- Energy’s Outlook Will Change With Biden As 2021 Isn’t 2020
- As The Energy World Turns: Bankruptcy Is A Constant
- Lockdowns, Fear, Life And Work Changes Hitting Oil Demand
- Europe’s Hydrogen Economy Regardless Of The Economics
- Will LNG Become A Fuel Of Choice For Shipping?
Musings From the Oil Patch
November 17, 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
Energy’s Outlook Will Change With Biden As 2021 Isn’t 2020 (Top)
In contrast to 2020, a year in which the unimaginable became the norm, 2021 will usher in a “return to normalcy” via a new political administration in Washington. With it will come a different view of energy, climate and their politics. The recent U.S. presidential election (still officially undecided) is projected to bring former Vice President Joseph R. Biden, Jr. into office, and with him, a change in the direction of energy and climate change policy. As a result, it will also usher in a changed landscape for energy companies to have to navigate. Just how may the current landscape change?
The future energy landscape will be shaped by an overarching commitment by the Biden administration to aggressive actions designed to rapidly reduce the nation’s carbon emissions. While many pundits foresee a political landscape that will prevent the implementation of the most extreme climate and energy actions backed by the progressive wing of the Democrat Party, we are not so sanguine. We would point out that Mr. Biden and his administration are well-schooled in the intricacies of manipulating the levers of the federal bureaucracy, as well as the legislative machinery. This should be a warning for Washington-watchers trying to anticipate how the energy business will fare under the administration of the 46th President of the United States to not accept what seems like straight forward conclusions.
There are many things about the incoming administration that we do not know, and that will shape its policy agenda. It may not become clear until early 2021 that we can realistically assess how energy and climate policies will change and what the impact may be on our economy and society. We do know some things, and others are becoming clearer by the day. Yes, the Republicans held off the media’s predicted Democrat ‘Blue Wave’ that would have yielded not only a Biden/Harris victory at the top, but would have also seen a larger Democrat majority in the House of Representatives and shifted control of the Senate from the Republicans to the Democrats. So far, neither of the Congressional outcomes have been realized, however, Republican control of the Senate will remain in doubt until the results of the January 5, 2021, Georgia senatorial run-off elections are decided. The defeat of the two Republican incumbents would leave the Senate with a 50/50 split in party affiliations, with the tiebreaking vote resting with Democrat Vice President Kamala Harris. This would assure Democrat control of the Senate, which ensures Democrat leadership for all the Senate committees, as well as the ability to set the political agenda in step with the House and the Biden administration.
Assuming the Republicans win the two Georgia run-off elections, they will control the Senate, giving them the ability to block policy changes that require legislative approval. This assumes moderate Republicans would not support opposition policies. And here is where the experience of Mr. Biden may become a wildcard in projecting outcomes. Given the way Congress works in the modern era, there is seldom a stand-alone bill dealing with a topic. Legislation is a mish-mash of provisions and items buried beneath a bill’s primary thrust. Those items might be structured to appeal to the political calculations of middle-of-the-road Republican senators worried about their upcoming re-election chances, causing them to flip their votes. With 37 years of history in the Senate, Mr. Biden is experienced in the “horse-trading” of legislation.
Does this imply that the highly liberal Green New Deal is going to pass? No. But, brick by brick, much of its plan can be constructed, with only the most radical pieces being left out. In this scenario, we need to watch what can be done and will be done through a President Biden’s executive orders. Not only are these orders significant, albeit not enshrined by law, they often unleash the power of the bureaucracy to enact rules and regulations that can achieve a high percentage of the desired objectives of the Green New Deal. In that regard, expect wind, solar and batteries to be favored targets for investment and mandates under the Biden administration.
Will fracking be banned? Yes, potentially on federal land, as it falls within the realm of bureaucratic power. We fully expect such a move, as Mr. Biden will need to score some political wins to keep the support of the liberal wing of his party before he has to compromise away from some of their goals. Rejoining the Paris Agreement on day one, a campaign pledge of Mr. Biden, will be applauded by the left, but what else will be tied to that move – stricter emissions reduction goals; following through on the requirement to give money to the developing economies; making the Glasgow meeting outcome for global climate policy as meaningful as Copenhagen or Paris? We will be watching to see.
How about nixing the Keystone XL pipeline permit? Will that be merely be an executive order, or will it become a foreign policy event helping to boost the stature of Canada’s leader Justin Trudeau? Some of the answers to these types of questions may depend on the personnel that Mr. Biden brings into his administration, an unknown factor at the moment, although names are being floated in the media and the betting odds are forming.
In thinking about 2021 and thereafter, we thought some of the comments by former Obama administration’s Secretary of Energy Ernest Moniz in a recent fireside chat are insightful guidelines. In his view, Mr. Biden will move to seek a bipartisan agenda that will focus on ramping up our energy innovation effort, while also pushing for a significant infrastructure bill that will include a focus on energy infrastructure. He said the Biden climate change/energy agenda would include not only returning to the Paris Agreement, but increasing emphasis on energy efficiency measures for appliances and elevating the corporate average fuel efficiency (CAFE) standards for vehicles. California will certainly retain its right to institute its own automobile emission requirements, which are followed by a number of other states and the automobile industry.
Sec. Moniz listed six key aspects of the energy transition that will occur under the new administration. (He was an energy advisor to Mr. Biden during the election campaign and is being touted as a possible cabinet member.) The list includes:
- Securing coalition support for the agenda (a political requirement);
- Recognize regional solutions to climate change, but coupled with a social justice agenda;
- Jobs/Jobs/Jobs;
- Secure the supply chains for clean energy technology;
- Clean energy innovation on steroids; and
- All of the above.
His discussion of a couple of these points was enlightening. Sec. Moniz said that during his term as Energy Secretary, his department documented that energy was responsible for twice the job creation rate compared to the overall economy. While not stating the obvious, this was due to the fracking revolution, which also led to geopolitical changes, including our ability to reshape Middle East politics. Moreover, the fracking revolution was the energy miracle that helped lift the economy out of the Great Recession. Without its success (forget its profitless nature), the U.S. economy’s recovery would have been even slower than it was.
Secure clean technology supply lines will be critical because the U.S. does not have the necessary minerals and metals for this revolution to be on solid footing. This is a point that Benchmark Minerals, a rare-minerals consulting firm, has made. They envision the clean energy future having a totally different supply chain from today’s, if governments are going to feel safe in pushing this technology. That means China will see its power in this sector diminished, but will that actually happen as they control supply and essentially set prices? Sec. Moniz also pointed out that we do not have the clean energy technology to reach net-zero carbon emissions. He figures it will take 2-3 times the current level of R&D investment to achieve such a goal, but he doesn’t know how long that may take.
Sec. Moniz’s sixth point, he said, would upset people. He believes we cannot ignore any solution in any region, which is why everything needs to be on the table. Presumably that includes fossil fuels, but likely tied to carbon capture technology and potentially a carbon tax. He also hailed the advances in nuclear technology, including fission and fusion, that should play a greater role in our clean energy future. In that regard, there are some interesting developments coming out of an effort at Massachusetts Institute of Technology, (MIT) and with its spin-off subsidiary, Commonwealth Fusion Systems, suggesting that technological breakthroughs have occurred that are bringing forward the timetable for fusion energy. His final point about nuclear (Sec. Moniz’s area of research expertise and personal passion) is that “there has never been as much R&D going into nuclear technology as now,” and that all of it is coming from the private sector. Nuclear is often acknowledged as being a critical energy technology if the world truly wishes to be carbon-free, but the fear of nuclear needs to be overcome for it progress.
A final point about the energy transition that will come with the new administration made by Sec. Moniz, was his comment that the court system today is very different from what existed during the Obama administration. As hard as it is to believe, given the long list of court battles over Trump administration policies that it lost, Sec. Moniz believes the courts may become a greater barrier to the implementation of climate and energy policies than political opposition. In hindsight, President Donald Trump’s legacy may be the judges he appointed to the federal courts who are expected to adhere to the words in the laws, rather than seeking ways to bend the laws to facilitate judges’ socially-desirable objectives. In our view, this observation may have been the most significant point Sec. Moniz made, and which may bear heavily on achievements of the Biden administration.
The courts may become critical when industry is forced to fight adverse rules and regulations. If the U.S. Senate remains under Republican control, the avenue for major changes to energy and environmental policies will be limited. Any progress will be tied to how good the Democrats are in drafting legislation and horse-trading the issues included.
Rules and regulations can be implemented easier than many believe. People worried about the staffing of agencies and departments may be overlooking the fact that lower level bureaucrats can temporarily run them, and since the vast majority of those staffs are sympathetic to the liberal agenda (bureaucratic power), this will not be a major hurdle. While some of the changes will require public comment periods, one should remember that the bureaucrats during the Obama administration often ignored or circumvented the Administrative Procedure Act (APA) requirement for implementing rule changes objected to by industry. This happened with offshore regulations, which offshore oil service company executives failed to challenge. It also didn’t matter what the courts ruled, either, as we saw with the Gulf of Mexico
moratorium following the Macondo well accident. Despite a court victory against the Obama administration’s offshore moratorium, it immediately reinstituted another moratorium. That last one was eliminated with the capping of the runaway well, ending the oil spill.
This political landscape is what energy companies will have to navigate over the next four years. Will they manage it? Likely, yes. Will it impact activity? Yes. These regulatory battles will come at the same time the industry is attempting to chart a strategy in a world where fossil fuels are a target for elimination, regardless of the physics or reality of energy needs and the state of clean energy technology. As Sec. Moniz’s comments highlight, as a nation, and likely a world, we do not have the clean technology to make the rapid shift in our energy consumption desired by environmentalists. Besides lacking the technology, much of it is uneconomic. Wishing and hoping the technology will scale up while the costs will fall significantly is the plan. But, as one of our old bosses taught us, “wishing and hoping” isn’t a strategy for success.
As The Energy World Turns: Bankruptcy Is A Constant (Top)
The latest bankruptcy figures for October have been released by law firm Haynes and Boone. The show that filings by oil and gas producers and oil services companies continue. The October figures for E&P companies might suggest a respite – only three entered bankruptcy proceedings. Nine oil services companies filed, however. These bankruptcies added $138 million in additional debt to the year-to-date total for E&P companies in 2020, and boosted the oil services’ total by $3.9 billion.
Exhibit 1. Oil Services Bankruptcies Setting New Records
Source: Haynes and Boone, PPHB
Exhibit 2. E&P Bankruptcies Continue Increasing Slowly
Source: Haynes and Boone, PPHB
Through the first 10 months of 2020, E&P company debt is trailing the record bankruptcy year of 2015 by $3 billion from 43 filers, compared to 70 in the earlier period. The oil services sector has passed its record year of 2017 by one company (53 vs. 52), and by 10% in total debt involved ($38.95 vs. $35.25 billion.) These stats signify how damaging the industry’s debt has been in a Covid-19 and oil price crash environment. Debt is one thing, but the jobs lost and lives disrupted are the saddest aspects of this correction.
We caught up with Buddy Clark, co-head of Haynes and Boone’s energy practice and Charles Beckham, Jr., the head of the energy bankruptcy efforts last Friday morning. While our conversation was held before the final October bankruptcy data was released, we talked briefly about the market trends reflective in the energy bankruptcy filings. Since their firm began tracking and publishing industry bankruptcy data in 2015, there have been over 250 filings total in each industry sector – 251 E&P producers and 254 oil services companies. The E&P sector total includes a couple of reruns, or Chapter 22 filings, when a company goes through bankruptcy a second time.
Given the relatively few filings last month, we wondered if the bankruptcy tsunami had run its course. Mr. Beckham noted that the timing of filings is dictated by liquidity and/or debt maturity events for companies, and not the calendar. While always wondering if the pipeline of bankruptcy candidates will run dry, especially with over 500 filings over the past five years, Mr. Beckham said he was not concerned about the lack of bankruptcy candidates in the foreseeable future. He began his energy bankruptcy practice in the 1980s in Midland, Texas, when the last major industry bust was underway. His career is a testament to the inability of some energy executives, even in boom times, to properly managing their company’s financial affairs.
According to Mr. Beckham, 2020 has seen more liquidity-driven filings than debt maturity ones, which may be a commentary on the impact of low oil and gas prices and the inability to cut costs fast enough to keep from sinking under debt loads. This trend is likely to continue during 2021 as producers see their production hedges burning off, meaning that revenues may take a hit, putting increased pressure on expense management.
As the energy industry moves through this period of restructuring, there are several developments that bear watching. In the last 90 days, these two lawyers are noticing greater financial restructurings underway among energy companies backed by private equity (PE) funds. PE funds traditionally utilize large amounts of debt in order to help boost investor returns. These financially over-leveraged companies are struggling in a low-oil price environment, forcing their PE sponsors to merge, sell or shut them down, but usually without going through the traditional bankruptcy process. A complicating consideration pointed out by Mr. Clark, is that there are often plugging and abandoning liabilities associated with the wells and leases, making it a less clean open-or-shut decision, especially if these firms are partners in E&P projects. The emergence of PE-backed companies as the next area of bankruptcy concern reflects the active involvement of these firms during the oil and gas boom years of 2010-2014. This is a dynamic making this industry downturn different from previous cycles in which few PE funds were involved. In the earlier cycles, debt financing came from more traditional sources such as banks, insurance companies and public markets.
The most intriguing development impacting the industry’s future we discussed with Messrs. Beckham and Clark are the battles between E&P companies and their midstream gathering and transmission vendors. Midstream companies negotiated contracts with producers to install pipelines in fields to collect the produced oil and gas and move it to market based on the belief that these contracts created a covenant that ran with the land and could not be rejected by a debtor during bankruptcy. These sacrosanct contracts provided the security allowing the midstream companies to borrow the funds to construct these pipeline networks. In a 2016 bankruptcy case, In re Sabine Oil and Gas Corp., a New York bankruptcy court, interpreting Texas law, held that midstream gas gathering agreements did not create covenants with the land and could therefore be rejected by the debtor during its bankruptcy. Different conclusions were reached in other cases: in Badlands, a Colorado bankruptcy court, applying Utah law, found such a gathering agreement did create real property covenants that could not be rejected; while in Alta Mesa, a Texas bankruptcy court, applying Oklahoma law, found certain gathering agreements also created real property agreements that could not be rejected.
In a world where cost pressures are intense on E&P companies, the issue of gathering contracts creating covenants that run with the land and cannot be rejected in bankruptcy is becoming the next major battleground. This is because E&P producers, having fixed their balance sheets via bankruptcy, are now addressing fixing their income statements, as commodity prices remain low. The battle involves the role of bankruptcy courts interpreting various state property laws, and reaching decisions that put the entire midstream industry at risk for raising financing for new pipeline networks, but more importantly in servicing its debt if its revenue stream is damaged.
Reading commentary by law firms about these cases and the issue, we have reached one conclusion. That is: writing future agreements between E&P producers and midstream companies will be challenging. Actually, the proper description is more like pretzel-making. A recent presentation on the issue by Haynes and Boone energy lawyers highlighted text from a recent decision relieving Chesapeake Energy Corp. from its midstream contracts under an interpretation of Texas property law. The citation stated:
“It does not stretch the imagination to envision a contract that both contains a covenant that runs with the land and is executory. In such a circumstance, the appropriate analysis is what benefit was previously bestowed by the debtor on the non-rejecting party that remains post-rejection and what future performance by the debtor is excused by rejection. Depending on the particular language of the subject agreement, a plethora of outcomes are possible”
Welcome to Pretzel Land!
While we have much to learn about this complex legal issue, we raised the question with the Haynes and Boone lawyers as to whether this could lead to massive restructuring of the midstream industry, much like resolving take-or-pay gas supply contracts did for the interstate natural gas pipeline industry in the 1990s. There are significant differences between the two business, not only in where they operate, but who their regulators are and the laws that govern the companies. However, at a very high level, we need to approach this industry uncertainty within the context of the degree of business risk producers and midstream companies are willing to assume. As an example of how traditional energy industry structures are being upset, think about the challenges commodity prices have caused for utilities. Low natural gas prices have impacted the economics of their long-term coal and nuclear power contracts. These issues are part of the “unintended consequences” of the oil and gas downturn, combined with the energy transition underway.
While the law is often thought of as being dry and dull, when it is caught up in the maelstrom of an industry restructuring, such as energy is undergoing, this could be an exciting period. While the lawyers wrestle with state property laws, contract law, energy law, and bankruptcy law, the economics of the industry are in turmoil, hampered by uncertainty about the future of the energy world dealing with Covid-19, collapsed energy demand, altered business and lifestyles, and the global push for a carbonless energy system. Stay tuned, as we monitor: “How the Energy World Turns.”
Lockdowns, Fear, Life And Work Changes Hitting Oil Demand (Top)
If you haven’t been living under a rock, you know that Western Europe and North America are experiencing another wave of Covid-19 infections. The sharp increase in cases, hospitalizations and deaths has forced political leaders to reinstitute more restrictive measures to curb economic activity and social mobility, translating into reduced oil demand. The extent and duration of the current Covid-19 outbreak is unknown, but the popular perception is that we are headed for “dark winter months.” That view is despite the good news of the announcement of the successful development of a vaccine by drug company Pfizer, with plans to begin delivering doses to Americans within the next few weeks.
The fear of further setbacks to the global economic recovery translates into expectations for lower mobility and industrial oil demand. Virtually every oil forecaster is revising lower their demand projections for the balance of 2020. OPEC cut its 2020 demand forecast by 300,000 barrels per day (b/d), implying an overall demand drop this year of 9.8 million barrels per day (mmbbls/day), a 10% decline from 2019. The International Energy Agency (IEA) expects this year’s oil demand to fall by 8.8 mmbbls/d. That estimate reflects a 400,000 b/d increase from its forecast last month, but the overall demand decline is still a record. Neither revision is surprising given the virus news and reduced pace of economic recovery.
For the oil industry, the bigger question is what 2021’s demand will look like, especially given the Pfizer vaccine, and reports that Russia and China are deploying vaccines. The uncertainty about the timing and efficacy of the vaccines means projecting 2021’s economic activity and its resulting oil demand remains a guessing game. OPEC’s economic forecast for 2021 was lowered recently from a 4.5% increase to a 4.4% gain. A 0.1% cut in the growth rate doesn’t seem like much, but it will likely impact those sectors most energy intensive. If the vaccine is rolled out rapidly and Covid-19 infection rates drop sharply, economic activity will ramp up quickly, given the pent-up energy among societies and growing confidence of a return to a more normal lifestyle and working environment. What are the odds of this happening? More importantly, what is the likely timing? The IEA doesn’t expect the vaccine deployment to have much impact on improving economic activity during the first half of 2021, therefore, they are sanguine about the outlook for oil demand. Most other forecasters expect improvement in 2021, but not until the second half of the year and leading into a much improved 2022 demand.
For the IEA, the issue about oil prices is twofold. First, the cuts in activity and demand have been centered primarily in the developed economies (OECD countries), while developing economies such as China and India are experiencing faster rebounds. But the second consideration is the inability of OPEC and its fellow exporters (primarily Russia) to curb global oil output. Therefore, the IEA sees oil inventories not improving materially through the first quarter of 2021. If OPEC+ elects at their upcoming early December meeting to hold to their production cuts, global demand growth next spring will help begin to shrink the inventory overhang, providing room for oil prices to improve. Again, all of these forecasts are tenuous and subject to many considerations, any one of which can derail or accelerate the pace of recovery for the oil market.
This leads us to the bigger question of oil prices. Friday afternoon, oil trading closed at a little over $40 a barrel. Since June, oil has traded within a range of $36 to $43 a barrel. Relative to where oil prices have been over the past few years, this trading range is somewhat narrow, especially when one considers how economic activity and the virus have oscillated between optimism and pessimism. With oil prices around $40 a barrel, the drilling rig count continues to improve, as has the fracking crew count. These are signs that producers feel comfortable they can make money with oil in this price range, which says something about how they have reduced their cost structure, or that they are optimistic the recovery will gain speed, lifting oil prices higher as production declines in response to the spring oil-price implosion and resulting collapse in demand and capital spending. Which answer remains unknown.
Exhibit 3. Oil Prices Are 20% Below L-T Average
Source: EIA, BEA, PPHB
To put the oil price issue into context, we have updated our chart of real oil prices since 1947. It shows that the average real oil price over this period was $48.87. The average nominal price was $25.66.
Certainly, average prices are influenced by the extended periods of very low and very high prices. If we calculate the average prices for 1973-2020, the real oil price averaged $60.91 per barrel, while the nominal price averaged $38.03. We have shown the average real and nominal oil prices for various periods of history, with a brief description of market conditions, demonstrating how different various historical periods have been.
Exhibit 4. How Crude Oil Market Conditions Changed
Source: EIA, BEA, PPHB
The question remains about how long we will be living with oil prices at current levels. With oilfield activity increasing with oil prices around $40, producers are comfortable, although they certainly would like higher prices. We doubt the current low oil price environment will last for as long as it did after the mid-1980s oil price crash – 17 years. With the industry’s continued struggle with over-leveraged balance sheets, at the same time government policies are working diligently to reduce global fossil fuel demand, there remain many imponderables about the future we can only speculate on. We harken back to the “lower for longer” mantra of BP plc’s CEO Robert Dudley introduced in early 2015, as he described the mentality of his management team in their planning for the future. We recommend keeping that mantra at the forefront of your thinking about the future for the oil industry. We will enjoy higher prices, but can’t plan on them.
Europe’s Hydrogen Economy Regardless Of The Economics (Top)
Europe is leading the charge into the Age of Hydrogen. This charge is predicated on the belief hydrogen is the best alternative for the economies of Europe to deal with its carbon emissions. One might liken this charge, however, to the famous one from the 1854 Battle of Balaclava during the Crimean War. In that case, it is believed that a misunderstanding between the commander of the 600-strong Light Brigade and his superiors led to the British cavalry unit nearly being destroyed. Having been ordered to secure Turkish cannon from possible seizure by the Russians, the cavalry instead charged a well-armed and prepared Russian and Cossack artillery unit. Although the cavalry unit broke through the canon ranks and killed some the artillery soldiers, the British were forced to withdraw with devastating losses. Their bravery was immortalized in Alfred, Lord Tennyson’s poem, “The Charge of the Light Brigade.”
So why do we suggest that the arrival of the Age of Hydrogen might suffer the same fate as the British cavalry? It is because few people have a clear view of the cost of hydrogen, let alone what such a switch might cost due to the inefficiency of generating hydrogen energy and then converting it back into a useful form of energy, most likely electricity. Thus, just as the Light Brigade was successful in completing its task, the cost was devastating.
Substantial work needs to be done to better estimate the true cost of the hydrogen economy, if that is possible now. That is why there are so many pilot projects being announced and conducted. Interest in hydrogen as an energy factor cannot be dismissed out of hand, however, because the goal of eliminating carbon emissions has become a significant political and social commitment, especially in Europe. Hydrogen has the flexibility to be used in virtually every energy market as it can be a gas or a liquid. With electricity targeted to be the structure of the future energy system, decarbonizing it is critical, and here is where hydrogen can play a role.
Green hydrogen, which is generated from renewable energy, is the siren song of environmentalists, and is being pushed by multiple governments who are announcing hydrogen strategies. Hydrogen can be produced from natural gas, known as blue hydrogen, but that is less clean. A new research paper suggests that green hydrocarbon produced from electrolysis (electricity) will always be more expensive than blue hydrogen due to the higher cost of the electricity needed for the green process. The announcements of hydrogen initiatives are often key parts of government plans to stimulate economic recovery following their shutdowns due to the spread of the coronavirus. The magnitude of the government hydrogen push can be seen in Exhibit 5 (next page) that shows the dates of announced initiatives.
Exhibit 5. Interest In Hydrogen Is Growing Daily
Source: OGE
Hydrogen is believed to be the best alternative for decarbonizing energy systems. In the case of Europe, its success will be helped by the existence of Europe’s highly interconnected energy infrastructure. This will allow the harnessing of existing renewable energy sources that can produce hydrogen and store it as an energy source that can be utilized in many different applications within economies. The hope for hydrogen’s success is tied to projections for a steady reduction in the cost of new renewable energy capacity that will lower the cost of electricity. Additionally, hydrogen offers cost savings by avoiding having to build new electricity transmission eyesores, since existing pipelines can be utilized.
Exhibit 6. Emissions Trajectory Needs Carbonless H2
Source: Climate Action Tracker
As Paris Agreement carbon emission reduction pressures weigh on European governments, as well as others around the world, the hydrogen solution is being pushed regardless of its cost. Exhibit 6 (prior page) shows the gap between where emissions are and where they need to go to meet the goals from the Paris Agreement. Thus, for the greater good, politicians expect the public to meekly accept the cost of a hydrogen-based clean energy system, whatever that cost may be. We would caution that this view may ignore economic pressures that are overtaking European citizens, which have been manifest in the recent riots against revived Covid-19 lockdowns in various cities on the continent. Given this reaction, it may be a mistake to assume the public will acquiesce to higher energy bills in the name of fighting climate change.
Two presentations during a webinar on hydrogen and Europe provided much needed guidance on the rationale for why energy companies are pushing hydrogen as the preferred solution for the continent’s carbon emissions challenge. The European Commission (EC), which establishes policy targets for the 27 European Union (EU) member countries, recommended in early March a proposal to enshrine in legislation the EU’s political commitment to become climate neutral by 2050. In its release, EC President Ursula von der Leyen wrote:
“We are acting today to make the EU the world’s first climate neutral continent by 2050. The Climate Law is the legal translation of our political commitment, and sets us irreversibly on the path to a more sustainable future. It is the heart of the European Green Deal. It offers predictability and transparency for European industry and investors. And it gives direction to our green growth strategy and guarantees that the transition will be gradual and fair.”
As the statement went on to explain, the European Climate Law sets the 2050 target and the evolutionary direction for all EU policy. However, the Commission needs to consult with the public on the future of the European Climate Pact. So, while the EU may embrace certain policies, without the agreement of all 27 members, the resulting policy may need to be modified. This may be necessary as member countries decide to how best to fight climate change through carbon emission reduction policies for their particular country. Those policies may have to be less onerous for their economies and citizens in order to gain public support.
The EU’s policy targets for reducing carbon emissions are laudable. Their impact is displayed in Exhibit 7 (next page), which shows the projected carbon emissions trajectory under the EU policy versus those for the next few years under a “business-as-usual” approach. People are always seeking policies that will produce graphs sloping downward for things that are considered “bad,” while applauding upward sloping ones for things that are considered “good.” In the case of carbon emissions, which are seen as harming society, the faster they decline, the better. Always left out of such graphs, however, are details about the economic cost and the impact on lives from embracing the policies necessary to achieve the targets.
Exhibit 7. What The EU Wants Out Of Clean Energy
Source: International Monetary Fund
While people may be in favor of the policy dictating reducing carbon emissions, they often don’t care for the actual rules and regulations governing how they must live and work. This is akin to people hate watching sausage being made, but they love the idea of sausage for dinner. The dichotomy between policy and rules is becoming a greater issue in Europe as the future challenges become clearer. To better understand this dichotomy, it is helpful to begin such a discussion by understanding the EU’s current energy situation.
Exhibit 8. A Lot Of Carbon To Get Rid Of From EU Energy
Source: Kehler
Dr. Timm Kehler, Director of Zukunft ERDGAS, an initiative of the German natural gas industry, showed that electricity accounts for 21.6% of the EU’s final energy consumption, but only a third of it is derived from renewable energy sources. Clearly, the industry will need to invest substantially in new renewable power facilities in order to transition the current European electricity business to a carbon-free status, let alone what will need to be invested to move the balance of the continent’s energy demand to electricity. With petroleum accounting for nearly 40% of final energy consumption, one can understand the increased focus on electrifying the transportation sector, but merely banning internal combustion engine vehicles is only an initial transition step. All forms of transportation in Europe will need to be powered by carbonless fuels for a net-zero emissions environment to be achieved.
While electrifying the European economy is the goal, and governments, with the support of activists, are aggressively pushing policies to achieve it, the reality is that renewable energy is unable to ensure 100% power on demand. Backup power will be necessary to deal with the intermittency of renewable energy, but that comes at a huge cost and a risk of failure to meet the needs. Achieving a zero-emissions target may be possible if the costs and disruptions of such a transition are ignored, but even that potential remains in doubt. In the United States, Rich Powell, Executive Director of ClearPath Action Fund, a Republican Political Action Fund (PAC) supporting candidates who back greater support for global warming policies and environmentalism, offered an insightful observation.
“Any plan to have carbon-free electricity by 2035 is wonderfully unrealistic. Even if it were economically and technically feasible, which we doubt, it is undoubtedly not permit-able under current regulations. The private sector is making big bets they’ll reach net-zero carbon dioxide (CO2) emissions by 2050. We need to work towards making sure the private sector has the technology needed to get them all the way to net-zero.”
In other words, timetables for achieving net-zero carbon emissions need to become more realistic, given today’s technology. Policies and goals are important, but technology is critical if we are to achieve net-zero emissions targets. At the present time, many of the projected technologies enabling a net-zero emissions world remain in research mode. Hydrogen is not quite in the research mode, as producing and using it has been underway for decades, but primarily tied to unique and limited applications. What is unproven for hydrogen, both technically and financially, is generating and using it at sufficient scale for electrifying meaningful economic sectors.
The current push for hydrogen is tied to the realization that the growth of renewable electricity in creating operational and financial challenges for utilities. Because wind and solar are intermittent, generating capacity must be overbuilt in order to ensure the delivery of the consistently desired volumes of electricity. When the wind blows strong and steady, and/or the sun is bright for hours, substantial surplus power may be produced, increasing the challenge for utility companies to manage their grids. These conditions often necessitate utilities paying renewable power producers to stop shipping their output, especially when electricity demand is low. Alternatively, utilities may require the producer to essentially dump the surplus renewable electricity into markets not served by the utility, which can upset power pricing. As a result of the growing surplus power potential, renewable power producers and utilities are searching for opportunities to use that surplus power, which presumably has an extremely low cost, to increase energy storage for those times when renewable power is not available. With many wind and solar facilities located offshore, where presumably the amount of intermittency is less than onshore, the idea is to install electrolyzers that can break water into oxygen and hydrogen molecules. The latter can be used as an energy storage source for later conversion back into power.
Daniel Muthmann, head of Strategy, Policy and Communication at Open Grid Europe (OGE), offered some views about the economics of hydrogen. OGE is the pipeline business of E.ON Gastransport, which was renamed in 2010. In 2012, it was sold to a consortium of international investment funds. Today, it operates one of the largest European gas pipeline networks, making it an integral part of the continent’s energy system. As Mr. Muthmann highlighted in his presentation, his pipeline network can move any type of molecule, either hydrogen or natural gas, meaning that development of a hydrogen-based economy can avoid having to invest in a new energy infrastructure system. He acknowledged that in order to complete a European-wide hydrogen economy, there would need to be additional pipelines added to the existing OGE system. We also don’t know how much of OGE’s current pipeline network might need to be replaced with new pipe to overcome possible failure due to the pipe becoming brittle due to interaction with hydrogen.
Exhibit 9. Why Hydrogen May Become Less Costly
Source: OGE
Exhibit 9 (prior page) shows the many locations of wind and solar energy projects that can be used to produce hydrogen. Besides using offshore water sources, hydrogen can be created by breaking down the methane molecule of natural gas, which can be imported into Europe either in liquefied form (LNG) or via pipeline. The resulting hydrogen output is labeled “blue hydrogen,” but it is not as environmentally friendly as “green hydrogen,” which is produced entirely from renewable energy and water. Based on the plans for new renewable energy projects, it would appear that there would be substantial capacity to produce blue and green hydrogen.
To meet Europe’s hydrogen demand in 2050, Mr. Muthmann showed the amount of new renewable energy investment necessary. To supply the 1,300 terawatt-hours of annual green hydrogen demand, assuming a 50/50 split between wind-generated and solar-supplied power, the energy industry will need to add 23,000 wind turbines and 4,650 square kilometers of solar panels. To put these investments in perspective, the estimated number of new wind turbines would equal all the offshore wind turbines already in place worldwide. With respect to solar panels, the presentation said that the area they would cover would equal just under one-half of one percent of the combined surface area of Spain, Portugal, Italy and Greece. Those four countries contain 398,315 square miles of surface, meaning the required solar panels would be spread over 1,792 square miles. Can all of these facilities be built? Sure. But one needs to also recognize that both wind turbines and solar panels have relatively short lives – 20-25 years. That means the generating capacity will need to be replaced frequently – in reality, constantly, given the scale of annual replace work. The presentation did not offer any estimate of the magnitude of the investment necessary to build all the additional wind turbines and solar farms.
Based on cost projections for wind turbines and solar panels, we estimate the following costs for a renewable energy system to produce hydrogen: between $687-$916 billion for the wind turbines and $1.374 trillion for the solar panels. Together, that totals approximately $2-$2.25 trillion. The cost projections we used came from marketcap.com for wind turbines and Solar Power Now for solar panels. We believe the wind turbine estimate is for a typical onshore turbine. Offshore turbines will be more costly, especially depending upon the water depth in which the projects are installed, although they are generally more productive. When Professor Gordon Hughes completes his study of the cost of the U.K. offshore wind farms, we will be in a better position to estimate the wind turbine share of the required investment. The cost estimates relate only to the cost of producing the renewable power generating capacity, and do not include any costs associated with generating the hydrogen, nor transmission and storage costs.
Exhibit 10. Contribution To Hydrogen From Renewables
Source: OGE
In pitching the advantage of hydrogen over relying entirely on renewable energy, Mr. Muthmann pointed out that one 48-inch natural gas pipeline has the transportation capacity of 24 gigawatts of energy. That is the equivalent of the amount of power moved along eight high-voltage power lines. If the pipeline were repurposed for hauling hydrogen, it would still have the energy-equivalent capacity of 80% of the natural gas pipeline, or six high-voltage power lines. Since pipelines are underground, they eliminate the high-voltage power line transmission towers. Quite possibly, a significant selling point for the hydrogen solution is its ability to be stored. The existing natural gas storage caverns in Germany are able to store sufficient supplies for three months of gas demand. This compares with all the current electricity storage (battery and pumped-water) capacity that totals less than one hour of power.
Exhibit 11. The Pipeline Advantage Over Power Lines
Source: OGE
These are all positive selling points for hydrogen as opposed to a totally renewable-based electric energy system. But, as pointed out in Dr. Kehler’s presentation, decarbonizing the heating demand within Germany will be a massive undertaking. All the existing renewable energy capacity in Germany, if devoted just to replacing building heating needs, accounts for less than 25% of the market. Even with adding insulation to buildings and heat pumps, there will need to be about a tripling of the existing wind and solar generating capacity in Germany. That will consume significant land area, besides representing a massive financial investment. It still doesn’t address the need for renewable generating capacity for all other energy needs such as electricity and transportation, let alone industrial power needs.
Exhibit 12. Germany’s Massive Heating Energy Problem
Source: Kehler
While we understand the push from the EU for hydrogen and the aggressive support of the gas industry, the economics remain a challenge that receives little current attention. Most of the studies for hydrogen’s potential focus on comparative economics in 2030 or 2050. For example, a recent Bloomberg New Energy Finance (BNEF) study says that renewable hydrogen could be produced for $0.70 to $1.60/kilogram (kg) in most parts of the world before 2050. BNEF said those prices would equate with natural gas priced at $6-$12 per million British thermal units (MMBtus). According to Hydrogen Tools, a hydrogen analysis web site run by Pacific Northwest National Laboratory, one kilogram of hydrogen is equivalent to the energy of 421.66 cubic feet of natural gas, which reflects the fact that hydrogen has only about one-third the energy density of natural gas. While we will not speculate on the price of natural gas in 2050, at today’s approximately $3/MMBtu price, hydrogen is nowhere near being competitive.
Possibly more interesting are observations from a paper by Armin Schnettler, the executive vice president and CEO of the New Energy Business at Siemens Energy, a company actively pioneering the development of hydrogen power. He discussed his company’s efforts to promote hydrogen R&D projects. In characterizing the state of hydrogen, he wrote: “As time moves on, hydrogen can become as big as wind and solar, but in terms of maturity (market and technology), it is 15 to 20 years behind the more established renewable technologies.”
In his and his company’s view, the real future for hydrogen is likely in the transportation sector. Hydrogen offers a competitive advantage over batteries for electric vehicles (EV) in both recharging times and driving range. He sees this as especially compelling in the medium- to high-duty transportation market. “Hydrogen’s low weight, long driving range, and fast recharging is especially relevant for heavy-duty vehicles and trains.”
According to Mr. Schnettler, for hydrogen to meet the critical price points to be competitive with alternative fuels, he sees three primary challenges. They are: the cost of electricity, the loading factor of the electrolyzer plant, and the capital and operational costs. Pointing to the issue of the cost of electricity, which represents 70% of operational costs, the development of renewable energy sources will help overcome that hurdle. He suggests that in areas that have advantageous renewable energy conditions, the costs to produce green hydrogen could already be about €3 ($3.54) per kilogram. While appearing attractive, the cost is nowhere near competitive with current transportation fuel costs. As pointed out by energy consulting firm RBN, the cost to fill up a fuel-cell powered vehicle in California, essentially the only market for these type vehicles, it costs about $15/kg, at the low end.
Furthering his argument that hydrogen is better suited for reducing transportation carbon emissions, Mr. Schnettler commented on the view of some proponents for the fuel’s use in the electricity market. He wrote:
“Today, there is probably no economically viable business case for producing hydrogen specifically for having it re-electrified directly afterward in a hydrogen-capable gas turbine – and efficiency wise, today it would not make sense either, because there are more applications with higher CO2 reduction potential at lower total cost.”
He does see the potential for hydrogen to be used for backup power when renewables, such as wind, are unavailable. However, he sees that solution as a mid- to long-term future for hydrogen, as the drive to decarbonize the economy needs to focus on the transportation sector, because more than half of global emissions come from industry (manufacturing processes), transportation, and the construction (cement) business. In Mr. Schnettler’s view, these sectors offer greater near-term potential for hydrogen, and probably can handle the more expensive fuel due to the greater concern over cutting carbon emissions. This may be a more realistic outlook for where and how the hydrogen economy will evolve. However, his assessment, which we believe is also Siemens Energy’s position, of hydrogen’s market and technology maturity being 15-20 years behind wind and solar energy, is sobering.
Mr. Schnettler’s final comments are important in assessing the development of the green hydrogen market. He wrote:
“Going forward, green hydrogen will command a premium price when compared to its less environmentally friendly hydrogen counterparts – blue and grey. The early stages of any technology curve must have some support, much as was seen in the early days of wind and solar power. But in the medium- to long-run, hydrogen must and will stand on its own legs and be viable without external support. When exactly that will happen, depends on several factors, including the adoption rate, economies of scale, and the regulatory frameworks.”
The EU is working hard on the regulatory framework to ensure that the financial support for hydrogen is in place, such that adoption rates are quick, which will help create economies of scale that should lower the fuel’s future cost. Without that happening, people will be saddled with energy costs consuming a greater portion of their incomes, and weighing down the pace of industry and commerce that will slowly sap economic growth. We are just now entering that phase, and the public will increasingly be challenged to either accept or reject the high cost of hydrogen. However, ignoring the development of a hydrogen economy would be foolish. Expecting it to end fossil fuel use anytime soon would also be a mistake. The energy market transition is well underway, but much like every past transition, the old fuels will retain a significant position in the future energy slate. This is a critical point missed by those believing fossil fuels will disappear in the next 20 years.
Will LNG Become A Fuel Of Choice For Shipping? (Top)
The United Nations’ International Maritime Organization (IMO) has been driving the global shipping industry to reduce its emissions. The most recent push, effective January 1 of this year, was to force all ships to switch from burning high-sulfur fuel oil to burning either low-sulfur fuel oil or some other lower-carbon fuel. They can also continue to burn high-sulfur fuel oil, but install scrubbers that remove the sulfur from the exhaust gas from burning the polluting fuel oil. One of the lower-carbon fuel oil options is liquefied natural gas (LNG). Its increased use is part of the global transformation of the world’s petroleum energy mix from high-carbon emission fuels to lower-carbon fuels.
Exhibit 13 (next page) shows graphically the latest breakdown of the world’s carbon emissions by sector in 2016, according to work done by Climate Watch and the World Resources Institute. It shows that the global transportation sector was the third largest emitter of CO2, after industry and buildings, at 16.2% of the estimated 50 billion tons per year of greenhouse gas emissions. Of that total, the global shipping industry represented 1.7%, or roughly 850 million tons, which was slightly below air transportation’s 1.9% share.
Exhibit 13. Shipping Is Small Share Of Global Emissions
Source: Our World In Data
The IMO’s push to reduce emissions – starting with sulfur – is expected to ramp up in future years as the organization is striving to cut shipping’s carbon intensity (i.e., its emissions per transport work) by 70% by 2050. It also hopes to reduce the industry’s total GHG emissions by at least 50% compared to 2008 levels. To achieve these goals, between 30% – 40% of all shipping fuel bunkered will need to be carbon neutral.
The sulfur cap on shipping requires that all ships use a fuel containing no more than 0.5% sulfur (SOx), or employ a scrubber. Low-sulfur fuel oil is essentially compliant diesel fuel. The switch, which requires the refining industry to significantly increase its clean-diesel output and make sure that it would be available in the world’s ports, had shipowners and regulators concerned about the impact on the economics and operation of the shipping industry. Would ships be able to find low-sulfur fuel oil everywhere they traveled? Moreover, would the fuel’s cost create economic challenges for the global shipping fleets? In the initial months of 2020, there appeared to be few incidents of a lack of fuel availability, and the cost of clean-diesel did not skyrocket, as some forecasters had predicted.
The picture for the shipping industry has been much more impacted by Covid-19’s economic shutdowns that have cut global oil demand drastically. It has created serious challenges for global trade, as consumer spending fell, as did global trade. That meant fewer ships were actively trading and port activity dropped.
Pre-Covid-19, the global shipping industry accounted for approximately four million barrels per day of oil demand, or roughly 4% of global energy use. Although all segments of the transportation industry were significantly hampered by the coronavirus, the shipping sector seems to be recovering, and possibly quicker than other oil-consuming sectors, as economic lockdowns ease and global trade increases.
LNG offers long-term promise for cutting carbon emissions. While practically eliminating emissions of sulfur and nitrous oxides, it also reduces CO2 emissions. If the global fleet were to switch to LNG tomorrow, the immediate CO2 reduction would be 15% compared to 2018 fleet statistics. An April 2019 independent analysis of LNG shows that its lifecycle GHG emissions reduction is up to 21% compared to conventional ship fuels. It is anticipated that these reductions will increase as technology improvements further reduce methane slip, the unintentional releases of methane from ship engines.
The shipping industry is not overlooking the potential for LNG as a solution to its long-term GHG emissions challenge. As of early this year, there were 175 LNG-fueled ships currently operating, excluding the approximately 600 LNG carrier fleet, the majority of which are LNG-fueled. There are 203 LNG-fueled ships on order, and 141 LNG-ready vessels in operation or on order. This would support the estimate by Reuters that the world’s LNG-fueled shipping fleet will grow to over 1,000 vessels by 2030. Virtually every category – cruise ships, container vessels, crude and product tankers, and bulk carriers – is represented in the LNG-fueled fleet. Additionally, ferries and bunker vessels are being powered by LNG. To further appreciate the LNG fleet growth, SEALNG, a UK-based multi-sector industry coalition aiming at accelerating the adoption of LNG as a marine fuel, indicates that as of February 2020, LNG can be delivered to vessels in some 93 ports with a further 54 ports in the process of facilitating LNG bunkering investments and operations. The growth of port services for LNG has been rapid. As of early February, there were 12 LNG bunkering vessels in operation with a further 27 on order and/or undergoing commissioning.
Each article and report we read has a different LNG-fueled vessel number, likely due to the timing of data collection. A report by the International Council on Clean Transportation (ICCT) showed two charts about the LNG fleet and its growth. They are based on data collected by IHS Markit through mid-2018, including vessels on order or under construction at that time. One chart shows the cumulative growth in the total number of LNG-fueled vessels, while the other chart shows the fleet growth by vessel type. We expect a chart prepared today would show a greater number of new vessels entering the fleet in 2021. That said, these charts provide an interesting perspective on the LNG-fueled shipping fleet.
Exhibit 14. Growth Of World LNG-fueled Shipping Fleet
Source: IHS Markit
Exhibit 15. Growth Of LNG-Fueled Fleet By Category
Source: IHS Markit
Some of the vessel owners adding LNG-fueled vessels to their fleets are entering into long-term supply arrangements with oil companies. France’s CMA CGM is adding nine of the world’s largest container ships powered by LNG, as well as five slightly smaller LNG-powered container vessels, that have just started to enter service and will continue through 2021. It recently took delivery of its first large LNG-fueled container ship, Jacques Saade, which is capable of carrying 23,000 20-foot equivalent units (TEUs) and promptly established a world record for the largest load of filled containers on an LNG-powered ship.
Exhibit 16. World’s Largest LNG-fueled Container Ship
Source: CMA CGM
The company said, “The choice of LNG must be considered as part of the long-term strategy of the CMA CGM group to comply with future regulations, and to demonstrate the importance the group gives to environmental protection.” To supply its growing LNG-fueled fleet, the CMA CGM group entered into an LNG supply contract with French oil company Total in 2017, at the same time it placed its order for LNG-fueled container ships. According to officials with the group, the purchase price of the LNG bunker is lower than that of heavy fuel oil (HFO), however, the cost of delivery (supply ship and gas terminal operations) is higher, but the overall fuel costs are similar. As Total’s head of its integrated LNG offering noted, “The big challenge for this nascent market lies with its logistics infrastructure, which still needs to be optimized.”
To deal with this challenge, oil companies and fuel suppliers are investing in LNG bunkering vessels. According to SEALNG, at the beginning of 2019 there were just six LNG bunkering vessels in operation around the world. That number doubled by the beginning of 2020. As of September 2020, the fleet had grown to 15. There are a further 25 vessels on order or under construction due to enter service by the end of 2021. The growth of this fleet will be key to the growth of the LNG-fueled vessel fleet. For example, Carnival Corporation, which services more than half the world’s cruise business, has decided that LNG will be the fuel of choice for its future vessels. In April, Carnival’s Aidanova, its latest addition to its fleet, became the world’s first cruise ship to bunker LNG in the port of Barcelona. The ship is propelled by four dual-fuel engines and, while it continues to carry marine gasoil (MGO) fuel for safety reasons, it has been running on LNG for 98% of the time. The vessel sails primarily through the western Mediterranean and the Canary Islands, but it is not able to refuel at all ports along its route. Management is hopeful that as more LNG-fueled vessels enter the world fleet, LNG bunkering services will grow, but in the meantime, Carnival has contracted with Shell Oil Company to handle its bunkering needs in the region.
A potential problem facing the global shipping industry is the charge that methane slip actually may lead to LNG becoming a much greater polluting fuel than projected. The ICCT report was published in January 2020 in advance of the February meeting of the IMO’s Pollution Prevention and Response Subcommittee. The report stated that LNG emits between 70% and 82% more GHG emissions over the short-term compared to clean distillate fuels (MGO). The authors of the report consider LNG to be a disaster as a solution to carbon emissions. They were particularly critical of the most popular engine type as being the worst emissions offender due to it having the highest rate of methane slip. This engine is especially popular with cruise ships, whose owners promote them as having significant climate benefits.
The Pollution Prevention and Response committee held its February meeting. In reading the meeting summary on the IMO’s web site, there is no reference to any recommendations regarding LNG having been sent to the Marine Environment Protection Committee, which was scheduled to meet at the end of March. This meeting was postponed due to Covid-19, and was rescheduled for a virtual meeting last week. We were unable to find any agenda for the meeting to see if the topic of LNG was to be discussed.
While we wait to see what, if any, response there is to the ICCT report, it is important to have a grasp of its conclusions. We are not sure exactly what expertise the authors have, as it becomes evident that they rely on others for estimating the carbon emissions of the upstream oil and gas business, as well as the technical aspects of the engines studied. We also know that the authors based their work on the Intergovernmental Panel on Climate Change’s (IPCC) worst case environmental analysis.
The gist of the conclusions is captured in the chart in Exhibit 17 (next page) that shows the life-cycle GHG emissions by engine and fuel type, the 20-year global warming potential (GWP), and the higher methane scenario. The three engines studied in depth are the high-pressure injection dual fuel (HPDF) and the low-pressure injection dual fuel (LPDF) in two formats – two-stroke piston versus four-stroke piston engines. One was calculated to run at slow speed and the other at medium speed. The ship’s speed has become an important consideration, as methane slippage seems to be accentuated when vessels steam slowly, something that was done during the worst of the coronavirus as global trade slowed and shipowners sought to reduce operating expenses.
Exhibit 17. LNG-Fueled Ship Engine Methane Slip Issue
Source: ICCT
As the chart above suggests, the major problem is for LPDF engines due to their methane slippage. The report contains two appendices discussing engines and how they may leak or fail to burn completely the LNG entering the cylinders. In the discussion, there are points about new engine designs that are either now being installed or will be available for use next year that may mitigate much of the methane slippage. To counter this engine technology progress, the authors relied on data about vessel age. According to their data, 37% of merchant ships are five to 14 years old, representing 54% of the tonnage. In their mind, this attests to a fairly slow replacement rate. We do not know what database they relied on for this conclusion, but shipping goes in cycles and fleets of vessel types often are replaced at shorter lives than suggested. In fact, an article in The Wall Street Journal last week highlighted how the economic downturn due to coronavirus has boosted scrapping of cargo vessels and cruise ships. While there have been 557 ships demolished this year, compared to 889 last year, both years are only a fraction of the 1,996 vessels scrapped in 2012, all data from VesselValue, a maritime reporting service in the U.K. The 2012 scrapping total was the result of the shipping industry’s removal of a vessel overhang that existed after the 2008 financial crisis. Is it likely that a large number of vessels will be scrapped in the next year or two because of Covid-19? In addressing the issue of methane slippage, there are two important questions to be asked: 1) Are existing LNG-fueled ship engines capable of being retrofitted to reduce or eliminate methane slip, and 2) Will the world’s shipping trade recovery dictate an increase in the pace of vessel scrapping?
In an attempt to present a balanced assessment of the ICCT report, we are quoting its final conclusions.
“We compared the life-cycle GHG emissions of LNG, MGO, VLSFO [Very Low Sulfur Fuel Oil], and HFO [Heavy Fuel Oil] for engines that are used in international shipping, including on cruise ships. The maximum life-cycle GHG benefit of LNG was a 15% reduction compared with MGO over a 100-year time frame. Note that this is only achieved by ships using an HPDF engine and only if upstream methane emissions are well-controlled. Controlling upstream methane emissions could be challenging as more LNG production shifts to shale gas and given recent evidence that upstream methane leakage might be higher than previously thought.
“Using a 20-year GWP, which better reflects the urgency of reducing GHGs to meet IMO’s climate goals, and factoring in higher upstream and downstream emissions, we found no life-cycle GHG emissions benefit to using LNG for any engine technology. HPDF engines using LNG emitted 4% more life-cycle GHG emissions than if they used MGO. At least 90 ships that are in service or on order use HPDF engines. The most popular LNG engine technology—LPDF, four-stroke, medium-speed, which is used on at least 300 ships and is especially popular with LNG-fueled cruise ships—emitted 70% more life-cycle GHGs when it used LNG instead of MGO and 82% more than using MGO in a comparable MSD engine.’
LNG is making impressive inroads into the global shipping fleet. The demand for LNG-fueled ships is a direct response to the pressure on the global shipping industry to clean up its carbon emissions. While not a major contributor to global emissions, a shift to cleaner-burning LNG will help the industry. Prior to the outbreak of the coronavirus that derailed the world’s economies, energy consultant Wood Mackenzie had offered the view that LNG would power a growing proportion of the fleet in the future. They suggested that the demand increase, while stark in its growth rate, would have a gradual impact on future oil demand. In their forecasting, late last year, the firm projected a 70% increase in LNG bunkering in 2020, but it only equated to a displacement of just under 100,000 barrels per day. The question is whether the trend toward LNG-fueled ships might be derailed by an IMO decision that the fuel is not as clean as advertised. The agency might still allow the transition to occur, but put more regulations on the engines used. It also might allow these ships to operate until the IMO’s and Europe’s preferred hydrogen fuel system is established toward the end of this decade, as it could be burned directly as a fuel. Either way, we do not see shipping ending its growth, although its growth rate may slow, but the pressure will continue to build on cleaner fuels for ships. At the moment, LNG is the best alternative. Oil demand will be the loser, but, as pointed out earlier, the rate of demand destruction will be slow rather than a one-off demand implosion.
Transportation Mixing Green And Fossil Fuel Power
Exhibit 18. Should Elon Musk Be Worried?
Source: You Tube
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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.
