- The Volatile Renewables Energy Market Of New England
- V-Shaped Oil Price Recovery To Drive More Or Less Activity?
- Rebuilding Economies After Covid-19 And Fuel Choices
- Offshore Oil Service Sector Being Pressured To Restructure
Musings From the Oil Patch
June 16, 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 oilfield service companies. The newsletter currently anticipates a semi-monthly publishing schedule, but periodically the event and news flow may dictate a more frequent schedule. As always, I welcome your comments and observations. Allen Brooks
The Volatile Renewables Energy Market Of New England (Top)
Just as leaders in many European countries are pushing for financial stimulus to restart their economies, they think green energy investments should play a key role. Similar moves are underway in New England. A recent article discussed how the Attorney General of Massachusetts has asked the state’s Department of Public Utilities (DPU) to investigate the plans of utility companies to transition away from the use of natural gas to power and heat the homes in the state in a decarbonized world. This shift is envisioned by the state’s commitment to net zero carbon emissions by 2050, which became policy last January. The new policy was immediately criticized by environmentalists, who judged it to be inadequate for solving the state’s climate change problem.
According to 2016 data from the Massachusetts Comprehensive Energy Plan (CEP), prepared by the state’s Department of Energy Resources (DOER), natural gas plays an important role in Massachusetts’ fuel mix for home heating, transportation and electricity markets. Natural gas supplies 68% of heating and 41% of electric generation. Fuel oil (24%) is also important for home heating, but clearly much more significant in the transportation sector. Nuclear power (26%) and net imports (17%), which is hydroelectric power coming from Canada, are key power market components.
Exhibit 1 Natural Gas Is Important Fuel In Massachusetts
Source: DOER
Important in the debate over clean energy is Massachusetts’ carbon emissions and their source. As the CEP shows, between 1990 and 2015, emissions from the power generation sector have declined noticeably, while there has been only a modest reduction in the heating sector. Both reductions came from increased use of natural gas to displace fuel oil for heating and residual oil in power generation.
Exhibit 2. Carbon Emissions Are Falling In Power Sector
Source: DOER
The author of the article suggests the shift away from natural gas will undercut the business models of regulated gas distribution companies. Could this cause gas distribution companies to have stranded assets? That possibility assumes that natural gas use ends completely, and that distributors are unable to replace gas with another fuel, such as hydrogen, or to add other fuel distribution services to their portfolios.
A problem the state has in meeting its net zero emissions goal is the cancellation of many clean energy projects. A plan to import significant hydroelectric power from Canada has been rejected by New Hampshire, forcing Massachusetts to turn to Maine, but it is having problems negotiating a deal. Another issue is that many clean energy projects are being cancelled due to the regulatory process and/or poor economics.
It is interesting to see the projected New England power market at the end of this decade. Exhibit 3 (next page) shows the latest supply report from ISO-New England, the operator of the region’s power grid. Despite the focus on ending natural gas use in the region, the fuel is projected to decline by only 0.6 megawatts (MW) of generating capacity, a 3.8% reduction. At the same point, wind generating capacity is projected to slightly exceed that of natural gas in 2029. We caution making too much of this outcome, since the forecast is based on nameplate generating capacity of the fuels and not their actual output. Wind turbines are usually assumed to deliver 40% of nameplate capacity in output over time. Usually, the output performance falls below that target, and there is always the issue of when the energy will arrive.
Exhibit 3. A Brighter Natural Gas Future Than Imagined
Source: DOER
The article makes the point that the future of Massachusetts power, in order to achieve net zero emissions, will require moving as much demand as possible to electricity, which is assumed to be generated all from renewables. However, there are no reliable studies showing how a state economy, let alone the entire U.S. economy, can be powered exclusively with renewables. The various studies, attempting to demonstrate 100% renewable power, also show that reaching that elusive goal will be hugely expensive and runs the risk of creating a less stable electricity grid, i.e., more frequent brownouts and blackouts.
As part of its plan to grow renewables use in the Massachusetts power market, the state has established a Clean Peak Standard, which creates credits for clean energy delivered during time windows identified as peak hours for a given season. Utilities in the state must obtain clean peak credits equal to a percentage of total electricity delivered in each year, starting at 1.5% in 2020 and growing annually. The goal is to create a price signal to shift clean power supply to those hours it’s most valuable for the grid. Since renewables are not dispatchable, this creates an opportunity for energy storage technologies, such as batteries, to deliver power during these windows of greatest value. According to DOER Commissioner Patrick Woodcock stated, “This is a core centerpiece of our efforts to incorporate storage into our clean energy policies. It provides that signal to chase that real-time peak and chase the seasonal peaks that really contribute to high costs for ratepayers.”
After incurring short-term costs to get the program up and running, the state expects the Clean Peak policy will save $400 million over the coming decade. The law requires ratepayer costs to be capped at $0.005 per kilowatt-hour (kWh). National Grid filed comments with DOER, arguing that while the cap "may appear to be a small amount, in fact, it could be quite substantial." The company foresees the cost ramping up over the decade to adding an additional $40 per year to consumer average bills.
It is interesting to note where New England utilities are relative to clean energy. We have reproduced the power mix data from National Grid for its standard offer contract for customers in Massachusetts and Rhode Island. In Massachusetts, solar and wind account for 15.0% of the power, about half the amount that comes from natural gas, and four percentage points below nuclear energy. In Rhode Island, the two renewable power sources total 8.5% of National Grid’s power supply, but only a quarter of the power that comes from natural gas and one-third from nuclear.
Exhibit 4. Renewables Trail Fossil Fuels By Wide Margin
Source: National Grid, PPHB
The greatest challenge for New England power markets is the winter when cold weather increases the demand for natural gas for home heating. Due to cold weather, renewables are of little value during the night when the coldest temperatures are experienced. Gas is diverted from electric generators, or utilities must pay very high prices for imported LNG or switch to fuel oil and standby coal plants. That impact is noted in the amount of coal and oil use in National Grid’s fuel supply data.
The Massachusetts CEP showed data from ISO-New England about daily fuel supply during the severe winter of 2017-2018. As seen, during the coldest days, oil became a significant fuel source when natural gas supply was limited. The yellow line shows how the daily average real-time price for power spiked at the same time low-cost natural gas supply shrank and more expensive fuel sources were needed. This is a structural issue for the region, created primarily by the failure to expand natural gas pipelines to deliver more supply. This restriction has been caused primarily by the objections of liberal governors in New York, New Jersey and Connecticut who have blocked pipeline expansions and new pipeline projects.
Exhibit 5. Oil Becomes Big Factor In Cold Weather
Source: DOER
Two charts from the CEP report show the fate of residential electricity consumers in Massachusetts. First, we see that Massachusetts’ electricity price relative to the other U.S. states and the national average in 2017 is at the upper end of the price range. Massachusetts ranks slightly higher than New York, and on a par with California. Amazingly, New Hampshire, Rhode Island and Connecticut have more expensive electricity. The most expensive power in America is found in Alaska and Hawaii.
Exhibit 6. Massachusetts Has Expensive Electricity
Source: DOER
The second chart shows DOER’s modeling of the cost of electricity under various scenarios, and compared them to the forecast for cost of all New England power, as well as for the entire United States. What the results show is how the cost for Massachusetts power declines slightly from 2021 to 2024, but then begins climbing regardless of the scenario. The pitch DOER makes is that by 2030, the state’s power prices will be below the New England estimate power price. The politicians in most New England states are committed to promoting clean energy, almost at any cost. That commitment will keep Massachusetts and New England power prices well above those of the United States.
Exhibit 7. Massachusetts Power Cost Is Heading Higher
Source: DOER
A quick update on the electricity market in Rhode Island shows what happens to renewables when subsidies decline. We have discussed our decision to install solar power on the roof of our summer home. We estimated we could achieve a 6-year after-tax, cash flow return of our investment, with the remaining nine years of our power contract providing profits. Based on the performance of the solar panels, we are now on a 5.5-year payback rate. Our installation was done as part of a plan to promote solar sponsored by our town. It struck a deal with an installer to offer homeowners a discount on the solar panel installation cost depending upon the number of projects completed. We were fortunate the number of projects exceeded the top end of the discount range, so we receive a 20% installation cost discount. We also were eligible for the 30% renewable energy investment tax credit.
Then there was the power contract with National Grid. When it began the solar plan in 2015, the company offered to buy residential solar electricity at $0.41/kWh. The next year, the offered price declined to $0.37/kWh. In 2017, the year of our installation, National Grid offered to buy solar power for $0.3475/kWh for 15 years with guaranteed renewal, although the price will be determined at the time of renewal. We are currently paying $0.196/kWh for our National Grid power. Rhode Island doesn’t allow net metering – using the solar power ourselves while remaining eligible to draw power from National Grid. The payment arrangements call for National Grid to credit us for the power we sell against the power we purchase, other than for select administrative fees, meaning our monthly electric bills run between $11-$23 per month. The balance of our sale revenues is paid to us monthly.
Recently, we talked with the chief electrician for our solar installer. He told us that this year, National Grid is only offering to buy power at $0.20/kWh, making it virtually worthless to install new solar projects. We asked what had happened to their business? He said they are very busy! While not installing many solar projects, they continue installing backup generators, another line of business they entered last year. Now they are extremely busy installing batteries, a new service line (more on that in a minute). He also told us they are performing maintenance work on systems they had not installed. At the height of the solar euphoria, when we installed our system, there were well over 100 installers operating in Rhode Island. With the collapse of the solar power price, there are now only six installers left in the state! There go some of those green energy jobs lost in the pandemic, but they are gone due to the decline in the value of the subsidy, i.e., the price National Grid was willing to pay to meet its clean energy requirement to operate in the state.
After hearing more about batteries, we are examining whether to install one. These batteries are contracted to National Grid, who can draw power from it whenever it believes its system will reach a critical point during heat waves. For that right, the company pays a flat rate, which we understand repays the investment in five years. For us, though, there are additional benefits with economic rewards. With a battery, we can continue operating our solar system whenever we lose power to the house and our backup generator powers up, enabling us to continue selling solar power to National Grid. Currently, when we lose power, the generator’s power does not allow us to continue to sell our solar power to National Grid. As we understand it, (and we haven’t met with the company about the details), this will further reduce the payback time for our solar system, as we will generate incremental revenue during power outages. Or that extra revenue could be seen as a reduction in the cost of the battery. If all of this is correct, in a few years, our house could actually be earning a profit from our utilities.
The Massachusetts and Rhode Island developments point to the impact that government policy has on utility markets. We have no idea how all these various governmental actions will work out. At the moment, there have been profit opportunities. We don’t put much faith in 2050 aspirational goals.
V-Shaped Oil Price Recovery To Drive More Or Less Activity? (Top)
When the energy world was coming apart in March and April, the prospect of any recovery, let alone a V-shaped one, seemed well in the future. Expectations were that demand destruction would be at a maximum in April, which was supported by the decline of oil futures prices into negative territory. Never before had the oil market experienced such an episode, although in select energy markets producers have experienced negative prices, especially wind turbine operators during nighttime hours. At those times, excess power supply often causes prices to drop into negative territory. In those cases, wind generators are supported by government subsidies.
Recent oil market data seems to support the view that oil demand destruction was less than forecasters’ worst-case scenarios. Everyone expects that May’s data will show meaningful demand improvement, as well as a smaller inventory build, as economies began opening and oil production was cut. Traffic data supports that view. The challenge in forecasting oil demand near-term is the uneven economic reopening, as well as the fallout from the protests and riots provoked by the tragic death of George Floyd in Minneapolis. But there is another overhanging concern about the future direction for oil demand, which is what is happening in China.
China was the site of the initial outbreak of Covid-19, which forced the government to lockdown Wuhan, the site of the infection, and then much of its country in an attempt to control the spread of the virus. By being the first to experience the virus, the first to lock down its economy, and the first to unlock its economy, China’s energy data has been the beacon forecasters are watching for guidance about the pace of the world’s energy industry recovery. While initial data showed a sharp upturn in economic activity, disruptions in company supply chains have limited the upturn in manufacturing output and power consumption growth. Fear of contracting the virus has led to an increase in personal driving to work, rather than relying on mass transit in major cities. Thus, vehicle congestion quickly returned to pre-virus levels on workdays. However, traffic on weekends has not returned to earlier levels, as citizens are reluctant to venture out. Now, we are hearing that weekday traffic and energy consumption has stopped rising, and may, in fact, be falling slightly. We suspect this weakness may be tied to the supply-chain disruptions that are keeping manufacturing plants from running a high utilization, likely meaning fewer workers are needed. These disruptions are probably more localized, rather than nationwide.
Could the same pattern in driving and overall energy consumption unfold in the U.S.? It has to be considered a high probability once most of the economy is reopened. Therefore, we expect to see a continuation in weekly energy consumption growth, before the rate of increase slows and potentially moves sideways. While the oil industry and the energy market can tolerate such a pattern, what will always be lurking in the background is the possibility that a fall outbreak of Covid-19 could send the economy back into restricted economic activity and a fall in energy demand. There is probably little risk of total shutdowns of states, but shutdowns of cities and regions that suffer a second virus outbreak have to be considered a realistic possibility. If that happens, it will snuff out prospects for a robust energy demand recovery.
A favorable economic recovery outlook has underpinned the dramatic recovery in oil prices. The Energy Information Administration (EIA) had an interesting chart on its web site. The chart showed how Brent oil prices have largely traded in a flat pattern from 2017 to early 2020. The range of prices was from the mid-$40s in spring 2017 to about $85 per barrel (/bbl) in the fall of 2018. The chart also showed the Brent price as of the first day of each month in 2020. The average price for the first six months of 2020 is $43.50/bbl. Of course, that was influenced by the high oil prices experienced during the first three months of the year. The IEA is forecasting Brent oil will average $34.13/bbl for 2020, down 46% from last year’s average. What is interesting is that if we assume the Brent price trades flat with its June 1st price for the remainder of the year, that produces an average of $40.75/bbl, considerably above the agency’s projection. According to the June Short Term Energy Outlook (STEO), the EIA has increased its oil price forecasts, lifting Brent from $34.13/bbl to $38.03/bbl That means the EIA either believes the Brent oil price will drop for some period of time during the rest of 2020, or the EIA needs to revise its forecast even higher.
Exhibit 8. Is The Oil Price Forecast Too Low?
Source: EIA
While a further recovery in global oil prices would certainly be welcomed, it should not be expected to dramatically alter the thinking of E&P companies. They will want to see oil prices rise further, and remain elevated for some period of time before E&P companies begin spending. The initial actions of these producers are to restart production shut-in during the depths of oil prices and height of fear over the onslaught of crude oil exports heading to >market. With WTI prices in the mid-$30s/b, reports from the oil patch and E&P press releases confirm that reopening shut-in production is underway. At some point, should the demand recovery falter, oil prices will drop. How far down they fall depends on the degree of change in sentiment about the underlying demand factors.
Exhibit 9. How Rigs And Oil Prices Moved In Recent Years
Source: EIA, Baker Hughes, PPHB
The linkage between oil prices and active drilling rigs is tight. The drilling rig count peaked coincident with the bottom of the oil price decline in 4Q 2018. Although oil prices subsequently recovered, they never returned to the $70/b level that marked their recent peak. The oil price recovery in 2019, following the 2018 low, reached price levels commensurate with early 2018. That recovery did not prevent the rig count from steadily sliding. That slide continued throughout 2019, despite oil prices trading within a fairly narrow range. In fact, oil prices began to climb late in 2019. As we entered 2020, oil prices weakened, but, fortunately, the rig count held up. That all changed
Exhibit 10. The Current Rig Downturn Approaches Last Decline
Source: Baker Hughes, PPHB
when oil prices collapsed in sync with the black swans of Covid-19 and the Russia-Saudi oil war. The rig count then fell at one of the fastest paces in history.
Exhibit 10 (prior page) shows multiple rig count declines since 1980, indexed to their peak. Each decline has its own shape and pace, reflective of industry events occurring during the declines. While the 2019-2020 rig decline may not be over, it has reached a point where it matches the 1984-1986 decline. If it continues, it may approach the scale of the 2014-2016 rig decline.
The shape of the 2019-2020 decline, a slow decline and then a collapse, reminds us of Ernest Hemingway’s dialogue in his book, The Sun Also Rises.
“How did you go bankrupt?” Bill asked.
“Two ways,” Mike said. “Gradually and then suddenly.”
“What brought it on?”
“Friends,” said Mike. “I had a lot of friends. False friends. Then I had creditors, too. Probably had more creditors than anybody in England.”
Oh, my! Mike might have been an energy CEO describing those who have become the bane of the oil and gas and oilfield service companies. The companies, swept up in the shale revolution and needing cash to buy acreage and drill wells, were shoveled money by investors, happy to snap up equity and bond offerings to assist the companies to grow. Now, they want their money back, and the companies don’t have it, nor are they likely to get it.
Exhibit 11. How Bad Is The Energy Equity Market?
Source: Reuters
As oil prices rose in the early-2000s, the number of equity offerings and the amount of money raised by energy companies increased.
Fundraising remained stable, with the exception of the Financial Crisis years, but exploded in 2016 in response to years of $100/b oil prices and expectations we would soon revisit those levels again. Since then, however, investors shunned shale producer offerings, demanding the companies demonstrate greater financial discipline, that they live within their cash flows and actually return excess cash to the shareholders. There was a lag between investors embracing shale producers and then acknowledging that they were largely destroying, rather than creating shareholder value. In high-risk debt markets, investors were also infatuated with shale companies, or at least they liked the yields those companies were willing to pay to raise capital. All the debt investors bought has now become a monumental challenge to the survivability of companies. The blue bars in the chart in Exhibit 12 represent the number of issues of high-yield debt offered.
Exhibit 12. How Energy Debt Market Changed
Source: S&P
The magnitude of the challenge facing the industry is shown by the progressively taller columns representing debt instruments from 2020 to 2022. From approximately $38 billion of debt in 2020 to $55 billion in 2022, the debt repayment challenge for oil and gas companies grows. The ability of the industry to repay, or even refinance, this debt appears impossible. This wall of debt is what is driving the uptick in bankruptcies, which will lead to an eventual flood of them, and is what haunts the industry and investors.
Exhibit 13. Oil And Gas Faces Debt Wall In 2022
Source: S&P
Over the past decade, private equity investors discovered the shale business and perceived a potential investment opportunity. They were happy to back new management teams in building new shale energy companies – both E&P and service. These new companies offered the opportunity for private equity managers to exercise all their skills – picking managements, developing strategies, raising capital (especially with a financial structure that facilitates the use of leverage), acquiring and merging companies, and exiting investments.
Exhibit 14. Energy PE Has Lots Of Dry Powder
Source: Private Equity International
All of this capital market activity was driven by the cheap money that was key to the nation’s recovery from the 2008 Financial Crisis. Once cheap money was unleashed, the Federal Reserve has been unable to turn off the money spigot. High-yield, high-risk debt was purchased hand-over-fist by investors desperate for income to make up for the absence of returns from low-risk government bond yields caused by the flood of cheap money. As debt on company balance sheets ballooned, the race to generate cash flow to stay ahead of debt repayments, while also stepping up drilling and well completions, was underway. That race lasted until the music stopped with the black swans.
The race shifted to how to deal with the debt. Although we know what is coming, the early figures are now in, courtesy of law firm Haynes and Boone who publishes bankruptcy watches for the E&P and oilfield service industries. The results, while listed as second quarter, are actually only through May. The firm announced that due to the impending avalanche of bankruptcy filings, it would begin reporting data monthly, rather than quarterly. Recently, Haynes and Boone energy practice co-chair Buddy Clark, told Energy Intelligence, “It’s possible we get to 100 filings this year. This is just the beginning of what follows the collapse of oil prices from the pandemic. The near-term future is not looking very bright – except
for oil and gas bankruptcy lawyers.” He had previously told another publication, "It’s hard to believe that 100 bankruptcies is the optimistic view. That just shows you where we are."
So, where are we? The latest data from Haynes and Boone shows that 14 E&P companies filed for bankruptcy during April and May, which was up from only five in the entire first quarter. Those filings represented $11.75 billion of secured and unsecured debt.
Exhibit 15. The E&P Bankruptcies Are Beginning To Flow
Source: Haynes and Boone
Looking at the oilfield service industry, we see a similar phenomenon. There were only five companies filing for bankruptcy protection during April and May, down from eight that filed in the first quarter. The five companies represented $812.2 million in total debt. Of that amount, 82% was accounted for by Hornbeck Offshore Services, Inc., with $668.5 million of total debt.
Exhibit 16. How Many Oil Service Bankruptcies Are Coming?
Source: Haynes and Boone
While the most recent bankruptcy data is not a complete surprise, we need to put into perspective the current environment for the energy industry’s financial health. Since the second quarter is not finished, we fully expect to see more E&P and service companies filing for bankruptcy protection. To assess where the industry is presently, we looked at the annual data from 2015.
Exhibit 17. E&P Bankruptcies Seems To Have A 2-Year Cycle
Source: Haynes and Boone, PPHB
What is striking when looking at the two charts is the dramatic rise in both the number of bankruptcies in 2016 for E&P companies. That was the second year following the 2014 oil price drop, and it reflected the weak financial position of many shale oil companies prior to the price collapse. When we look at the following years, we noticed there was a jump in companies last year, which followed the oil price fall in 2017. Now, just because we have a pattern, that doesn’t mean we need to wait until 2022 for the fallout from this global oil price collapse and economic shutdown to manifest itself in a spike in bankruptcies. This year will see more bankruptcies, as the weakening of balance sheets and the loss of substantial cash flow heading into this downturn will doom many producers quicker.
Exhibit 18. Oil Service Company Bankruptcies Will Climb
Source: Haynes and Boone, PPHB
The pattern of bankruptcies and debt expunged for the oilfield service industry is somewhat different from that of E&P companies. The service industry seems to follow a three-year cycle. Unfortunately, 2020 marks the third year of this pattern. We know from public filings that there are a number of large, heavily indebted oilfield service companies that have hired restructuring advisors and lawyers to guide them through negotiations with their lenders prior to filing for bankruptcy. In other words, there will likely be greater pain to be experienced in the oil patch over the balance of 2020.
The recent employment report for May that showed nearly three million jobs being added, rather than the anticipated nearly nine million jobs being lost, suggests the economy is snapping back as states reopen. Whether the totals are accurate seems to be debatable. What is important is that the growing reopening of states did add more workers to the employment rolls. More people working means more energy will be needed, especially oil and gas, which is tied closely to mobility activity. This data, coupled with the agreement among the OPEC+ parties to extend their production cuts for another month, has encouraged traders to bid oil futures prices higher. The higher oil price is bringing some shut-in wells back into operation. What we haven’t seen is any uptick in new well drilling. That will take longer to begin, as producers will want to see higher prices and for those elevated prices to be sustained for a while. Normally, the lag between upturns in oil prices and a pickup in drilling is about three months. Will the lag be as long this time? The answer probably depends on the financial health of companies, as well as their ability to access capital. The push by investors for increased financial discipline, plus greater emphasis on more attention to environmental, social and governance (ESG) standards and decarbonizing the economy will play into the future recovery and pace of activity. Enjoy the better industry environment, but don’t expect a dramatic activity recovery soon.
Rebuilding Economies After Covid-19 And Fuel Choices (Top)
“We have a unique opportunity to build a greener and more resilient Europe through investment and innovation,” stated Thomas Buberl, Chief Executive Officer of insurance giant AXA and Chair of the new CEO Action Group for the European Green Deal. This view is shaping the debate over the European recovery plan, although there remain skeptics of its sustainability. The greener economy view is also rapidly becoming a central plank of liberal proposals for restructuring the U.S. economy as it rebounds from the Covid-19 shutdown. These pushes for greener economies are prompted by pictures of cleaner air over various cities around the world that appeared in the media as economic shutdowns peaked earlier this year.
An interesting aspect of those clean air pictures is that the greenhouse gas data reported by the meteorological station on the Mauna Loa volcano in Hawaii doesn’t show any reduction in CO2 this spring. How could there be so much clean air in cities that locked down their citizenry, restricting the amount of driving undertaken, yet no impact on CO2 data? The National Oceanic and Atmospheric Administration (NOAA) who operates the station explained on its web site that the natural carbon cycle was overwhelming the reduction in emissions. Who knew that the world was subject to a seasonal carbon cycle that is strong enough to offset the reduced carbon emissions from a global economic shutdown?
Exhibit 19. Covid-19 Not Impacting Carbon Emissions
Source: NOAA
According to the Organization for Economic Cooperation and Development (OECD), which includes 37 of the world’s most developed economies, the group’s GDP fell by 1.8% in 1Q 2020, the largest quarterly decline since the 2.3% contraction experienced in early 2009 at the height of the financial crisis. What we know is that country shutdowns created greater economic retrenchment in the early months of 2Q 2020. The International Monetary Fund (IMF) was projecting a 3.0% decline in world GDP this year, after originally forecasting growth of 3.3%, a swing of 630 basis points. Last week, the World Bank issued a report predicting the global economy could shrink by 5.2% this year, a severe contraction, but not the worst forecast scenario the bank presented. The 2020 contraction makes the Great Lockdown, as the IMF calls it, greater than what was experienced during the 2008-2009 Financial Crisis, and only surpassed by the 1929-1932 Great Depression era when global GDP shrank 50%.
We found NOAA’s explanation for the lack of carbon emissions progress to be fascinating since seldom is there any mention of the existence of a natural carbon emission cycle, nor that it is significant.
What we are learning with the sharp global economic contraction is just how strong nature truly is. Regardless of the recent data, the Global Carbon Project, a global research project of Future Earth and the World Climate Research Program, both groups of scientists and climate experts from around the world, using data from the International Energy Agency (IEA) and the Carbon Dioxide Information Analysis Center (CDIAC), forecasts a 5% reduction in CO2 emissions this year due to the economic shutdown. The group notes this will be the first emissions reduction since CO2 fell 1.4% following the 2008-2009 Financial Crisis. We would point out that there has been a decline in emissions after every significant economic event, as demonstrated by the chart in Exhibit 20.
Exhibit 20. Significant CO2 Reduction Predicted For 2020
Source: Carbon Tracker
The hope is that 2020’s CO2 decline will set the world on a new trajectory that will bring it closer to the goals of the 2015 Paris Accord. Governments now are able to unleash the monetary printing presses with the blessings of their citizens who are pleading for financial support to deal with the Covid-19 shutdowns. At the same time, expectations are that interest rates will remain near zero for the foreseeable future, a policy embraced by the U.S. Federal Reserve, minimizing the financial pain governments will face as they increase their spending and grow their debt. With this framework in mind, we see, especially in Europe, concrete plans to target industries perceived to be catalysts for building a green economy and back them with policies and money.
France is taking a leadership role in Europe in this green economy effort. President Emmanuel Macron announced an €8 ($9.1) billion plan to revive France’s automobile industry. The plan increases by €1,000 ($1,136) the subsidies for buyers of electric and hybrid vehicles, increasing them to €7,000 ($7,953). There will also be funds for research into hydrogen power and self-driving cars. France will also have the equivalent of the U.S. “cash for clunkers” program from the Financial Crisis days, in that French car buyers can purchase conventional gasoline- and diesel-powered vehicles if they can demonstrate these new cars are more fuel-efficient than their current vehicles.
A prime motivation for France’s financial stimulus programs is to not only promote greater economic activity, but also to drive it towards greener energy. In President Macron’s targeting of near-term support for France’s automobile manufacturers and its suppliers is the hope they will become global manufacturers and exporters of clean vehicles. He wants France to lead Europe in the production of clean vehicles, with an output target of one million units a year by 2025. PSA, owner of the Peugeot and Citroën brands, is increasing its clean car manufacturing capacity from zero in 2019 to 450,000 annually by 2022. Renault, another French car manufacturer, plans to triple its clean car output by then.
President Macron has pitched his rescue efforts, including those for Renault, as a three-way deal between the state, manufacturers and employees. The companies should be investing in production on French soil, as a condition of receiving government support. One shouldn’t underestimate the role that the French government’s ownership of 15% of Renault has played in the rescue effort.
To further that effort, France and Germany have teamed up to back a consortium of PSA Group, its German subsidiary, Opel, and Total’s Saft, to build an electric vehicle (EV) battery manufacturing plant, freeing the European auto industry from dependence on China and South Korea for EV batteries. France’s Renault will become a partner in the consortium, also. The two governments are pledging €1.7 ($1.9) billion to support the consortium.
The €7 ($8) billion bailouts of Air France-KLM and Air France requires various greenhouse gas reduction steps. The airline is to cut by 50% its overall CO2 emissions per passenger-mile by 2030, compared to 2005 levels. For domestic flights, the reduction is more stringent, as Air France is to cut emissions by 50% by 2024. One way this will be accomplished is to stop flying between domestic cities where high-speed rail transportation of less than 2 ½ hours exists. French finance minister Bruno Le Maire said that these short-distance flights “aren’t justified.” As he put it, “The cost in terms of carbon emissions is too high.” Short-distance flights for feeding passengers onto long-haul flights will be allowed, but at a much-reduced level.
France is not the only European government targeting green investments as part of structuring its financial stimulus efforts to help their Covid-19 ravished economies recover. These efforts will impact the future of the energy business – both for transportation and electricity. The social embrace of many of these actions across Europe, whether it involves clean vehicles, renewable-powered electricity generation or restrictions on the use of vehicles within urban areas, carries a cost, which has yet to be fully-levied on the citizens. In Germany, the revamping of its electricity industry to generate 65% of its power from renewables has led to protests about the relative burdens levied on residential and commercial power-users. There is also a growing battle over wind turbine siting, an issue so contentious it may cripple the onshore wind industry.
Amazingly, Germany has recently started up its last coal-fired power plant, something fossil fuel supporters point to as a necessary evil due to the country’s move to a largely-renewable electricity system. The 1,100-MW Datteln 4 €1.5 ($1.7) billion power plant in the North Rhine-Westphalia region began testing in May and went into commercial operation on May 30. Its supporters acknowledge the timing of the start-up was unfortunate. During the testing, Germany’s power demand was so low due to Covid-19 that overall power prices fell to such low levels renewable energy producers lost money. This has prompted a call to increase and extend the subsidies for renewable power.
The new Datteln 4 plant is much more efficient, allowing the closing of older, less-efficient plants, which could cut 40% from the industry’s carbon footprint. The challenge facing Germany’s power industry is how to fuel its electricity generation while meeting the country’s goal of becoming carbon neutral by 2050. German citizens found out the answer to a question posed by The New York Times: How hard is it to quit coal? The answer was 18 years and €40 ($45.5) billion. That investment will fund the closure of the nation’s 84 coal-fired power plants by 2038 and the social costs for the displaced workers.
An argument for closing the coal-fired power plants is the job creation that comes with renewables. According to government data, there are about 20,000 workers in Germany’s lignite (brown) coal industry, and about 15,000 in its black coal mining industry, with about 5,000 workers at lignite-fueled power plants. That compares to more than 250,000 renewable energy sector workers. (There is always a question about how green energy jobs are counted, and the methodology often overcounts them.) Of course, the goal of power is to reduce the number of workers necessary to produce it, allowing others to work in more economically-productive jobs. That has been its history, too. At the height of Germany’s coal industry in 1957, it produced 150 million tons of black coal and employed 607,000 workers. Although output has declined, a significant portion of the reduced labor is due to improved mining productivity.
Lower Saxony’s government, Germany’s largest wind producing state, is calling for a "safety net" in the form of continued support payments for wind turbines, targeting those who lose their subsidies in 2021. That marks the end of their 20-year guaranteed support period. These turbines cannot be easily replaced. Thus, Germany would face a decline in its total renewable power capacity. A reason they cannot be easily replaced is that there is growing opposition to the siting of turbines, resulting in litigation and regulation against new turbines. The government says "This safety net should be akin to long-term power provision contracts." It proposes a fixed remuneration of about 4.4 eurocents (5-cents) per kilowatt hour (kWh) for a maximum of seven years. It argues that power customers, who pay the surcharge with their power bill, would not face higher costs as long as power prices for onshore wind remain above the fixed remuneration.
Some of the power providers argue that they need a “temporary backstop” to avoid a decrease in Germany’s renewable power capacity. Five thousand onshore wind farms are targeted to close. Power companies believe it is cheaper to keep old, fully-functional wind turbines operating than to replace them with power plants of any technology.
Exhibit 21. Covid-19 Hit German Energy Use Hard
Source: Clean Energy Wire
A concern for keeping wind turbines spinning was their contribution to Germany’s energy mix during 1Q 2020. During that quarter, renewable energy accounted for more than half the electricity generated on the German grid for the first time ever. Wind power was the largest component with about a 35% market share.
The impact of the global economic shutdown on electricity use has been significant, although it varies by country. In a recent report, the IEA showed just how power demand fell with the start of shutdowns, and in the early stages of recovery. As power demand grows, how it is fueled may shift based on employment and economic considerations, overwhelming environmental concerns. For politicians and managers, short-term concrete economic pressures may far outweigh long-term possible health issues.
Exhibit 22. Covid-19 Impact On Electricity Use
Source: IEA
For example, in India, the government is seeking to bail out power generation and distribution companies while pushing utilities to switch to using coal from the country’s ever-growing stockpiles. That may help the economics of the companies, while at the same time boost employment in the coal mining industry.
Other countries such as Bangladesh, Mongolia and Indonesia are backing building more coal-powered plants. Financing these projects may become more challenging as various banks, largely those in Europe, are backing away from financing coal projects by 2030 and 2040. The abandonment of coal investments by sovereign wealth funds and large, socially-focused institutional investors will also add to the challenging investment environment. For example, the Norwegian sovereign wealth fund has dumped the stocks of five coal companies and put four others on notice. A major French bank has also announced it will cease financing all coal projects for European Union and OECD countries by 2030 and the rest of the world by 2040. The World Bank announced in 2013 that it would only finance coal projects if there were no alternative energy source available. Since then, the bank has worked around this pledge by making indirect loans, but again only in countries where there are limited alternatives.
In December, the IEA projected coal use through 2023 would be stable. It sees strong consumption growth in Southeast Asia offsetting declining consumption in Europe and North America. The reason for Southeast Asia growth is its affordability and availability, according to the report. CarbonTracker’s web site has an interactive chart showing global coal use. Based on 2019 data, the world has 2,044,831 meagawatts (MW) of coal power generation capacity. China accounts for 49% of that total. In the United States, coal generating capacity was 246,187 MW, which was slightly higher than third-place India with 228,964 MW. The big difference is that the trend in the U.S. is down, while it is rising in India.
Exhibit 23. China’s Coal Use Has Soared
Source: Carbon Tracker
While China is the world’s largest coal consumer, it is continuing to add plants as the country’s power needs grow. At the same time, China continues to build out its renewable energy portfolio and, importantly, the ability to get this power to market. In the past, much was made of China’s additions of renewable generating capacity, but its output wasn’t growing at a commensurate rate. That was because there were limits on the capacity to ship this power to customers. China recently completed the construction of a $3.17 billion ultra-high voltage electricity line that, for the first time, will transport only clean energy. It will allow more renewables to be developed in Qinghai and Gansu provinces and deliver that electricity to Henan in central China. Based on initial plans for 2020, China planned to add 52% more new wind and solar power capacity than it did in 2019. That year it added 25.74 gigawatts (GW) of wind power and 30.11 GWs of solar, but it still has capacity to add 36.65 GWs of wind and 48.45 GWs of solar power to the grid.
Exhibit 24. China’s Energy Mix Is Changing Slowly
Source: Carbon Tracker
Covid-19 and its response has upset the global energy market. In most regions, the higher cost of renewables compared to indigenous coal deposits has led to the latter being favored for fueling additions to electricity generating capacity. In the region most committed to green energy, Europe, the financial stimulus is being used to reorient its carbon emissions trend. In Europe, this effort for more green energy is not being embraced by all parties. The commentary by one leading European businessman offers a view as to the future. Michael O’Leary of Ryanair commented, “I suspect an awful lot of the environmental agenda and targets will be put on the backburner for a number of years.” He went on to say that people will still care about the environment, but they will care more about “massive unemployment” and sizeable government indebtedness. As a columnist for the Financial Times put it, Mr. O’Leary has history on his side. Ahead of the global recession associated with the Financial Crisis, he predicted the downturn would shift attention from the environment to unemployment, which is exactly what happened. Mark Carney, the former Bank of England governor, confirmed that shift when he pointed out that immediately following the recession, only $1 in $6 of investment was spent on sustainable infrastructure.
The FT columnist said she thought that Mr. O’Leary would be wrong about this crisis. In her view, too much has changed over the past decade. Green technology is cheaper, it employs massive numbers of people, and countries have agreed to compensate coal workers and other workers who lose their jobs in the green energy shift. All of that makes it harder to argue that climate change actions will automatically cost jobs. Left out in this analysis: At what cost?
Offshore Oil Service Sector Being Pressured To Restructure (Top)
The headline of a recent Financial Times article about offshore drilling read: “Seadrill/offshore oil: under water. The forecast for this sub-sector is as dark as its product.” It is possible that no other sector of the oil and gas business has as bleak an outlook as offshore drilling. How could it not, given the dramatic decline in oil prices due to Covid-19 and the oil war between Russia and Saudi Arabia, and the high cost of the oil being sought offshore? As an old African proverb states, “when elephants fight, it is the grass that suffers,” meaning the weak get hurt in conflicts involving giants, and who would not argue that Russia and Saudi Arabia are heavyweights in the global oil industry? The oil service industry is among those in the grass, and the offshore sector is even weaker, so they are being crushed by low oil prices.
Baker Hughes reported for the week ending June 5 that only 13 drilling rigs were working in the Gulf of Mexico, down from 23 a year ago. In the early years of this century, the Gulf rig count was consistently 10-13 times greater, and in the boom days of the 1970s, the offshore rig count was well above 200.
What is happening in the Gulf is consistent with what is happening with offshore activity worldwide, as the oil price collapse after Saudi Arabia and Russia failed to agree to extend the OPEC+ oil production cuts collapsed oil prices. Ignoring the few hours when WTI oil prices actually fell into negative territory for the first time ever, the prospect that world oil prices would trade around $25 a barrel for the foreseeable future forced producers to slash their capital spending plans for 2020 and begin reorienting business strategies.
Exhibit 25. How Offshore Rig Counts Have Unfolded
Source: Credit Suisse
The problem for the offshore industry is its recent history, and the inability of managements to envision the possibility of an extended period of low activity. As a result, managements built budgets and debt repayment plans based on expectations of more historical rates of activity and day rate levels. History shows that since the first OPEC oil price collapse in late 2014, the offshore industry has experienced a dramatic decline in business. From mid-2014, when oil prices were last in the $100 a barrel range, the offshore rig count fell steadily, reaching bottom in late 2017 for floating drilling rigs, but earlier in September 2016 for jackup rigs. Between the high and low in June 2014 and September 2016, the rig count fell by nearly 43%.
Floater rigs, semisubmersibles and drill ships, are used primarily for deepwater drilling and development work, which requires higher oil prices both initially and for the future. The bottom-supported jackup drilling rigs work primarily in shallow water, which tends to be a market that responds faster to changes in oil and gas prices. A reason for that faster reaction time is a function of lower day rates for jackups and shorter contracts. Shorter contracts are tied to the larger fleet, offering greater choices for offshore E&P customers.
The current worldwide offshore drilling fleet of 510 rigs is roughly composed of 72% jackups and 28% floaters. Using data from investment banker Credit Suisse’s latest monthly offshore rig report, there are 315 working jackups and 98 floaters. The respective fleet segment utilizations are 85.4% and 69.5% for jackups and floaters. Overall, the offshore drilling rig fleet has an 81.0% utilization rate.
A point that should not be lost when analyzing fleet utilization is that since 2014, according to oil industry consultant Rystad Energy, 160 drilling rigs have been removed from the active fleet. That means the world’s fleet has contracted by 24% over the past five years. Based on comments from Seadrill Limited and announcements from Transocean Ltd., the fleet will likely continue to shrink. While an extraordinarily large contraction, it is not unprecedented in the history of the offshore industry. It is also a necessary step along a path to restoring industry profitability.
A recent report by Rystad Energy focused on the problems besetting the floating drilling segment of the offshore industry. At its root, the industry has too much debt for the earning power of its equipment. This view was echoed by comments from Seadrill chief executive Anton Dibowitz in the company’s first quarter 2020 earnings call with analysts and investors. He observed:
"This industry has two fundamental challenges which are emphasized by recent events – there are too many rigs carrying too much debt […] a number of our assets are increasingly unlikely to return to the market and need to be scrapped. Assets across the industry also carry debt levels which are unlikely to be sustainable and consequently we should expect to see substantial indebtedness being converted into equity".
In the earnings report, Seadrill announced an impairment charge of $1.2 billion connected to its plan to scrap up to 10 of its rigs. That charge, which contributed to the company reporting an earnings loss of $1.3 billion, doesn’t reflect the ongoing challenge of Seadrill’s $7 billion in debt on its balance sheet. To support large debt loads, offshore drilling contractors need both high equipment utilization and high day rates. As noted above, utilization for floaters is below 70%. Additionally, as Rystad pointed out in its analysis, drilling contractors lack pricing power, or the ability to lift day rates. The combination of balance sheet leverage, a lack of liquidity, and a challenged business outlook is a recipe for a financial restructuring.
It is difficult to understand all the challenges facing drilling contractors operating in the Gulf of Mexico. A new report from industry consultant Wood Mackenzie titled “After the crash: five key changes in US Gulf of Mexico,” provides some perspective, but also highlights the bleak outlook the FT noted. In the report, the reduction of Wood Mackenzie’s long-term Brent oil price outlook from $60 a barrel to $50, wiped 30% off the remaining value of the deepwater Gulf asset base, reducing the magnitude of work for floaters, and likely limiting the pace of recovery for this sector.
The drop in oil prices, coupled with a less attractive outlook, has contributed to a 22% reduction in spending, the loss of $4 billion. As a result, exploration in the Gulf will fall to historical lows, and a rebound will require time. The firm sees only 15 exploration wells being drilled this year, a reduction of 55% from last year, a level of drilling Wood Mackenzie had predicted for 2020.
The reduced spending will also result in no greenfield projects being sanctioned this year, and subsea tie-back will also struggle. The inability to bring new wells into production this year will contribute to the expected decline in production. That would mark the first drop in production since 2013, which came courtesy of the Gulf of Mexico moratorium following the Macondo well disaster and the reduced investment that followed. Based on the history of the Gulf, it is likely the reduced spending and activity this year will cause a greater loss of production in 2021 and beyond, necessitating the industry stepping up spending at some point.
Exhibit 26. GoM Exploration Drilling To Change
Source: Wood Mackenzie
The Rystad presentation showed that starting in 2015, following the 2014 oil price drop, E&P companies’ exploration spending no longer tracked their cash flow, a first for the industry. As exploration and greenfield development spending accounts for 38 and 39 percent, respectively, of total E&P company spending on floating drilling rigs, the change in company strategies for managing their long-term future has cut in half the market for these rigs.
Exhibit 27. How Offshore Capex Broke From CFO
Source: Rystad Energy
Reduced spending is only one problem besetting the offshore drilling sector. The other is too few customers. Rystad showed that in 2005, there were 51 floater customers (oil companies conducting deepwater drilling), which grew by four to 55 in 2010. The oil price boom following the Great Recession in 2009 led to a 10-customer increase in 2014. In hindsight, the 65 customers that year appears to mark a recent peak in customers. By the end of 2014, the industry downturn commenced, and in two years the customer number fell by 30 to 35. Today, the customer base has shrunk by another five to only 30.
During this period, the number of contractors who could supply floaters to oil and gas customers expanded from 24 to 34, then to 35 and to 38, before shrinking to 33 this year. The impact over the nine-year period 2005-2014 was that the ratio of suppliers to customers ranged around 50% (0.47 in 2005, 0.62 in 2010, and 0.54 in 2014). With the collapse in the number of customers in 2016, the ratio of suppliers to customers rose to 1.09, and is now 1.10.
With essentially a one-to-one ratio of customers to floater contractors, any pricing leverage that existed earlier for contractors has evaporated. Pricing leverage comes from multiple customers wanting rigs, and facing few options. The lack of pricing leverage jeopardizes future rig utilization and earnings. Without cash flow, debt restructurings will be mandatory. Long-term, the absence of customer competition for floaters will drive industry consolidation. In that regard, Rystad focused on major floater contractors, showing how this universe shrank from 15 to 11 following the acquisitions of smaller competitors by Transocean and Valaris, the company formed through the merger of Ensco Ltd. and Rowan Drilling. Rystad speculates the industry may be headed to only four major floater contractors, although Rystad doesn’t predict when consolidation might occur. If they are right, there is a hurricane of pain and suffering ahead for this industry, something it can’t avoid.
The initial phase of consolidation is already underway – and has been for a while. That phase involves restructuring of company balance sheets, which basically means less debt and more equity. Several offshore drilling contractors are already in bankruptcy – Diamond Offshore being the most recent – with others preparing to file. Several contractors confronting bankruptcy will be doing so for a second time, suggesting more drastic overhauls may be necessary. The failure to adequately restructure balance sheets in their first bankruptcy is why these troubled contractors are at bankruptcy’s door again. A different outlook for the future will be needed to underpin balance sheet restructuring this time.
The contractor bankruptcies will result in companies having new owners, as debt is swapped for equity, leaving current shareholders with little or no value. New company directors, and often new managements, may lead companies in different directions. Changes are often driven by the desire of the new owners to monetize their investments. In reality, they are trying to recoup as much of their past investment as possible, and as quickly as possible. This is the catalyst for industry consolidation. How quickly consolidation occurs will depend on the willingness of contractors to engage in transactions in which one management and organization disappears. These deals make it easier to shrink the global rig fleet. Fewer contractors and fewer rigs will help restore pricing leverage.
The history of the offshore industry consolidation of the 1980s and 1990s will be the model for this cycle’s consolidation. Healthy contractors will be necessary for the offshore drilling industry to be able to deliver quality service for its customers in the future as the industry continues to expand in the challenging deepwater and harsh environments offshore. At some point, these challenges, coupled with the desire of oil and gas companies to want to explore and develop resources in these areas will necessitate a new generation of equipment, something that can only be done with a healthy contracting industry. This will happen because the promise of the offshore is too great for such a reformation to not occur. Predicting the timing is impossible, and a great frustration.
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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.
