MUSINGS FROM THE OIL PATCHenergy-musings.com/sites/default/files/Musings 022520.pdf · Arabia...

MUSINGS FROM THE OIL PATCH February 25, 2020

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 and planning for the future. The newsletter is published every two weeks, but periodically events and travel may alter that schedule. As always, I welcome your comments and observations. Allen Brooks

Summary:

The Rhyme Of Oil History Should Be Heard And Studied – Part 9 The industry stands on the edge of the next restructuring phase. We examine its debt problems as well as its financial performance and ability to generate sufficient cash flow to continue growing its reserves and output.

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Global LNG Catches The Virus, But Maybe Has Bigger Issues The COVID-19 virus has severely impacted China’s energy consumption, creating oil price problems. These problems are hitting the LNG market, too. But it may be suffering from some structural problems, also.

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Climate Change, Green Energy And Meeting Energy Needs Wildfires in Australia and wind and solar power in the UK are all tied to climate change, although the facts don’t support the former and the latter still remain expensive and require backup power that will be very costly.

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Correcting Some Oil Patch History With the aid of an old friend who was involved in one oilfield service company deal we talked about, we are able to correct a mis-identification of the protagonist in a colorful takeover battle.

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MUSINGS FROM THE OIL PATCH PAGE 2

FEBRUARY 25, 2020

The Rhyme Of Oil History Should Be Heard And Studied – Part 9 The industry has turned the U.S. into a new global energy powerhouse, altering geopolitical relationships and liberating the country’ economy from dependence on Middle East oil “The current restructuring of the global oil and gas industry suggests that optionality is becoming more important than sheer scale”

This chapter in our search for the similarities and differences between the current oil and gas industry downturn and the one from the ‘boom and bust’ era of the 1970s to 1990s has us examining capital structures, debt and profitability. For the past five years, the industry had been wandering through a netherworld of fluctuating oil and gas prices, growing social and political pressures challenging the existence and ‘reason for being’ of the energy business, and geopolitical events that have the potential of completely reshaping the business. Despite those challenges, the industry has turned the U.S. into a new global energy powerhouse, altering geopolitical relationships and liberating the country’ economy from dependence on Middle East oil. After five years of waiting for conditions to improve, we believe there is a growing recognition that the phrase ‘this time is different’ may actually be true. It doesn’t mean everyone has bought into this realization yet, but they will have to at some point in the foreseeable future. We ended our last chapter with the following:

“Just as the producer sector needed nearly 15 years to complete its transformation following the collapse of global oil prices in the mid-1980s, so too did the oilfield service sector. The two final oilfield service industry transformative deals occurred in the first half of 1998. Halliburton agreed to acquire Dresser Industries in a $7.7 billion merger in February, and Baker Hughes merged with Western Atlas in a $5.5 billion transaction in May 1998. Following these deals, the global oilfield service industry was left with three very large service companies with broad portfolios of products and services along with the global scale to deliver them to customers worldwide. Scale-to-scale was the mantra driving the energy business restructuring as the end of the 20th century approached. The current restructuring of the global oil and gas industry suggests that optionality is becoming more important than sheer scale. For the oilfield service industry, serious self-examination of company core strengths is being undertaken, which is leading to meaningful restructuring of companies from top to bottom within the sector. Understanding what the defining mantra is for the energy industry for the next decade will shape its future and how producers and service companies will have to look and operate to be successful.”

After reading the last Musings issue, a friend emailed us with the comment that he was now referring to what is happening in the energy patch now as ‘The Reconstruction Period.’ That reference sent us back to examining our history. An article titled


FEBRUARY 25, 2020

For them, it is inevitable crude oil and natural gas prices will have to rise to very high levels if the world’s future hydrocarbon needs are to be met The lower demand projections by the IEA and OPEC suggest global inventories will grow more than anticipated, increasing pressure on global oil prices and further testing the resolve of Saudi Arabia to keep its OPEC+ (the alliance including Russia) output under control

Reconstruction on History.com began with the following: “Reconstruction (1865-1877), the turbulent era following the Civil War….” That statement got us thinking, not about the violence and retributions associated with the political and social struggles the U.S. faced in attempting to put the union of the states back together in 1865, but rather about the similarity of the oil wars waged by Saudi Arabia against its fellow OPEC members in 1985 and again in 2014. As often happens with wars, there are many unintended consequences. One unintended consequence is the health of the global energy industry. Can we put Humpty Dumpty back together again? Many people want to, and believe it is possible. For them, it is inevitable crude oil and natural gas prices will have to rise to very high levels if the world’s future hydrocarbon needs are to be met. Higher commodity prices will provide the cash flows oil and gas companies will need to fund increased exploration and development to find the additional hydrocarbons the world will be clamoring for. That price recovery currently is being delayed by disruptions created by the emergence of a coronavirus in China, officially designated as covid-19 by the World Health Organization. As a result of the virus, the International Energy Agency (IEA) has reduced its global oil consumption estimates for both the first quarter of 2020 and the full year. The agency now calls for a decline in consumption in the first quarter of 425,000 barrels per day (b/d). This will mark the first time in a decade that global oil demand contracts during the first calendar quarter, a time when demand normally rises due to winter temperatures. The IEA also cut its full-year 2020 demand projection to only 825,000 b/d, a reduction of 365,000 b/d, marking the lowest annual increase since 2011. Underlying the reductions are the IEA’s belief that rather than representing a third of the estimated oil consumption growth in 2020, China’s oil use will only represent about 20% of the growth. OPEC, according to the organization’s latest monthly report, has also reduced its demand growth forecast for this year by an estimated 230,000 b/d. The lower demand projections by the IEA and OPEC suggest global inventories will grow more than anticipated, increasing pressure on global oil prices and further testing the resolve of Saudi Arabia to keep its OPEC+ (the alliance including Russia) output under control. The OPEC+ parties have been in discussions about increasing the group’s output cut from 1.7 million barrels per day (mmb/d) for the first quarter of 2020 by an additional 600,000 b/d, as recommended by the group’s technical monitoring staff. Despite extending the two-day technical group’s meeting and consultation, the parties have yet to agree to either the increased amount and/or the timeframe of the reduction. Reports are that Russia favors extending the first quarter 1.7 mmb/d cut by another three months, rather than increasing the reduction.


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Pressure on global oil prices continues unabated, with price relief whenever positive news about the virus’s containment is published

Pressure on global oil prices continues unabated, with price relief whenever positive news about the virus’s containment is published. The Wall Street Journal highlighted the impact of oil hedges, a popular investment vehicle for aggressive investors to capitalize on commodity price trends, on the price drop. The paper’s article contained three charts telling the story of how the fall in the number of futures contracts to purchase oil correlated with the decline in oil prices and the value of energy companies. These charts reinforced two points about the oil business: 1) the increased volatility of oil prices driven by events external to the operations of oil companies; and 2) how short-term events are depressing the industry’s outlook, as reflected in the underperformance of energy share prices. Exhibit 1. Unwinding Long Positions Pressured Oil Prices

Source: WSJ.com


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Exhibit 2. The Pressure Of The Virus On Oil Prices

Source: WSJ.com

Exhibit 3. Energy Stocks Remain Out Of Favor

Source: WSJ.com


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The third chart carries longer lasting implications, as it reflects the disdain investors have for energy stocks Oil prices crashed, the supply of capital for the industry dried up, and the surplus of equipment, lack of activity and overleveraged balance sheets destroyed companies, forcing the energy industry to undergo a massive restructuring All of this construction consumed copious amounts of the world’s raw materials and a substantial portion of its hydrocarbon output

Is there a message in these charts? Short-term, commodity traders adjust their oil contract positions in reaction to news signaling demand shifts that impact oil prices. The oil price chart is little more than a history of where prices have been, which highlighted how oil prices fell as concerns over COVID-19’s impact on oil demand grew. The third chart carries longer lasting implications, as it reflects the disdain investors have for energy stocks. The energy share performance reflects investors shifting capital away from the energy industry because they believe its outlook is unfavorable. If we use the price of oil in real, inflation-adjusted, terms as a way to measure how the world viewed the near- and long-term outlooks for oil and oilfield service companies during 1973 to 2020, we can clearly identify two cycles. Exhibit 4 (next page) shows our division of this history into shorter time spans reflecting industry and investor perceptions about the energy industry’s future. Had we used current-dollar oil prices, we would have seen that today’s oil price, even though lower than it was in the recent past, and below where many people believe oil prices should be trading, is still 10-15 times greater than oil prices were during the 1970s boom period. We have divided the 1973-2020 era into five distinct periods for purposes of analysis. The first – 1973-1985 – reflected the initial industry boom when oil became extremely expensive in response to fears of serious supply shortages. The boom turned into a bust when the shortage fears and high oil prices suddenly produced opposite results. Rather than a shortage, high oil prices resulted in significant new supply sources being tapped, as well as OPEC members engaging in “beggar thy neighbor” production quota cheating to generate more income for themselves. Oil prices crashed, the supply of capital for the industry dried up, and the surplus of equipment, lack of activity and overleveraged balance sheets destroyed companies, forcing the energy industry to undergo a massive restructuring. This restructuring period extended from 1986 to 2002 and resulted in dramatically different oil and gas, and oilfield service industries emerging at the end. As the dust from the mid-1980s energy bust began to settle as the new century commenced, there was an explosion of oil consumption in China, driven by the country’s preparations for hosting the upcoming Olympics. In expectation that many visitors to China attending the Olympics would want to tour the country, its leaders desired to showcase a modern state, necessitating the construction of new airports, roads, rail lines, as well as new housing and hotels, etc. All of this construction consumed copious amounts of the world’s raw materials and a substantial portion of its hydrocarbon output. China’s consumption of oil and raw materials set off alarm bells over fears for a potential peak in global oil supplies. Dramatically higher oil prices resulted, as the market needed to drive exploration and development of new reserves, while also slowing current consumption.


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The lack of liquidity sent massive industries, including oil and gas, depending on free-flowing capital to fund their activities to meet supply needs into chaos For much of this five-year history, oil prices have traded in a fairly narrow range

Exhibit 4. Characterizing The Oil Market Over Time

Source: EIA, St Louis Fed, PPHB

The commodity-driven boom of the early 2000s suddenly ran into a financial firestorm caused by the mismanagement of the U.S. housing finance and mortgage market. The fallout from this crisis was an unimaginable event in modern financial history – a global liquidity crisis. The lack of liquidity sent massive industries, including oil and gas, depending on free-flowing capital to fund their activities to meet supply needs into chaos, necessitating government bailouts and injections of copious amounts of money into the financial system by central banks. After the financial crisis and accompanying global recession during 2007-2009, oil prices spiked as demand rebounded sharply. This made oil extremely expensive, once again, and regenerated the fear of an impending oil supply peak. That condition existed until mid-2014 when supply, driven by the profits from expensive oil and expectations that oil prices would only go higher, began to outrun demand, creating a global oil inventory imbalance, which slowly grew into a glut. Once again, key factions within OPEC battled over how to allocate the smaller output required of the organization to meet the world’s needs. This led to a dramatic collapse in oil prices when Saudi Arabia again acted to teach its fellow OPEC members another lesson about quota cooperation. After a brief oil price recovery, there emerged a realization that global oil supply, driven by the earlier high oil prices, was not going to settle into a balanced market quickly or easily. Thus, oil prices fell again, dispelling the hope that the 2014 oil price collapse was yet another short-term industry cycle. The range of oil prices since 2015 has been wide. However, both the peak and the valley of prices were brief. For much of this five-year history, oil prices have traded in a fairly narrow range. At the present time, the uncertainty about


FEBRUARY 25, 2020

The average real oil price for the first boom was $71 per barrel, which then transitioned to an average of $36 per barrel during the restructuring era of 1986 to 2002 As the current low oil price condition continues, there are many in the industry, and others outside, worried about its ability to earn a profit at “such low oil prices”

the potential oil demand impact – both magnitude and duration – due to the coronavirus has oil prices trading at the lower end of the channel where they have traded for much of the time. The differences in these five historical periods of the oil business are reflected by the wide spread in average oil prices between them. The average real oil price for the first boom was $71 per barrel, which then transitioned to an average of $36 per barrel during the restructuring era of 1986 to 2002. The emerging China boom pushed the average real oil price up to $58 per barrel, which then climbed to a $99 average during the last boom with its peak-oil frenzy. The current period, albeit only five years in duration, finds the industry dealing with an average oil price of about $56 per barrel. While the current period’s real average oil price is 56% greater than the average experienced during the 1986-2002 reconstruction period, what may be more illustrative of these similar environments is to compare the change in the average oil price between the over-supply periods with the average prices of the earlier booms. The 1986-2002 period saw an average oil price about 52% of the average price of the 1973-1985 boom period. The current 2015-2020 average oil price of $56 just happens to be 56% of the prior boom period’s $99 per barrel average price. As we are only five years into the current downturn, and we don’t know how much longer it may last, it is possible that the eventual average oil price for this period will be lower, and thus its percentage difference may increase. The point is that the current downturn has witnessed a similar price correction as seen in the earlier period cycle. As the current low oil price condition continues, there are many in the industry, and others outside, worried about its ability to earn a profit at “such low oil prices.” Many of these people are also concerned about the impact reduced industry cash flows will have on future exploration and development spending, and, in turn, on future oil and gas discoveries. We continue to hear the refrain: Low oil prices and resulting reduced E&P spending mean higher future prices to meet demand. This argument has been made many times in the past – starting with 1981 when oil prices peaked at the end of the first oil boom. As we wrote in Part 6 of this series in our January 14, 2020, Musings issue, the argument about the resulting starving of oil industry capital spending leading to a rebound in price was highlighted in the late 1990s Federal Deposit Insurance Corporation (FDIC) report, An Examination of the Banking Crises of the 1980s and Early 1990s. The authors of the study were attempting to explain a major problem banks in the Southwest experienced in dealing with the oil downturn, which was their optimism that prices would rebound and activity would resume and loans would be repaid. As they wrote in their study:


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That history was replete with booms and busts, as prolific new fields were discovered, swamping demand and sending oil prices crashing Total reserves in the United States have more than doubled over the decade of 2008-2018

“Many banks compounded their troubles by presuming that the weakening in oil prices was merely temporary. For example, James Cochrane, chief economist of Texas Commerce Bancshares, argued that the low level of exploration in mid-1985 would result in future shortages of oil and gas supplies and that ‘by the end of the decade, we will have a serious inability to supply energy products. . .We continue to believe in the long-term future of the industry.’”

Was this merely blind faith that every time the capital spending spigot was turned off oil prices would rebound, or was it based on fundamentals? Remember that in the mid-1980s, the U.S. oil industry already had about 120 years of history. That history was replete with booms and busts, as prolific new fields were discovered, swamping demand and sending oil prices crashing. At that point, the wildcatters who were driving the industry’s development would stop spending. Eventually, the output from some of the highly prolific wells would diminish, and oil consumption would grow, providing a market correction mechanism to lift oil prices and attract the wildcatters back to the business in their quest to create the next boom and bust. In the 1960s, the United States Geological Survey (USGS) estimated that the proved reserves of the nation had peaked and were in decline. In 1961, the USGS estimated proved reserves were 31.8 billion barrels of crude oil. By 1969, total reserves had declined to 29.6 billion barrels. In 1970, total reserves grew by 9.4 billion barrels, primarily due to the inclusion of the Prudhoe Bay discovery in Alaska. Today, the government estimates Prudhoe Bay will yield approximately 13 billion barrels of ultimately recoverable crude oil. Total crude oil reserves for the United States in 2018 were estimated to be 43.8 billion barrels. That volume was helped by both offshore discoveries in deep water in the Gulf of Mexico and the impact of the shale oil revolution. Total reserves in the United States have more than doubled over the decade of 2008-2018. People might say that the dramatic increase in U.S. proved oil reserves is attributable to the higher oil price of the 2006-2014 period, and future reserve growth is at risk due to lower oil prices. While there may be some truth to that statement, even if proved reserves decline from their 2018 peak, it is difficult to believe the nation’s oil supply is at risk any time soon. Any contrary argument disregards further technological improvements in drilling, completion and recovery technologies. On the other hand, forces are at work that could cap the oil and gas industry’s productive capability, thereby limiting our hydrocarbon consumption growth. Those caps would likely be put in place in response to social and political pressures. If that were to happen, it would fulfill the observation of Saudi Arabia’s Oil Minister Sheik Yamani in the mid-1980s that the Stone Age ended before they ran out of stones, and the Oil Age will end before we run out of oil.


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Gas available for purchase by buyers operating in the interstate market was often outbid by intrastate pipelines who were not subject to federal price regulations The deals allowed the pipelines to pay upfront for gas reserves the drillers anticipated finding

Exhibit 5. A Modern Revival For Domestic Oil Industry

Source: EIA

The experience of crude oil was mirrored by natural gas in the United States during the 1960s. Gas available for purchase by buyers operating in the interstate market was often outbid by intrastate pipelines who were not subject to federal price regulations. This situation caused many interstate natural gas pipeline companies to seek additional gas reserves and production from federal offshore waters. The rise in finding and development costs soon outstripped the prices allowed to be paid under federal price regulations. At the same time, the more attractive gas reserves were located in state waters, which meant that interstate pipelines were at a disadvantage against intrastate pipelines who possessed greater price flexibility. In an attempt to rectify this competitive imbalance, the Federal Power Commission (FPC) allowed interstate pipeline companies to make deals with offshore natural gas explorers in a unique way. The deals allowed the pipelines to pay upfront for gas reserves the drillers anticipated finding. For the pipeline companies, these advance payments were to be carried as assets on their books and included in their rate base calculations, which meant they would earn their allowed rates of return on the funds advanced to the drillers. Successful exploration programs would be paid back from the value of the gas production. In the case of exploration failures, the advance payments did not have to be repaid by the driller, and any unpaid advance would remain as an asset and be included in the pipeline’s rate base earning its regulated return. This advance payment program worked wonders to revive the Gulf of Mexico drilling market as producers cranked up their drilling. The key question today about our oil production future is whether the oil industry will have sufficient cash flow to invest in new drilling and completion activity. Expectations for capital spending in the United


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Globally, upstream spending is projected to rise by about 2%, as the anticipated 5% increase in international spending offsets the domestic spending decline E&P spending is now less of a priority than seeing companies live within their cash flows Over the years, the number of companies participating in surveys has fluctuated, impacting reported spending totals

States in 2020 have called for a 10% decline from 2019’s spending levels. Globally, upstream spending is projected to rise by about 2%, as the anticipated 5% increase in international spending offsets the domestic spending decline. These spending estimates are based on estimates from industry surveys of oil and gas producing companies undertaken late last year, and are at risk of not reflecting potential budgetary reductions in 2020 in response to the lower oil prices due to the coronavirus. Upstream capital spending is only claim on oil and gas company cash flows. Companies also must fund their operations, i.e., spend on oil and gas production activities, as well as repay debts previously incurred. There is also the possibility of rewarding shareholders through the payment of dividends or the repurchase of outstanding company shares. All three of these uses of company cash flow are considered at the moment to be of greater shareholder value than increased spending on new exploration activity. This priority for using a company’s cash flow reflects the new industry mantra demanded by shareholders of sustaining the company’s production and financial health, while also returning surplus cash to shareholders. E&P spending is now less of a priority than seeing companies live within their cash flows. However, it is axiomatic that if a company cannot sustain its output, or manage a decline while building up other sources of income, shareholders will view the entity as a liquidating asset with little residual value. Reserve growth, production growth and shareholder returns are all balanced against the growing sustainability pressures driven by representatives from the climate change movement. Before considering how these pressures are altering the historical operating approach of oil and gas companies and oilfield service entities, we should look at how upstream spending progressed historically. Tracking oil and gas industry upstream spending has been an elusive goal for years. Energy investment analysts have been gathering company spending intentions and actual spending data for decades in hopes of being better understand how to value producers, while at the same time being able to forecast the fortunes of the oilfield service companies. We also engaged in this pursuit during our career on Wall Street. As a result, we have gathered estimates of capital spending data from multiple sources over the years. The technology to collect more and better data have improved, but it has meant that no upstream spending survey has consistency over time. Merger and acquisitions among the producers have made it difficult to track the same universe of companies consistently. In addition, as the international oil and gas industry has matured, especially with the rise of state-owned petroleum companies, tracking them and convincing them to respond to survey inquiries has proven to be challenging. Over the years, the number of companies participating in surveys has fluctuated, impacting reported spending totals.


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What we see in the spending data post 2003 is a large, growing spending pool, which at times expanded rapidly By tracking the spending in constant dollars for a consistent universe of companies we can see how spending trends unfolded over time

The longest consistent E&P spending survey is conducted by Barclays, which began as a research effort by the oilfield service analysts at Lehman Brothers. In its most recent survey report (December 2019) estimating spending expectations for 2020, Barclays published the chart in Exhibit 6. Their survey is divided between North American and International markets. As seen from the chart, overall spending was relatively flat between 1985 and 1995, before increasing somewhat. From 1998 through 2002, spending again was fairly flat. It wasn’t until after 2003 that spending started to rise sharply, which would be consistent with what was happening with oil prices, as we have highlighted earlier. What we see in the spending data post 2003 is a large, growing spending pool, which at times expanded rapidly as illustrated by the arrows. Over 2002-2008, the compound annual growth rate (CAGR) in spending was 18%, followed during 2009-2014 by an 11% CAGR rate, which then slowed to only a 5% rate for the 2016-2020 period. This latter slowdown in global upstream spending growth is not surprising given the fall in oil and gas prices and the increased pressure on producers to exercise greater capital discipline. Exhibit 6. How Oil Industry Capex Has Tracked

Source: Barclays OFS Research

The Energy Information Administration (EIA) used to collect and publish data about the financial performance of the oil and gas industry. One statistic they collected was upstream spending measured in inflated dollars. The problem was that the EIA only tracked 42 companies that they thought were representative of the industry, but not as complete a survey as attempted by Lehman/Barclays. However, by tracking the spending in constant dollars for a consistent universe of companies (See Exhibit 8, next page, for the companies), we can see how spending trends unfolded over time. Moreover, by plotting the real and nominal oil price against the spending data, we are afforded an interesting window into the attitudes of E&P company executives regarding the market.


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The EIA also tracked the merger and acquisition activity of this group of producers, which demonstrates that it took a long time in the face of flat-to-declining oil prices before the industry came to grips with the pressure to restructure and finally acted. Exhibit 7. Real Oil Industry Capex And M&A Activity

Source: EIA, PPHB

Exhibit 8. EIA Oil Company Financial Analysis Universe

Source: EIA


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What is key is that the trend in spending changes mirrors closely the trend in oil prices in current dollars It is also noteworthy to point out that the consecutive years of 1985, 1986 and 1987 were all negative In the 1981-1985 span, the declines in total spending were reflected initially in greater reductions for production and development, and only later cuts to development and exploration spending

As we have collected upstream spending data since 1970, we have never been confident that each survey’s history had the same companies and covered the entire industry. What we did gain confidence in, as we attempted to integrate the various surveys, was that the annual percent changes in upstream spending were consistent. It is important, however, to understand that the high percentage increases experienced in the 1970s and early 1980s were on total spending amounts that were relatively small. Thus, it didn’t take huge spending increases to generate high annual percentage changes. What is key is that the trend in spending changes mirrors closely the trend in oil prices in current dollars. For example, when oil prices peaked in 1981 and then headed lower until 1987, four of the six intervening years saw declines in industry spending. Each of the two years reporting positive gains – 1982 and 1984 – showed only 2% increases, or virtually no change. It is also noteworthy to point out that the consecutive years of 1985, 1986 and 1987 were all negative. That history was repeated in 2014, 2015 and 2016. The one difference between those two periods was that during the recent contraction, the annual declines increased each year. That was not the case in the 1980s. Exhibit 9. Capex Spending Cycles With Oil Prices

Source: EIA, PPHB

Another take on oil company spending is to consider the spending broken down by exploration, development and production in constant dollar terms between 1981 and 2009. In the 1981-1985 span, the declines in total spending were reflected initially in greater reductions for production and development, and only later cuts to development and exploration spending. In other words, the optimism that formed the backbone of the oil business coming out of the 1970s boom was that drilling for new resources and developing existing ones had to be the focus. If spending had to be cut, it would be concentrated in the production area.


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The key question is how is oil and gas company spending being financed – from cash flow, borrowings, asset sales, or the sale of additional stock in the company? In 1901, the discovery of Spindletop had caused oil prices in East Texas to drop to three-cents per barrel, wiping out many oil producers

Exhibit 10. How Oil Companies Spent Their Money

Source: EIA, PPHB

Spending is only one aspect of the energy equation. However, it its certainly critically important for the companies that support the oil and gas companies. The key question is how is oil and gas company spending being financed – from cash flow, borrowings, asset sales, or the sale of additional stock in the company? Throughout the modern era of the oil and gas industry, all of these various sources of cash were utilized by companies, depending on industry business conditions and credit market attractiveness. In the 1970s and 1980s, commercial banks played a much more significant role in financing the industry. Drilling funds and limited partnerships to finance oilfield service equipment were also very prevalent. The greater problem for producers during that period was the volatility of oil and gas prices. Volatility was most pronounced in the 1910-1930 era when wildcatting added new wells and fields with huge outputs that overwhelmed demand and collapsed oil prices. That price volatility spawned legislation in Texas in 1917 dealing with the preservation and conservation of all the state’s natural resources. It eventually led to legislation handing the regulatory power over natural resources to the Texas Railroad Commission (TRRC), a body created by the Texas legislature in 1890 to regulate the rates and operations of railroads, terminals, wharves and express companies in the state. In 1901, the discovery of Spindletop had caused oil prices in East Texas to drop to three-cents per barrel, wiping out many oil producers. In response, the TRRC’s responsibilities and powers over oil and gas were steadily increased. In 1917, pipelines were declared to be common carriers and subject to TRRC regulation. In 1920, natural gas production and sale was determined to be a utility and subject to TRRC regulation, and in 1927, the very first voluntary proration occurred among the operators of the Yates field. From


FEBRUARY 25, 2020

Fear of supply shortages, augmented by the use of oil as a political weapon by Middle East suppliers, drove up global oil prices to extraordinarily high levels The overriding conclusion from the chart is that the financial performance of the oil industry in the current downturn has been much worse than its performance in the 1980s and 1990s

that point forward, the use of proration of oil production to control pricing was employed to ensure that oil patch busts were limited and the pain of low oil prices shared amongst all producers in Texas. By 1970, the United States maxed out its oil production. Fear of supply shortages, augmented by the use of oil as a political weapon by Middle East suppliers, drove up global oil prices to extraordinarily high levels. These high levels were expected to be sustained because of the need for the oil industry and its support industry to be recapitalized to fund and execute more exploration and development to meet the surging oil demand growth of the 1960s. When oil prices collapsed by 70%-80% in the mid-1980s, the world’s producers and service companies were unprepared for such a price reversal. The oil price collapse precipitated the restructuring of the oil industry that lasted until nearly 2000. During this time, the oil industry’s profitability was on a downward trend. From its founding in 1974 until 2009, the Energy Information Administration (EIA) conducted an operational and financial analysis of a number of producers (FRS) who were representative of the entire oil industry. This analysis enabled the EIA to comment with some authority about trends within the producing industry. The M&A activity of the late 1990s and 2000s taxed the resources of the EIA, at the same time Wall Street analysts and other industry experts were performing more extensive investigation of industry trends, and on a more-timely basis. Thus, the EIA suspended the FRS analysis. About 2017, the EIA contracted with oil and gas data firm Evaluate Energy, to prepared the industry analysis, but because of the contractual nature of the arrangement, the actually data calculations are not made available to the public. The two data-sets are based on different groups of companies, although they contain many of the same companies. This makes the data from the latter analysis not fully comparable to the former, but we can still learn from the two analyses. In Exhibit 11 (next page), we plotted the return on equity for the FRS universe of oil companies for 1974-2009, and the Evaluate Energy group for 2000-2019 (Q3 is the latest data available) compared to the ROE for all manufacturers in the U.S. The most recent data series is plotted as dotted lines to distinguish the series when they overlapped in 2000-2009. While the numbers are different, the performances of the industry are similar. We have shown the current dollar oil price in the background to demonstrate how industry returns mirrored changing oil prices over time. The overriding conclusion from the chart is that the financial performance of the oil industry in the current downturn has been much worse than its performance in the 1980s and 1990s.


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The primary reason for the negative ROE in 2016 was the devastating impact the 2014-2016 oil price collapse had on the financially leveraged oil and gas producing sector

Exhibit 11. Current Downturn Performance A Disaster

Source: EIA, PPHB

The primary reason for the negative ROE in 2016 was the devastating impact the 2014-2016 oil price collapse had on the financially leveraged oil and gas producing sector. The integrated producers enjoyed better returns because their downstream operations benefited substantially from the low oil prices of the feedstocks used in their refineries and the healthy refined product prices available in the market. How devastating the oil price drop was for pure producing companies is best shown by Exhibit X. Exhibit 12. The Financial Toll Of Shale Investments

Source: EIA


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Besides low oil prices, the vast amounts of debt producers had used during the boom years of 2011-2014 to finance their operations sapped company earnings Issuance of debt securities by oil and other energy companies has far outpaced the substantial overall issuance by other sectors

The industry’s negative ROEs of 37%-40% for 2015 Q4 through 2016 Q2 reflected oil prices that fell into the low $30 per barrel range, down to an absolute low of $26.68 per barrel on January 20, 2016. Besides low oil prices, the vast amounts of debt producers had used during the boom years of 2011-2014 to finance their operations sapped company earnings. Debt has been a bugaboo limiting the industry’s financial recovery and is now setting it up for another critical financial viability test. While we cannot directly compare the current financial condition of the oil industry to that of the 1980s, debt has always been the downfall for the industry whenever oil and gas prices collapse. A 2015 research paper published by the Bank for International Settlements (BIS) examined the issue of debt and oil markets. Most research efforts examining this issue generally focus on it from the point of view of debt issued by oil producing countries, but this BIS paper looked at the company impact. Exhibit 13 contains two charts from that report – one showing total energy and corporate debt outstanding for 2002-2015 and the ratio of total debt to assets of the companies in the industry categorized by very large (2013 total assets greater than $25 billion), other U.S. producers, and national oil companies of countries in emerging markets (EME). Exhibit 13. The Buildup Of Oil Industry Debt

Source: BIS

As the BIS wrote:

“The greater willingness of investors to lend against oil reserves and revenue has enabled oil firms to borrow large amounts in a period when debt levels have increased more broadly due to easy monetary policy. Since 2008, companies in the oil sector have borrowed both from banks and in bond markets. Issuance of debt securities by oil and other energy companies has far outpaced the substantial overall issuance by other sectors (Graph 2, left-hand panel).


FEBRUARY 25, 2020

Oil and gas producers and oilfield service companies have $3 billion of scheduled debt maturities due in 2020, jumping to $20 billion in 2021 and further escalating to $41 billion and $59 billion due in 2022 and 2023, respectively There is also the potential that much of this lower-rated debt will not be refinanced because the borrower is forced to enter bankruptcy restructuring

Oil and gas companies’ bonds outstanding increased from $455 billion in 2006 to $1.4 trillion in 2014, a growth rate of 15% per annum. Energy companies have also borrowed heavily from banks. Syndicated loans to the oil and gas sector in 2014 amounted to an estimated $1.6 trillion, an annual increase of 13% from $600 billion in 2006.”

While we don’t have sufficient data to extend this analysis, we do know that energy industry borrowing continued in 2016-2019. The problem for the industry today is that we are at the point where, as the expression goes, “It’s time to pay the piper.” According to data from private equity and distressed debt investor Angelo Gordon in December 2019, as reported by The Wall Street Journal, oil and gas producers and oilfield service companies have $3 billion of scheduled debt maturities due in 2020, jumping to $20 billion in 2021 and further escalating to $41 billion and $59 billion due in 2022 and 2023, respectively. A more recent analysis by the credit group at Standard & Poor’s Global shows a greater amount of debt due this year, but similarly greater amounts due in 2021 and 2022. Thereafter, the maturity schedule seems to be relatively flat, but at a relatively high level. Exhibit 14. The Debt Maturity Schedule Of The Energy Industry

Source: S&P Global

This is what the outstanding debt maturity schedule looks like for the producers and oilfield service companies. (See next page.) The totals for each industry sector are broken down by credit ratings, highlighting which years will be the most challenging for lower-rated credit-quality companies. Of course, there is also the potential that much of this lower-rated debt will not be refinanced because the borrower is forced to enter bankruptcy restructuring.


FEBRUARY 25, 2020

There is also pressure building on E&P companies who are facing the upcoming commercial bank loan redeterminations, in which the banks tell their oil company customers how much money they can borrow against their oil and gas reserves

Exhibit 15. Debt Challenge For Producers

Source: S&P Global

Exhibit 16. Debt Challenge For OFS Companies

Source: S&P Global

The pressure on company financial health will grow the longer the oil market is depressed by the fear about the coronavirus impact on oil demand, and thus on global oil prices. There is also pressure building on E&P companies who are facing the upcoming commercial bank loan redeterminations, in which the banks tell their oil company customers how much money they can borrow against their oil and gas reserves. This determination, rumored to possibly result in borrowing amount reductions of up to 40% of existing credit line amounts, may create serious hardships for many small E&P companies. As they will have access to less additional capital, and may even be forced to repay current debt ahead of schedule, drilling and completion activity will suffer, placing greater strain on the finances of the oilfield service companies. We can see what has happened to debt defaults in the past when oil prices fell – they surged in 2015 and 2016. If, as some analysts speculate, oil prices fall into the low $40s or below due to the coronavirus impact on demand, we would expect a subsequent surge in defaults and bankruptcies.


FEBRUARY 25, 2020

A brief window in the high-yield debt market opened for energy companies in January We are also likely to see more below-par exchanges of debt as a way for energy companies to deleverage, while containing their interest expense

Exhibit 17. Oil Prices Trigger Debt Defaults

Source: S&P Global

Whenever possible, energy companies are attempting to take advantage of capital markets to refinance some or all of their near-term debt maturities. A brief window in the high-yield debt market opened for energy companies in January. We see that the energy industry raised nearly as much capital then as it did during all of 2019. Exhibit 18. Debt Reprieves Are Opportunistic

Source: S&P Global

High-yield debt is expensive. However, given the alternative of being shut out of credit markets and/or not having sufficient cash to operate, it is cheap money. To appreciate the significance of what is happening, some of this high-yield debt was senior unsecured guaranteed notes that ranked in front of legacy senior unsecured notes without guarantees. This means that the standing of certain debt holders within the credit structure of energy firms has been altered meaningfully, especially if the company eventually is forced to enter bankruptcy. We are also likely to see more below-par exchanges of debt as a way for energy companies to deleverage, while containing their interest expense. Credit rating agencies may view some of these debt swaps as selective defaults, despite the benefits from the transaction. This is because investors will not receive the promised


FEBRUARY 25, 2020

The current pricing of debt for companies and credit ratings within the energy sector is reflective of an industry rapidly approaching “Hail Mary” status Bernard Looney, the new CEO of BP plc, says that his company’s E&P business will be smaller in the future than now, although he says it will not disappear for decades

terms of the debt, having to accept an offer less than the original promise. For many debt holders, the alternatives of bankruptcy and/or restructurings will cost them less than accepting a haircut on their debt while hoping for a recovery. The current pricing of debt for companies and credit ratings within the energy sector is reflective of an industry rapidly approaching “Hail Mary” status. Exhibit 19. Debt Markets Signal Problems For Energy

Source: S&P Global

As we await greater clarity about the severity and duration of the coronavirus’ impact on oil demand and oil prices, we reflect on the state of the global energy business. Not only is there more oil available than needed at the moment, the future growth of oil demand is under assault from environmentalists, politicians, regulators, and investors. A recent study by the World Energy Council predicts oil demand will peak between now and 2025. Even Bernard Looney, the new CEO of BP plc (BP-NYSE), says that his company’s E&P business will be smaller in the future than now, although he says it will not disappear for decades. Reduced earnings from E&P are anticipated to be offset by greater earnings from renewables investments. An oil industry in 2014 that saw demand of 100 million barrels per day growing at 1% a year and dealing with a 7%-8% annual production decline rate was comfortable that it had a bright future. That view of the oil industry’s future in 2014 looks considerably different 5-years into a downturn and facing an uncertain future. With limited capital, the industry is being forced to re-orient its operations to focus on its best prospects, while dumping unprofitable


FEBRUARY 25, 2020

We are not “certain” that the energy business in 10 years will look “completely” different

assets and business-lines. With limited access to capital markets, and certainly access to cheap financing, capital discipline is being forced on company managers. Exhibit 20. Long-Term Challenge For Oil & Gas

Source: BDO

A recent study of the future energy industry conducted by the energy practice of BDO and based on detailed survey results of 100 oil and gas and power generation CFOs, was titled “Energy: Energy Goes Green.” The study was focused on the climate change pressures on energy and power companies and how CFOs are preparing their companies for the future world in which they will be forced to operate. The concluding chart in the report showed how the CFOs ranked the most dominant alternative energy sources by 2023. Solar was the choice of both sectors, with either hydroelectric or wind being the second most important source. The concluding statement in the report was: “Time will tell who wins the renewables race, but one thing is certain: the energy industry in 10 years will look completely different than it does today, and our world will be better off for it.” In the rush to get on the right side of “politically correct,” many people have a tendency to make extreme statements. We are not “certain” that the energy business in 10 years will look “completely” different. Are we confident that the industry will be significantly changed? Sure. Completely different? Not so sure. Virtually no one would have projected the energy world of today when we turned the page on the 20th century, two decades ago. Who would have thought the U.S. would be the world’s largest oil producer, and a leading oil and natural gas exporter, to the point that we have disrupted global commodity markets? OPEC was seen to have an iron-grip on world oil markets, dictating the global price. Instead, the organization is fractured and having to enlist Russia to demonstrate any semblance of market power. Renewables and electric vehicles were not that far removed from science fiction tales, but they are now on our roads and carving out market niches that


FEBRUARY 25, 2020

What we are confident about is that the global energy industry has entered another era of significant restructuring We are confident this industry will deliver a better world for mankind in the future

will growth with favorable social and political backing, regardless of whether they make economic or environmental sense. Who would have believed the global energy business would be closer to BP CEO Lord Brown’s vision of the future than that of ExxonMobil’s Lee Raymond? What we are confident about is that the global energy industry has entered another era of significant restructuring. How long it will take, and how violent it will be, are unknowns. The industry will look different in 10 years, 20 years, 30 years, and longer, but that would be in keeping with its history. This is an industry that has changed significantly many times since it began in the mid-1850s. What many people overlook about the oil and gas and oilfield service industries is that they contain the greatest collection of scientific, engineering and technical talent, possessing a greater understanding of how energy works - from the molecules to their conversion into power – than any other industry in the world. We are confident this industry will deliver a better world for mankind in the future. A world with fewer people living in poverty, and everyone living in a cleaner environment. The industry will work toward those twin goals, while also earning profits for its shareholders and delivering positive outcomes for all its stakeholders. The oil and gas business may not be as large, but the energy industry will be larger. The journey won’t be smooth, but it will occur despite the turmoil the industry sectors will undergo during the next few years as they restructure from their 2000-2020 configuration. We look forward to tracking and commenting on its progress.

Global LNG Catches The Virus, But Maybe Has Bigger Issues Every discussion about the future of world economies and commodity markets today is influenced by what one believes to be the fallout from the coronavirus

One cannot help but think that every discussion about the future of world economies and commodity markets today is influenced by what one believes to be the fallout from the coronavirus (COVID-19). This virus that emerged from Wuhan, China is slowing spreading around the world. The uniqueness of virus, given its lengthy period when it can be transmitted, as well as not requiring person-to-person transfer, has created a serious health scare around the world. It is being called a pandemic and analysts are scrambling to assess its potential ramifications for world economic activity. Exhibit 21. The Societal Cost Of COVID-19

Source: Pharmaceutical-Technology.com

Coronavirus Statistics (Updated as of Feb. 18, 2020) Counts

Countries with Confirmed Cases 27

Global Confirmed Cases 73,332

Global Reported Deaths 1,873

Global Recoveries 12,692


FEBRUARY 25, 2020

In an attempt to limit the spread of the virus, substantial parts of China have been locked down in quarantine, meaning people could not travel or even leave their homes Additionally, the disruptions are upsetting company supply chains, further impeding operations, not just in China but around the world With long distance buses only allowed to operate at 50% of capacity to help prevent the risks of viral transmission, it will take a long time to get everyone relocated

China has been criticized for its lack of candor about when the disease was first discovered and what steps the government took to control its rapid spread. As a result, there is much skepticism about the validity of the counts of people infected with the virus and the reported death toll. In an attempt to limit the spread of the virus, substantial parts of China have been locked down in quarantine, meaning people could not travel or even leave their homes, except that one family member per day was allowed to go shopping for food and everyday necessities. Virtually all activities were shut down. Many were already scheduled to be shut for a week in conjunction with the national celebration of the Chinese New Year. Thus, the timing of virus outbreak came at an opportune time for limiting its economic impact. What did happen, however, was that many people who would normally have gone to visit relatives or to take vacations abroad were prohibited from traveling. This severely cut air traffic into and out of China and neighboring Southeast Asia countries, impacting aviation fuel consumption. The Chinese Lunar celebration was extended for an additional week, but now life is supposedly returning to some form of normalcy. However, due to the extended manufacturing disruptions and the continuing travel restrictions, many workers have been unable to return to work, limiting output. Additionally, the disruptions are upsetting company supply chains, further impeding operations, not just in China but around the world. Based on data reported by Bloomberg Economics, Chinese plants were running at about 40%-50% of capacity last week. Time magazine’s web site reported that as of February 18th, about the same number of trips by planes, trains, automobiles and boats were taken in the run up to the Lunar New Year this year compared to last year, but the falloff since the first day of the new year (January 25th) has been sharp. On average, only about 20% as many trips are being taken each day, suggesting that millions of people still haven’t traveled back to work. With long distance buses only allowed to operate at 50% of capacity to help prevent the risks of viral transmission, it will take a long time to get everyone relocated. These travel disruptions are further documented by data showing the number of passengers on China’s public transportation system before and after the Lunar New Year (Exhibit 22, next page). Demand for electricity in China remains low, based on recent statistics, suggesting that much of the manufacturing sector has yet to resume work. Satellite measurements of nitrogen dioxide emissions in the week following the holiday were 36% below where they were at the same point a year earlier. According to the researchers, the drop is due to 25%-50% reductions in activities such as oil refining, coal-fired power generation, and steel production.


FEBRUARY 25, 2020

While all the focus is on the virus’ impact on Chinese and Asian oil demand, the natural gas market is also suffering With LNG production capacity growing, structural changes in the global gas market are underway, ensuring that it will become much more competitive

Exhibit 22. The Energy Cost Of COVID-19 Virus

Source: Our Finite World

The New York Times conducted an analysis of Chinese national and local government announcements about actions to contain the virus. As of February 18th, it says that 150 million people, over 10% of the country’s population, face restrictions about how often they can leave their homes. That is a subset of the more than 760 million people whose neighborhoods and villages have imposed restrictions on people’s movements. All of these restrictions will have an impact on China’s energy consumption. By just how much remains unknown, as does the duration of the disruption. While all the focus is on the virus’ impact on Chinese and Asian oil demand, the natural gas market is also suffering. However, it may be suffering due to factors extending beyond the virus. Last December we wrote about changes underway in the global natural gas market, especially as they related to the growth in liquefied natural gas (LNG) export capacity. We highlighted how this expansion, reflected in the number of new LNG export terminals being approved and constructed in the U.S., as well as LNG expansion efforts in both Qatar and Australia, currently the world’s two largest gas exporters, was likely to run up against the opening of new gas pipelines connecting Russia and China. The global gas market is benefitting from new gas consuming nations. But it is equally true that there are now more gas exporting nations. Many of these new suppliers are smaller than the major producers of Qatar, Australia, the United States and Malaysia, but the additional supply is hurting the overall market. With LNG production capacity growing, structural changes in the global gas market are underway, ensuring that it will become much more competitive. In fact, in 2018, 31% of LNG volumes traded were done in the spot market, a market segment that barely existed a few years earlier. The ending of destination restrictions for LNG exports


FEBRUARY 25, 2020

The major traditional Asian LNG buyers – Japan and South Korea – are seeing their demand flatline With a warm winter in the U.S. and Asia, and additional gas export capacity coming on-line, global LNG prices have cratered Current spot prices virtually guarantee that some of the Gulf Coast LNG exporters cannot earn a profit on a full-cost basis

and the ability of more customers to take wider quality ranges of LNG have added to the competitiveness of the market. Lastly, the major traditional Asian LNG buyers – Japan and South Korea – are seeing their demand flatline. As gas decontrol in Japan has occurred, and the growth of cheaper coal-fired power plants grows as an offset to the loss of the nation’s nuclear power output, a new business model is evolving. This model is based on major gas consumers aggregating small gas consumer supplies and then re-exporting the surplus supply to attractive regional gas markets as a way of generating income to reduce gas supply bills. At the conclusion of our December 2019 article, we wrote:

“As we look at what has happened to Asian LNG prices – they are below $6 per million BTU versus over $10 a year earlier – we are left wondering if low natural gas prices will prevail globally in the future? In other words, is the United States exporting its low natural gas pricing environment globally? If so, then the world’s gas industry should be bracing for changes it has yet to consider.”

Little did we realize how prescient that view would turn out to be. At the time we wrote the article, we were looking at Asian LNG prices at around the $6-per-million-BTU level. Now, with a warm winter in the U.S. and Asia, and additional gas export capacity coming on-line, global LNG prices have cratered, forcing companies to make decisions about their long-term business strategies. For some, they are counting on new LNG consumers, such as Vietnam, the Philippines, Bangladesh, and African countries such as Morocco and Ghana, to help pick up some of the slack. The problem is that besides new LNG consumers, we are seeing new LNG exporters, in addition to new land and underwater gas pipelines, either in startup mode, under construction or planned, which are adding to global gas supply capacity. We are rapidly transitioning into the gas world that some major players have long prayed for. The new market dynamics, however, are creating challenges for a number of foreign utilities. For some, the decision is to exit the LNG trading business, or in the case of at least one, not entering it. The key question for many LNG producers facing current spot prices in the sub-$3 per million BTU range is whether they need to cut back their operations. Current spot prices virtually guarantee that some of the Gulf Coast LNG exporters cannot earn a profit on a full-cost basis. Therefore, expectations are growing that this summer will see many export terminals undergoing repairs and maintenance for longer periods of time to avoid having to ship money-losing cargos.


FEBRUARY 25, 2020

For LNG buyers, this may be an opportune time to enter negotiations with owners of new export terminals for long-term contracts If an early spring does arrive, weaker gas withdrawals will depress natural gas prices for longer than the summer months, unless supply falls off

Exhibit 23. A Tale Of Weak Global LNG Market

Source: Bluegold Research

For LNG buyers, this may be an opportune time to enter negotiations with owners of new export terminals for long-term contracts. In a market facing a glut of LNG supply, new terminal owners may be willing to sign long-term contracts to secure a known-income stream before having to compete in the depressed spot LNG market. It is likely these long-term contracts will be at favorable cost points for the new LNG buyers. The greater challenge for the U.S. natural gas market is what will a weaker LNG exporting market this summer, and possibly longer, mean for storage and wellhead gas prices? Natural gas prices are trading below $2 per thousand cubic feet, having fallen to as low as $1.77, the lowest gas prices seen in the month of February for over two decades. Until the growth in associated natural gas coming from shale oil wells stops, gas prices will be at the whims of weather forecasts and weekly gas storage withdrawal volumes. If an early spring does arrive, weaker gas withdrawals will depress natural gas prices for longer than the summer months, unless supply falls off more than anticipated and/or we experience a blistering hot summer jacking up air conditioning loads. Absent those conditions, look for natural gas prices to remain depressed, not only in the United States but globally.

Climate Change, Green Energy And Meeting Energy Needs

The United Kingdom has been buffeted by two strong winter storms – not an unusual event. But these storms have provided the media with a club to bludgeon the heads of residents that climate change is


FEBRUARY 25, 2020

The wildfires, prevalent in winter (summer time down under), were raging in the eastern part of the continent where the population is the densest This effort is in keeping with the center’s motto: In a world with limited budgets and attention spans, we need to find effective ways to do the most good for the most people The trend in the amount of acreage burned every year in Australia has been in a downward trend since 1900

making their winter weather worse and the solution necessitates a radical shift in powering the country. The media “club” had been employed earlier this winter, even without bad weather, as the pictures of wildfires in Australia provided “proof” of climate change’s impact down under. There was no denying the wildfire pictures and their aftermath, especially given the sad photos of two of the country’s leading figures, koalas and kangaroos, produced sympathy for the suffering locals. The wildfires, prevalent in winter (summer time down under), were raging in the eastern part of the continent where the population is the densest. The political uproar over the vacationing prime minister was intense. He was pictured as being insensitive and incompetent, because he has not embraced climate change, which is pictured as causing havoc across Australia. The prime minister is actually a realist about climate change and its relationship to wildfires. The Copenhagen Consensus Center think-tank founder and current head, Bjørn Lomborg, authored a column for the center’s newsletter, which became an op-ed in The Australian about the nation’s recent wildfires. His column was an attempt to put the devastation into a proper context. Whether he succeeded or not we don’t know. Mr. Lomborg is known for his critical takes on many of the positions of people pushing the climate change narrative, not that he dismisses the need for society to make adjustments in how it lives to better protect the environment. Rather he believes one needs to look at the recommended actions in light of the costs they entail. His center sponsors a conference every four years of some of the world’s leading economists who examine and prioritize potential solutions to global issues by employing cost-benefit analysis. This effort is in keeping with the center’s motto: In a world with limited budgets and attention spans, we need to find effective ways to do the most good for the most people. Cost-benefit analyses are not controversial, and actually are the appropriate way to consider most major questions that impact the economy, unless you happen to be an activist or politician with an agenda. Mr. Lomborg, pointed out that the trend in the amount of acreage burned every year in Australia has been in a downward trend since 1900, even with the advent of satellite surveillance, which allows for better monitoring of the entire continent. As a chart accompanying his column showed, since the late 1990s and the age of satellite surveillance, the percentage of acreage burned has been in an even sharper downtrend than exhibited earlier, with the exception of two extraordinarily severe wildfire seasons in 2000 and 2008. The amount of acreage burned in the latest wildfire season is in line with the record lows of earlier years.


FEBRUARY 25, 2020

These centers are where the preponderance of the nation’s media is located, making it easier for the wildfire stories to overwhelm all other news coverage Research needs to examine the possible relationship between vibrations in the water created by rotating wind turbine blades and the loss of hearing of these aquatic mammals

A partial explanation for the distorted view that all of Australia was in flames was related to the fact the fires happened near population centers. In addition, these centers are where the preponderance of the nation’s media is located, making it easier for the wildfire stories to overwhelm all other news coverage. That is not to denigrate the severity of the fires or the suffering of humans and wildlife. However, who wants to go cover a wildfire in the central (largely uninhabited) region of the continent? Of what news value will that story be? Exhibit 24. How Australia’s Burnt Acreage Has Fallen

Source: Copenhagen Consensus Center

In the United Kingdom, the green energy push remains strong despite problems with costs and power intermittency. The new government has just announced it plans to ban the sale of new gasoline, diesel and hybrid vehicles beginning in 2035, five years earlier than originally planned. Who knows what the cost of this edict will be? Politicians continue pushing solar and wind power, especially offshore wind. This is despite the sudden rash of whales, dolphins and porpoises beaching themselves and dying. It turns out these aquatic mammals were deaf. Their sensitive hearing is critical to their survival as it guides their travels and feeding. These beachings have all occurred near offshore wind turbines, suggesting research needs to examine the possible relationship between vibrations in the water created by rotating wind turbine blades and the loss of hearing of these aquatic mammals.


FEBRUARY 25, 2020

These fees are projected to increase UK residents’ electricity bills by 7% Late January was the latest example of the fallacy of relying on solar and wind to entirely power the country’s electricity grid

An even bigger issue confronting British citizens is the intermittency of solar and wind power, and the cost to have their generators not supply electricity when demand in insufficient. The environmental levies (fees the public pays) are projected by the British government in its “October 2018 Economic and fiscal outlook” to increase by £2.0 ($2.6) billion by 2023-24. That total will grow by an additional £1.4 ($1.8) billion in subsidies paid to the operators of the Hinkley Point nuclear plant when it becomes fully operational sometime after 2025. These fees are projected to increase UK residents’ electricity bills by 7%. Exhibit 25. How Environmental Fees Are Impacting Citizens

Source: Paul Homewood

The problem is that these fees do nothing to solve electricity’s intermittency issue, at least until Hinkley Point is operational. Late January was the latest example of the fallacy of relying on solar and wind to entirely power the country’s electricity grid. According to data from GridWatch.co.uk, as of February 19th, charts show the hourly wind power production, along with data for the month of February and 2020 year-to-date in both gigawatts (GW) and percentage of capacity. The problem of wind intermittency arose during a four-day span shown in the 19 Jan to 26 Jan block on the year-to-date chart in Exhibit 26 on the next page. This was when a high-pressure weather feature settled over the UK, dropping wind speeds dramatically.


FEBRUARY 25, 2020

During that four-day span of high pressure, wind output averaged only 2.5 gigawatts (GW), or 6.5% of the 38.7GW of total demand The 5,000 batteries would cost an estimated £625 ($811) million, and would only provide backup power for four days

Exhibit 26. UK Wind Energy Output In Gigawatts

Source: GridWatch.co.uk

Exhibit 27. UK Wind Power As Percent Of Total

Source: GridWatch.co.uk

According to UK analyst Paul Homewood, during that four-day span of high pressure, wind output averaged only 2.5 gigawatts (GW), or 6.5% of the 38.7GW of total demand. For more than a quarter of the time, wind provided less than 2GW of power. Coal provided 2.9GW and natural gas 21.1GW of the nation’s power during that period. Mr. Homewood says that if one adjusts for embedded wind generation not included in the grid figures, which adds about 30% to the total, wind power was still only running at about 13% of total capacity. He went on to note that if you use average wind utilization of 35%, there was a shortfall in power generation of 500 gigawatt-hours over the four days. That would necessitate using 5,000 Tesla 100MW (megawatt) batteries to supply the missing power. Those batteries are similar to ones installed in Australia in 2018 at an estimated cost of £125 ($162) million. The 5,000 batteries would cost an estimated £625 ($811) million, and would only provide backup power for four days. As Mr. Homewood also commented, this recent spell of high pressure was of a relatively short duration, and not as windless as


FEBRUARY 25, 2020

Keeping thumbs off the scales when energy decisions are made will be a constant struggle, but it is critically important if we really want to take affordable and permanent steps to a decarbonized world in the future

many episodes are. At the present time the UK has 23.9GW of wind capacity, an amount some environmentalists would like to see quadrupled or more, meaning an even greater battery-backup investment. Green energy is good, until the costs are considered. This is where Mr. Lomborg’s focus on cost-benefit analysis comes into play. Failure to consider all the relevant costs during the energy selection process often leads to ‘feel-good’ choices that ultimately cost everyone more than the alternatives, such as stuffing landfills with unrecyclable, used wind-turbine blades. Keeping thumbs off the scales when energy decisions are made will be a constant struggle, but it is critically important if we really want to take affordable and permanent steps to a decarbonized world in the future.

Correcting Some Oil Patch History We said that Joy Manufacturing Company was the suiter, but our friend corrected us to say it was Petrolane Inc. that was after Gray Tool The battle led directly to an early Securities and Exchange Commission insider trading case

A former co-worker and long-time reader of the Musings emailed us after Part 8 of our “Rhyme of Oil History” articles appeared to correct one of our historical notes. We had discussed the formation of Vetco Gray, a joint venture formed by Combustion Engineering (CE) and Hughes Tool Company shortly before Hughes Tool was acquired by Baker International. Gray Tool was owned by CE, who purchased the company as a white knight during a take-over battle. We said that Joy Manufacturing Company was the suiter, but our friend corrected us to say it was Petrolane Inc. that was after Gray Tool. That information did ring a bell for us. The outcome of our email exchange provided us with substantial additional color on the takeover battle, and the revelation that the battle led directly to an early Securities and Exchange Commission insider trading case, the details of which we won’t get into. The email exchange also prompted us to reconnect with an old friend who worked at Petrolane during the 1980s, but he was unable to recall any details since he was running a division of the company and not at corporate and involved in the take-over effort. Our mistake actually generated additional historical knowledge for us, as well as providing the impetus to reconnect with old friends, for which we are thankful.

Contact PPHB: 1900 St. James Place, Suite 125 Houston, Texas 77056 Main Tel: (713) 621-8100 Main Fax: (713) 621-8166 www.pphb.com

PPHB is an independent investment banking firm providing financial advisory services, including merger and acquisition and capital raising assistance, exclusively to clients in the energy service industry.

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