Author: Brynne Kelly
Crude oil has been the primary fossil fuel energy source consumed globally since the 1960's (when it overtook coal). As the current incumbent, it has the most to lose. The rapid evolution of interest in climate change has completely upended the status quo of energy production in favor of alternative energy sources deemed to be 'cleaner'. These alternative energy sources begin as wildly more expensive passion projects and eventually appear cheaper as regulatory burdens on legacy energy sources increase. These regulatory burdens eventually lead to stranded or impaired assets that are cleverly spun off into 'bad banks' that attract little investment. In addition, the upcoming presidential election highlights the fact that now more than ever, we are a mere election away from complete policy change that leads to even stricter environmental regulation.
We saw this happen in the electric power generation industry. In April 1996, the Federal Energy Regulatory Commission (FERC) issued two orders (888 & 889) that changed the landscape of how electricity is generated, transmitted, and distributed throughout the North America. Order 888 established 2 key changes:
An acknowledgment that barriers to competitive wholesale markets may exist and that those barriers must be removed
Permit utilities to recover stranded costs associated with providing open access to transmission
In order to facilitate competitive wholesale markets, Order No. 888 specified the unbundling of a utility's operations, separating generation, transmission and distribution.
In the initial years following Order 888, wholesale markets became active and on-peak power prices soared. This led to an interesting development. Utilities believed that wholesale prices would exceed retail prices (tariff rates) and wanted access to said wholesale prices. To do this, regulated utilities began creating unregulated subsidiaries where they could move generation assets (typically coal and nuclear) and begin to capture wholesale market prices.
It's hard to even imagine that anyone would make such a prediction regarding wholesale vs retail prices, but we will cut them some slack considering no one thought the deregulation of electricity markets would begin and end at the wholesale level (it's a bit more complicated than that, but not requiring a deep dive here).
As expected, competition at the wholesale level drove down prices and led to severe under-performance of utility unregulated subsidiaries. What followed next was the growth in US natural gas production and gas-fired power plants and the souring of consumers and policy makers towards fossil fuel. Suddenly, the assets that were transferred to unregulated subsidiaries and were touted as the future growth engine were unprofitable and toxic. Some utilities dissolved their unregulated subsidiaries and reabsorbed the assets into their retail base, others took the 'bad bank' approach.
This is a common practice in all markets. The practice of creating a 'Bad Bank' or a "Spin Co" to house legacy business activities whose risks are rising, costs are increasing and profits are decreasing is nothing new. Such spin-offs or shell companies help insulate the parent company from liabilities associated with decommissioning or abandonment. A company is basically saying “you’ve made our business extremely risky, so we are going to put the risky parts in a separate company”. The decommissioning costs for nuclear are rising quickly, especially after the incident at the Fukushima Nuclear Power plant in Japan in 2011, which became the second worst nuclear accident in the history of nuclear power generation. Because of this, most nuclear power plants have been sold or spun-off under separate companies.
Utilities turned their focus back towards acquiring retail customers (since they pay the highest price for their generation) and high-incentive renewable investments. Coal and nuclear power plants, which still make up the lions-share of the electricity produced, suddenly became a political and regulatory nightmare.
Are we starting to see something similar in the oil industry as players begin to distance themselves from high-risk markets?
Last week, California Resources Corporation (CRC), one of California's largest oil producers, filed for Chapter 11 bankruptcy. As a reminder, CRC was formed in April 2014 as a corporate spin-off of Occidental Petroleum, which took over Occidental’s California oil and gas wells. In April 2018, the company acquired the interest in the Elk Hills Oil Field, previously held by Chevron Corporation, for $460 million and 2.85 million shares.
On 15 July 2020, CRC filed for Chapter 11 bankruptcy with $5 billion in debt.
This leaves the fate of its approximately 18,500 active and idle oil and gas wells uncertain. According to some sources, properly plugging and abandoning these wells could cost over $1.2 billion. Although operators are obligated to plug and abandon their wells, its not uncommon for firms in bankruptcy to try and shed these substantial legal liabilities wherever possible.
Statewide, the California Council on Science and Technology estimates that cleaning up California’s approximately 107,000 oil and gas wells would cost over $9.2 billion, yet the bonds that are supposed to cover these costs total only about $107 million.
During times of status quo, decommissioning and abandonment costs are of little concern. Only when the shift in consumer sentiment becomes too big to ignore do these costs begin to generate quiet, yet sneaky exit strategies since the 'last one to leave the party' is usually left holding the bag. In February, BP announced that it will become a net zero company by 2050 or sooner. Over the last year or so, we have seen many of the oil majors begin to either shed some of their fossil fuel assets or 'regrade' them to more flexible higher-returning plays.
Ironically though, fossil fuels still accounted for 84% of the world's primary energy consumption in 2019, according to BP's statistical review of world energy 2020. Currently only around 5% of global energy consumption comes from renewables.
Just like the utility industry though, what's 'old is old' even if it is still the primary backbone of energy consumption. We even see a nod to an uncertain oil future in the financial statement footnotes of energy companies such as these in Berry Corporations 1st quarter results:
Risk factors include:
the California and global energy future, including the factors and trends that are expected to shape it, such as concerns about climate change and other air quality issues, the transition to a low-emission economy and the expected role of different energy sources;
the impact of current, pending and/or future laws and regulations, and of legislative and regulatory changes and other government activities, including those related to drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of our products;
Companies are resigning to the fact that all eyes seem to be on that 5% renewable bucket and the need to associate with that in order to garner favor from investors.
Where does this leave us going forward? There are several routes the industry could take.
Become the lowest cost provider
When your product is politically out of favor, you are relegated to competing as the lowest cost provider. We saw this in the electricity markets. Natural gas worked it's way into the generation stack by way of being either the lowest cost input or gaining market share through regulations like the Clean Power Plan that mandated the retirement of coal plants. Renewable sources, however took first place in line as federal mandates and tax credits made them the first to be dispatched if they were running.
In an era of technology and 'choice', oil prices that rise more than inflation or end-user demand for products have the potential to choke refining margins, which will cause refiners to look for alternative business models.
Social distancing from legacy oil production could lead to integrated oil companies becoming less 'integrated'. The focus may shift towards investment in refining flexibility - doing more with less or doing more with less expensive inputs. Better yet, refiners may begin to focus on investments in processes that are tied to tax incentives as the power generation utilities have done.
Logistics
The environment for new pipeline investment is rapidly deteriorating due to increased regulatory hurdles and pandemic-induced uncertainty in future demand. Regional spreads are narrow, yet product still needs to be moved from production centers to demand centers. Location of production assets now, more than ever, need to be positioned as close to end-user demand as possible to avoid being undercut by a lower cost, more strategically located provider.
Looking at the WTI/Brent spread over the past 5 years, the Brent premium is sitting at around $2.50/bbl. Factoring in transport costs, this doesn't leave much room for WTI to come in as the lowest cost provider internationally. The is a far cry from the WTI discount seen in 2018 and 2019.
The 12-month term structure of the spread has had some volatility over the past week (Friday's close in purple), but even a year from now, the futures spread only widens-out to around $3.30 Brent premium over WTI.
This could lead to overseas investments in oil production - closer to demand centers, becoming the better option than those in the US that are burdened with travel risks and expenses.
Options
Given the price action since March, at $40, WTI is enticing option activity. The $40 level is high enough due to the large, swift rally off the lows to get people to still believe in the upside story. But, with pandemic fears still looming, at $40, prices are also high enough for people to believe there is room for another big selloff.
As a result, implied volatility still hovers around 40%, which is high given the tight range oil has been in since the beginning of June.
As upside potential is capped at the moment by the potential supply overhang that looms via inventory and via production restraints, the push/pull at the $40 price level could result in a road to nowhere.
Operation vs Abandonment
With the abrupt halt in demand due to the pandemic, US producers are faced with the need to shut-in production. However, an inactive well comes with it's own set of economic woes.
For example, in Texas, the Texas Railroad Commission (“Commission”) oversees plugging and abandoning operations.
"Inactive wells are required to be plugged and abandoned within a year after drilling or operations on them cease, unless the Commission approves an exception. 'Inactive' is a status that describes a particular well. For purposes of plugging requirements, an inactive well is one that meets these two characteristics: (1) for 12 consecutive months or longer, the well has not reported production of at least (a) five barrels of oil or 50 Mcf of gas during at least three consecutive months, or (b) one barrel of oil or one Mcf of gas each month for 12 consecutive months; and (2) it is not permitted as a disposal or injection well.[ Accordingly, a well that is shut-in may become inactive, but its status as “shut-in” under a lease may not in itself answer whether the well can be classified as “inactive” under Commission rules."
The risk in shutting-in a well is that it's unknown when conditions will exist that allow it to return to production. State and federal regulations require well operators to post bonds that are released only when they have properly decommissioned their wells. Despite this, several states have long lists of orphaned wells.
When the cost of decommissioning a well exceeds the bond amount, the operator lacks the incentive to clean up and might choose to leave the well in a state of temporary abandonment instead (pending a decision to restart the well or close it permanently). In the meantime, operators may become financially insolvent or records may be lost, leaving the state with the liability, which often exceeds the bond amount.
Which brings us back to the 'Bad Bank' concept discussed earlier. Will we see producers quietly spin-off production assets in order to distance themselves from liability?
Doing more with less capital inflows/Attracting new capital
Companies which focus on exploration and production have faced their own pressure to boost profits now rather than growth later, given uncertainty over future demand. Private-equity firms no longer have an easy exit strategy for energy investments because uncertain regulation and demand make it hard to envision a successful listing or sale to an oil major in a few years’ time.
In order to attract capital, the oil industry could go the route of the utilities and begin to re-brand themselves as innovators, or at the very least as a service provider more than a producer. Utilities have determined that the real profit to be made is in transportation and distribution. How might that look when applied to the refining industry?
Conclusions
There is a possibility that the pandemic has pulled forward structural changes that were inevitable. We have seen this happen in other industries. As a result, short-term markets could completely disconnect from term markets. Short-term price spikes/dips caused by the mismatch of supply and demand as the world returns to more normal operations may do little to longer-term prices. We could see temporary bouts of backwardation that are less about the market being bullish and more about a lack of faith in the future.
Inventory
Weekly Changes
The EIA reported a total petroleum inventory DRAW of 11.10_million barrels for the week ending July 9, 2020. Crude oil alone posted a weekly DRAW of 7.50 (excluding SPR).
Year-to-date, total Inventory additions stand at a BUILD of 156.40 million barrels (vs 167.50 last week). This is only the 5th weekly draw of crude oil inventories this year.
Commercial Inventory levels of Crude Oil (ex-SPR) and Refined Products are high everywhere as discussed earlier (except those at Cushing).
Lee Taylor - Technical Levels
BRENT
Resistance: 43.47 / 45.18 / 43.97
Support: 41.98 / 39.70 / 36.49
The last few weeks have not brought volatility or excitement to the energy marketplace like it has in the equity markets. Short term support is found at 41.98 but major support rests at 39.70 – a level we haven’t broken through on for four straight weeks (on the weekly charts) Resistance is easy to find as one can just focus on the gaps above – we find the same gap in the weekly chart and the daily September as we do the daily continuation which is 43.97-45.17. Sep/Oct Brent held the -26 level and we feel it will continue to trade between that and flat as we approach expiry.
WTI
Resistance: 41.72 / 42.49 / 46.37
Support: 39.58 / 38.92 / 37.06
There is still one gap left in the crude market which appears in the August daily chart between 41.63 to 42.17. We have discussed the gap ad nauseam to date, but every week it appears to get heavier, stronger and/or more burdensome to the crude oil market. Our support and resistance levels remain, but look carefully to the support numbers as a move back toward 36.35 seems imminent. We continue to give our guidance for the front two crude spreads in which Aug/Sep and Sep/Oct WTI will remain stuck in a range between -25 up to flat. We do not see that changing unless a major move in flat price occurs.
RBOB
Resistance: 1.2448 / 1.2641 / 1.2796
Support: 1.1980 / 1.1527 / 1.0981
Once the Bayway news ended up as a small after-thought in the middle of the paper, the gasoline market was able to resume its sell-off. After selling off early Friday, it rallied again on more Bayway news. If this market begins to trade off and break through support levels, our first main objective will be 1.0581. RBOB spreads are having a difficult time finding a bid but we did see some short covering especially in Sep/Oct RBOB as it nearly traded down to 714, then rallied to settle at 793.
HEATING OIL
Resistance: 1.2452 / 1.2583 / 1.2771
Support: 1.1994 / 1.1850 / 1.1328
August Heating Oil stayed in a 5-cent range last week as the entire energy complex struggled with summer doldrums. Even if my support and resistance levels come into play this week or next, the real levels lay even further outside this picture. The bottom of the gap remains above on the continuation chart at 1.3023, but the support level is 1.0612. Major support seen below in Aug/Sep heat between -147 to -160.