due to recent technological improvements. This phenomenon is what was referenced earlier with respect to producers drilling up their capital budgets faster than they normally have done.

Exhibit 14. Annual Wells Per Rig Up In Recent Years

Source: EIA

Unfortunately, we have no roadmap for how the contract drilling business will change in the future. We are confident, however, it will change, and maybe in ways that are not obvious today when looking at industry data. What new drilling technologies will emerge is difficult to anticipate. We know producer cost pressures will drive change. Likely, it will mean fewer but more efficient electric drilling rigs that employ greater technology and software but fewer people. As the shale revolution has altered the debate over the resource and production potential of America and the world, it will also impact the producers and service companies trying to navigate their way to the future. These sectors will change, just how we aren’t sure.

Regulator Change At BSEE Might Become Industry Nightmare (Top)

We have written periodically about the expansion of the regulatory scope of the Bureau of Safety and Environmental Enforcement (BSEE) to include all offshore service companies in addition to operators/leases. At one point our discussion focused on whether BSEE had the statutory authority to regulate service companies under the powers granted it by the Outer Continental Shelf Lands Act (OCSLA). While that remains an important issue, the more critical one for the industry is what the regulatory rules will be and how they will be enforced. The process for establishing these offshore regulatory ground rules is the rulemaking process that requires the regulator to proffer a set of rules for comment by the industry and then to take those comments and work with the industry to reshape any rules deemed unworkable or unclear. Through this give and take process, the regulations under which service companies will be regulated will become clear, and more importantly, known and understood by service companies before they began work offshore.

The lack of regulatory clarity is problematic. Largely due to the BP Macondo trial, the long-established relationships between operators/lessees and their service company contractors have been upset. Now, all companies involved in a project offshore have joint and several liability for any damages caused during the work. That means every participant involved in providing a service is liable for the actions, or mistakes, of all the other contractors involved along with the actions of the operator/lessee. In the past, the operator/lessee was the responsible person for all regulatory errors and insurance liability. The operator/lessee could then establish a working relationship with its contractors via contracts that spelled out what risks each party would assume. That historical working relationship has now been scrambled.

While some offshore service companies were very concerned about the changed nature of the regulatory scheme and lack of clarity, others were comfortable that they could work through any issues because they had a high level of comfort with the leader of BSEE, James Watson, a former head of the Coast Guard, which shared some regulatory responsibility with the offshore industry’s prior regulator, the Minerals Management Service, and has continued that relationship with BSEE. The positive working experience with Admiral Watson gave these service company executives comfort.

Admiral Watson has announced he is leaving BSEE September 2nd for a job in the private sector. This means Sally Jewell, the recently appointed Secretary of the Interior, will be naming a replacement to head BSEE. While Sec. Jewell is well-respected and has oil company work experience early in her career, whomever she appoints to this position could tip the regulatory balance. Will her appointee be an activist with an agenda for stricter regulation or will it be someone comfortable with a light touch to the regulatory tiller? Given the recent court ruling forcing Anadarko Petroleum Corporation (APC-NYSE) to face a lawsuit over comments to investors about the company’s involvement in Macondo, managements should be more alert to the changing face of offshore regulation. Maybe offshore service executives will want to reconsider their previous decision not to push BSEE on rulemaking to clarify offshore regulation.

Transportation And Developing Economies Drive Oil Use (Top)

We continue to pay close attention to two strong economic trends to understand the future level of global oil consumption and possibly the demand for alternative fuels, along with how quickly demand is likely to grow. The Organization of Petroleum Exporting Countries (OPEC) recently issued its first look at oil consumption for 2014. Their forecast calls for global oil demand to rise by 1 million barrels a day (b/d) to 90.7 million b/d, which would exceed the estimated 800,000 b/d increase projected for 2013. This year’s growth has to be considered at risk due to the slowing global economy reflected in the recent global economic growth estimate reduction by the International Monetary Fund to 3.1% and 3.8% for 2013 and 2014, respectively, each down 0.3% from the Fund’s April forecast.

Assuming that the current economic environment in developed economies continues to slowly improve and that China’s near-term growth, albeit slower than in recent years, doesn’t collapse and Middle East tensions don’t get appreciably worse, then more oil will be needed. Unfortunately for OPEC producers and Russia, the North American shale revolution is pressuring their market shares for crude oil and natural gas supplies. Recent concerns about flattening, or even a decline, in U.S. oil and gas output this year and next due to less drilling and declining reservoir output could boost OPEC’s role in global oil markets, contrary to their recent utterances about how shale is eroding their market share. OPEC’s recent talk of cutting back production by the end of 2013 could prove to be a lagging indicator.

The resurgence of the U.S. automobile industry has been surprising, although it has benefited from the past delay in auto purchases due to the financial crisis and subsequent recession and the extremely cheap credit available. With the exception of the Cash for Clunkers government program that boosted vehicle sales for a brief period, since the late summer of 2009 at the end of the recession, the volume of monthly auto sales has been straight up. While reflecting a significant recovery, monthly auto sales have yet to reach levels that persisted for most of the early 2000s until the financial crisis in 2007. Will auto sales reach those historical levels, or will the monthly rate moderate while remaining at a healthy level?

Exhibit 15. U.S. Auto Industry In Strong Recovery

Source: U.S. Global Investors

From a global perspective, the health of the Chinese and U.S. auto markets is extremely important for the global oil market, as reflected by the first half of 2013 sales figures compared to last year. If the European Union and Japan auto sales comparisons were to become positive, or at least not be significantly negative, global vehicle demand will become quite strong, as long as all other markets remain stable. Counting on improved contributions from those two markets is questionable given their current demographic, economic and political forces. It doesn’t appear these factors will improve materially, especially with respect to demographic trends. Any improvement should trigger an upward move in auto sales, but a sustained upward trend will require time to become established in our view given the amount of economic damage inflicted on these countries over the past half-decade.

Exhibit 16. Global Auto Industry Led By China And US

Source: U.S. Global Investors

The overriding consideration supporting higher future oil demand lies in the analysis of energy use per capita in developing economies and the historical relationship compared to various country’s growth in gross domestic product (GDP) per capita. As shown in Exhibit 17 on the next page, the developed economies that rank highest in GDP per capita also rank high in the amount of energy used per capita. Developing economies appear uniformly inversely-related on those measurements, but they offer the prospect for being the principle driving force for energy demand growth in the future as their economies and populations grow.

Exhibit 17. Developing Economies Drive Oil Consumption

Source: U.S. Global Investors

Factors at work in the developing economies boosting energy demand include urbanization and industrialization. Both trends are “resource-intensive.” Virtually all of these developing economies have large populations so it only takes a modest rise in per capita energy use to translate into a large absolute increase in global energy consumption. If the history of mankind is any guide, these trends will occur and energy consumption will rise.

Is It The End Of The Commodity Super-Cycle? (Top)

Earlier this summer, there were a number of investment professionals and investor newsletters harping on the theme that the commodity super-cycle is over due to the slowing of global economic growth and especially the accelerating growth of China. In 2010, economists at Standard Chartered PLC (STAN.L) issued an extensive report declaring the world was in the midst of its third super-cycle since the mid-1800s, and that the cycle, despite volatility, would extend until 2030. The two prior super-cycles they identified occurred in 1870-1913 and 1946-1973, and were marked by meaningfully higher global economic growth rates compared to the period immediately prior.

Exhibit 18. Third Super-Cycle Underway

Source: Standard Chartered

The primary reason for the super-cycle has been the rapid growth of China driven by its cheap manufacturing labor supply and its expanding middle class population. Two charts (Exhibits 19 and 20) show the geographic composition of the global economy in 2010 and its expected composition by 2030. Examination of the charts shows that China’s and India’s share of global output will expand from 9% and 2% to 24% and 10%, respectively. On the other hand, the U.S., EU and Japan, collectively, will shrink in their share of global output from 60% to 29%. For this dramatic reshaping of the global economy to occur there will be a substantial increase in basic materials and energy, which is the backbone of a commodity super-cycle.

Exhibit 19. Current GDP Favors Developed Economies

Source: Standard Chartered PLC

Exhibit 20. Future GDP Reflects Greater Role For China

Source: Standard Chartered PLC

A slowing Chinese economy is being equated with the end of the super-cycle. That said, when we look at the price performance of energy and raw materials over the first half of 2013 we observe an interesting pattern. Mineral prices have declined during this period, but energy prices have risen.

Exhibit 21. End Of Super-Cycle?

Source: U.S. Global Investors

Unsettled geopolitical conditions in the Middle East may be part of the explanation for higher oil and gas prices so far this year. However, operators are using fewer drilling rigs in the United States, although there remains strong international drilling demand as reflected by higher active rig counts and a flurry of new orders for offshore drilling rigs. Is the energy business seeing its own super-cycle, or do the price trends of oil and gas during the past six months reflect a bubble?

Is Barack Obama A Modern-Day Marie Antoinette? (Top)

On June 25th, President Barack Obama delivered his signature climate change speech in the midday heat to an audience assembled outside at Georgetown University. In the speech, he heralded the need for the United States to take a global leadership role in reducing carbon emissions in order to prevent catastrophic damage to the planet that would hurt the youth of the world and future generations. His goal is to reduce the use of dirty energy in the U.S. through tougher emissions restrictions on existing coal-fired power plants, promote the use of more clean energy by funding research in new clean energy technologies, and reducing the amount of energy consumed through stricter energy efficiency standards such as high fuel efficiency standards for vehicles. He also wants to get the developing world to work with the U.S. to slow its energy consumption, and that involves eliminating funding for new coal-fired power plants around the world and pressuring countries to use more natural gas and clean energy.

The day after his speech, the President, First Lady and their two daughters left on an eight-day trip through three African countries. While the President was slammed by the leaders of two of his host countries for his position on gay rights, his greatest faux pas may have been the message he delivered to African children. In speaking to a group of African youth, President Obama said the following: “Ultimately you think … about all the youth that everybody’s mentioned here in Africa, if everybody’s raising living standards to the point where everybody’s got a car, and everybody’s got air conditioning, and everybody’s got a big house the planet will boil over – unless we find new ways of producing energy.”

In thinking he was defining the need to develop clean energy, a message the President has been pushing in America, he was actually dampening the aspirations of the young, poor African children in the audience. This is a world where 1.2 billion people lack access to electricity and 2.8 billion with only access to primitive cooking fuels. Lore has it that one contributor to the unrest that fostered the French Revolution was sharply rising bread prices. In response, France’s Queen, Marie Antoinette, supposedly said: “Let them eat cake.” A dichotomy of views over economic development lies at the heart of the global challenge for limiting carbon emissions. Why should Africa’s youth, or the youth of any developing country, be told to sacrifice their desire for electric appliances and motor vehicles, which is a given in the developed world, in order to limit global carbon pollution. That view reflects the outrageous attitude attributed to the beheaded French Queen.

Is Midland’s 58-Story Tower A Symbol Of The Oil Boom? (Top)

EnergyInc: Texas Edition carried a story recently stating that the planned 58-story tower for Midland, Texas will become a symbol of the current oil boom. The Energy Tower at City Center will become the tallest building in West Texas and will dwarf the current tallest building in Midland, the 24-story Bank of America Building. The building will commence construction once leases for 30% of the space have been signed and it will then take 30 months to build. At a presentation in Dallas introducing the building to real estate professionals, comments made suggested that the Permian basin office market is in desperate need of new, upgraded space since there hasn’t been much built since the great boom of the 1970s. As one speaker put it, “We missed out on the prior booms.”

Exhibit 22. Midland Tower Will Change City

Source: Edmonds International

The Energy Tower will be a combination of a hotel, office and retail space, restaurants and park space. It will be located near I-20 and will certainly provide a notable new symbol of Midland. The scary thought, however, is how other iconic office towers in Texas have marked the end of oil booms. If we look only at Houston, the 64-story Williams Tower (WMB-NYSE), formerly the Transco Tower and located behind the Houston Galleria complex, was constructed in 1983. The building is the 4th-tallest in Texas, the 22nd-tallest in the United States, and the 102nd-tallest building in the world. It is the tallest building in Houston outside of Downtown Houston, and at the time of its construction was believed to be the world’s tallest skyscraper outside of a central business district. The 75-story JP Morgan Chase Tower, formerly Texas Commerce Tower, at 1,002 feet is currently the tallest building in Houston, the tallest building in Texas, the tallest five-sided building in the world, the 13th tallest building in the U.S. and the 75th tallest building in the world. It was built in 1981. Lastly, consider the 71-story Wells Fargo Plaza, formerly the Allied Bank Plaza and First Interstate Bank Plaza, is the 14th tallest building in the U.S., the 2nd tallest building in Texas and Houston, and the tallest all glass building in the western hemisphere. The building stands 992 feet tall with four more stories below street level, and was completed in 1983.

Does anyone remember what was happening to the global economy and especially energy prices in 1981-83? The boom of the 1970s, reflected by global oil prices, peaked in 1981, but experienced a brief rebound in 1983 with the introduction of area-wide lease sales in the Gulf of Mexico by the federal government. That rebound ultimately became a “dead-cat bounce” as the market was crushed by the 1985 collapse in global oil prices when Saudi Arabia stopped supporting high OPEC oil prices by ceasing to cut its output and oil exports. In fact, Saudi Arabia waged an oil output war to teach its fellow OPEC members the need for cooperation in oil production policy. Given the debate today about where oil prices may be heading in light of slowing economic growth, especially in China, one has a sense of “dejá vu all over again,” to quote that great philosopher, Yogi Berra.

Visual Impact Of The Power Of Eagle Ford Formation (Top)

We were captivated recently by a recent satellite picture from the National Aeronautics and Space Administration (NASA) showing the lights at night from the drilling operations in the Eagle Ford formation of South Texas. The picture (Exhibit 23, page 23) shows the mass of city lights of Dallas-Fort Worth, Houston, San Antonio and Austin along with the Eagle Ford drilling rig pads. The drilling rig lights begin just east of San Antonio and south of Austin and then extend all the way to the left-hand side of the photograph.

In exploring other photos of the Eagle Ford, we found the photo in Exhibit 24 on page 23 showing the extent of drilling rig activity in the trend – at the time about 138 rigs were working. The drilling rigs are concentrated in a crescent-shaped swath of light extending from the Texas/Mexican border upward to just below the bright spots representing Austin and San Antonio near the center of the state. For those who have followed the evolution of the Eagle Ford formation know that the area of rig concentration this spring is the oil and liquids-rich trends of the play. The light swath provides a sense

Exhibit 23. Eagle Ford Drilling Rigs Light Up Night

Source: NASA

of the magnitude of the Eagle Ford formation and its importance for Texas and the nation’s energy supplies.

Exhibit 24. Eagle Ford Lights Crescent Work Area

Source: NASA

These photos reminded us of an earlier period in our career and dealt with the Anadarko Basin, as equally significant an energy play in its day as the Eagle Ford is today. In the fall of 1981, drilling for deep natural gas had been incentivized in response to the gas shortages of the late 1970s and operators were targeting the 1985 decontrol of gas prices. The success Robert Hefner of GHK Company had in pioneering deep drilling (below 15,000 feet) for natural gas in Oklahoma coupled with the price incentives encouraged him to push deeper. GHK embarked on an ultra-deep gas drilling (below 25,000 feet) program in the Anadarko Basin of western Oklahoma and the Texas Panhandle. He also attempted some ultra-deep wells in the Arkoma Basin on the other side of Oklahoma. The Oklahoma deep drilling records show the impact of that effort as the state had 198 deep well completions in 1981 and nation-leading totals of 430 wells in 1982 and 375 in 1983.

At this time, the investment firm we were working for held a conference in Oklahoma City for investors interested in the Anadarko Basin and deep gas drilling. At the dinner, there was a spirited discussion about the opportunities and activity for deep drilling involving Mr. Hefner, Bobby Parker of Parker Drilling Company (PKD-NYSE) and the investors. In response to that discussion, a helicopter trip was arranged for the next day to show the investors the drilling rigs at work. We had previously seen the mass of drilling rig pad lights on our flight into Oklahoma City so we appreciated the visual impact of seeing these drilling rigs seemingly everywhere. Today, the availability of photos of areas taken from satellites overshadows the view one gains from planes and helicopters without the need to travel. Of course, having seen the earlier version of a drilling boom, one has a greater appreciation of the photos from space.

Correction:

In the last Musings we incorrectly referred to the octane rating for the “clean” diesel that would be produced by Sasol’s proposed GTL plant when we should have referred to the fuel’s cetane rating that refers to the fuel’s combustion quality. We are sorry for the error.

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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.