Oil below $20 USD per barrel – what caused this?

The following is a tutorial on the economics and financing of oil and gas. It looks at the market over the last two years, how several factors have contributed and the role that the following have played into it:

1. OPEC;
2. Production and inventory supplies;
3. Global economy;
4. Deals, treaties and sanctions.

Saudi Arabia has increased their production and cut their price to get everyone at the table, not just OPEC+, to start talking about production. OPEC+ is composed of 11 OPEC members and 10 non-OPEC countries including Russia. Russia does not want to do any more cuts in production because they see non-OPEC+ countries trying to grab more of a market share after OPEC+ has done production cuts.

History of oil and boom and busts

In the early days of refining oil, the market was highly competitive with numerous small independent refiners competing harmoniously with each other, so their customers got kerosene at a reasonable price (Epstein, 2011a). The issue was anyone who could buy the equipment for $300 could refine oil into kerosene. This caused many to produce impure kerosene which was highly explosive and caused numerous deaths (Epstein, 2011a). With all these people entering into the refinery business, it became oversaturated and the refining capacity became greater than the supply of oil causing a drop in the price of kerosene (Epstein, 2011a).

Rockefeller came along and formed Standard Oil with the goal of creating standards and efficiencies for the refinement of oil. Rockefeller’s strength was he always put those that worked for him to the task of discovering ways to lower every cost, while continuously seeking more sources of revenue (Epstein, 2011b).

One of things Rockefeller started to do was instead of just selling the kerosene, he started to sell the by-products of crude besides kerosene and established marketing operations in major consumer states and overseas (Epstein, 2011b). Standard Oil with all these efficiencies and strategies gained control of the oil refinery market and was able to control the price.

After the break-up of Standard Oil, the control of the price of oil became the responsibility of the Texas Railroad Commission. In fact, OPEC is modelled after the Texas Railroad Commission. In the 1930’s, the Texas Railroad Commission set the production to control the price just like OPEC does.

Even recently with the differential between West Texas Index (WTI) and Western Canada Select (WCS) being too large, the Alberta government stepped in and curtailed the production of heavy oil. This was done to decrease the differential, even during a time when there was a demand for heavy oil for the complex refineries on the Gulf Coast due to the sanctions against Venezuela, and the decrease in production from Mexico.

Many don’t realize that the oil from the unconventional plays is a light oil. The heavier oil molecule such as black oil is too big to move through the pores of the tight sand plays or unconventional plays.

Implementation of IMO 2020 and effect on oil sands

The complex refineries, which need both light and heavy oil to produce fuels and other derivatives, were trying to take advantage of the stronger margins ahead of the implementation of the new sulfur emissions rules of the International Maritime Organizations (IMO 2020), while the Alberta government was curtailing heavy oil production because of the large differential between WTI and WCS.

IMO 2020 ban ships from using fuel with a sulfur content higher than 0.5 percent for heavy fuel oil or bunker fuel (George and Ghaddar, 2018).  Heavy fuel oil or bunker fuel is used for ships because it is cheap.  It is residue from the crude oil refining process and as such is the dregs of the process.  One of the means to deal with this is to fit a hydrocracker or coker unit so that a refinery produces more distillates with lower sulfur content while reducing the fuel oil output (George and Ghaddar, 2018).

There is concerns that IMO 2020 will reduce the price for heavy oil containing high levels of sulphur, such as raw bitumen from the Alberta oilsands further increasing the differential between WTI and WCS (Healing, 2019).

It is expected that companies that have oilsands upgraders are expected to benefit as the new standards will increase the demand for refined low-sulphur fuels (Healing, 2019).

Heading to a recession: 2019

In September 2019 there were signs that there was a slow down in the economy.  The signs were (Fitzgerald, 2019):

1. The 10-year Treasury note fell below the 2-year yield.  Normally the long-term bonds tend to carry a higher interest rate than short-term bonds (inversion of the yield curve);
2. Gross domestic product in the U.S. slowed down;
3. U.S. manufacturer growth slowed to the lowest level in 10 years in August 2019;
4. Copper was down over 13% in the last half of the year.  Copper tends to be a barometer of economic health because of its use in homebuilding and commercial construction.

Even the International Monetary Fund (IMF) forecasted a slow down in the global economic growth compared to 2018.  The 2019 forecasted growth was just 3.0%, a substantial drop from a growth of 3.6% in 2018, which was the result of reduced production in the industrial sector (Thaioil PLC, 2020).  In 2019 the International Energy Agency (IEA) estimated that the global oil demand in 2019 would only grow by 1 million barrels per day (bpd), which is down 100,000 bpd from 2018 (Thaioil PLC, 2020) because of this slowdown.

Cuts in production

In 2019 OPEC+ cut their production of oil by 797000 bpd in January with the Saudis making the largest cuts to their production which did help stabilize the oil price but the boost in the price fell short of what was expected (DiChristopher, 2019).  Then in November OPEC+ agreed on deeper cuts which equated to another 1.2 MMBPD (CNBC, 2019).

We saw other reductions in oil production due to U.S. sanctions against Iran and Venezuela.  The sanctions against Iran lowered their production by 1.65 MMBPD (Radio Farda, 2019) and the sanctions to oust Venezuela’s President Madura lowered Venezuela’s production by 500000 BPD to 1 MMBPD. 
The primary business partners of PDVSA, the national Venezuelan oil company, are Rosneft, Reliance, Repsol and Chevron.  In 2019, Rosneft was the main receiver of Venezuelan oil, followed by China National Petroleum Corp (Alper et al., 2020; Parraga, 2020).  Cubametales has also received oil from PDVSA and has been sanctioned by the U.S. Treasury Department for continuing to import crude and other products from Venezuela in exchange for helping the Nicolas Maduro regime with defense and security (Mogollon, 2020).

At the same time that OPEC+ was cutting their production, and Iran and Venezuela were affected by sanctions, US crude output continued to climb, with production in November 2019 reaching 12.9 million bpd, a 7.3% increase from 2018 (Thaioil PLC, 2020). 

Trump effect

Since President Trump took office, oil production has increased by 3.2 MMBPD (Scheid, 2019).  This has caused the U.S. to surpass Saudi Arabia in February 2018 and 6 months later they surpassed Russia in crude oil production for the first time since February 1999 (World oil, 2018).  This production came from conventional plays in the Gulf of Mexico and unconventional plays in the Permian, SCOOP, STACK and Bakken. 

It has been projected that at this rate of oil production, the U.S. would overtake the output of Russia’s entire oil & gas sector by 2025 (The Moscow Times, 2019).

President Trump increased oil and gas production and relaxed the Obama-era regulations around GHGs emissions, offshore drilling safety, fuel economy and wetlands (Popovich et al., 2019).  Some see the relaxation of these regulations as the reasons why the U.S. has become so successful with its oil and gas production but this might not be the case because some of these repeals have been tied up in litigation (Scheid, 2019).

The biggest factor that affected production was the end of U.S. restrictions on crude oil exports put in place in 1975, which Obama signed into law in December 2015 (Scheid, 2019). 

We are seeing declines in oil production from (Rapier, 2018):

1. Venezuela and Iran from sanctions;  
2. Mexico, which has been declining over the past 15 years; 
3. Angola, due to technical and operational problems at its key fields (Gupte, 2019);
4. and Norway which peaked in 2001 and has been declining since.

These declines in production have created a gap that U.S. producers have been filling.

State versus Federal Leases

Part of the issue with assigning the success of the oil industry to Trump has been most of the production in recent history has taken place on private and state lands.  The number of federal oil and gas leases in effect has fallen steadily over the past decade (Scheid, 2019).

Response to a possible recession

With a possibility of a global recession, at the start of 2020 major central banks worldwide resumed stimulus by lowering interest rates and buying bonds to increase the money supply.  With this stimulus it was expected economic growth would increase to 3.4% increasing, and with it the demand for oil was expected to grow (Thaioil PLC, 2020).

Unfortunately, at the start of 2020 non-OPEC supply growth for both 2019 and 2020 exceeded demand.  Many globally were expecting this would balance out because of a slowdown in the unconventionals due to pipeline limits, reduced flow from wells drilled too close together, low natural gas prices and high land costs (Cunningham, 2019).

Sanctions against Russian companies

The U.S. also levied sanctions against Rosneft, the largest Russian oil company, for buying Venezuelan oil and against firms building Nord Stream 2, an undersea pipeline that will allow Russia to increase gas exports to Germany (Rumer, 2019).

The sanctions against firms building Nord Stream 2 has caused Germany to accuse Washington of interfering in their internal affairs, while Russia and EU officials also criticized the sanctions.  The main issue U.S. has with the pipeline is they see it will further tighten Russia's grip over Europe's energy supply and reduce the U.S. share of the lucrative European market for liquefied natural gas (BBC, 2019).  U.S. sees a huge demand for LNG by Germany when they shut down all its remaining nuclear power plants by 2022 (Slav, 2020).

The sanctions against Rosneft has made it more difficult for refiners in Asia and Europe to buy from them.  Even a Chinese refinery, operated by Sinochem, refused to buy Rosneft oil.  Sinochem has refused to accept cargoes from any U.S. sanctioned countries such as Iran, Syria and Venezuela, and it will not buy from Kurdistan where Rosneft had commercial interests (Cho and Cheong, 2020).

Rosneft sees the Venezuelan sanctions as being illegal, saying its interests were commercial not political (Cho and Cheong, 2020), and that is why it continued to buy Venezuela oil.  It also sees Chevron operating in Venezuela under a waiver, which the U.S. government will probably not renew in April 2020 (Mohsin et al., 2020).

Price meltdown

Rosneft had some influence with Putin and expressed that they felt that OPEC+ group had lost its significance in balancing the global oil market as countries including the United States, Brazil, Norway, and Mexico raised their production as OPEC+ dropped their production.  Because of this, Rosneft felt Russia should not agree to OPEC+ request for another production cut to support oil prices amid a fall in global demand caused largely by the effects of the COVID-19 pandemic (Prince, 2020).

Some believe with this price drop Russia is targeting not only U.S. unconventional companies but the coercive sanctions policy that has become Trump’s administration foreign-policy weapon of choice (Defterios and Ilyushina, 2019; Harrell, 2019).

Others believe that Saudi Arabia has increased their production and dropped their prices to exercise their dominance and to become the world’s top oil exporter.

This came when the effect of COVID-19 in China caused has significantly decreased the demand for world oil by 3.8 million barrels per day (BPD) from a year prior.  This represented a downward revision of 4.5 million BPD from estimates prior to the outbreak (Sharma, 2020).  Previously, the largest quarterly decline was during the financial crisis of 2009, when Q1 oil demand fell 3.6 million BPD year-over-year (Rapier, 2020).  It is also expected with more countries quarantining and travel between countries essentially halted that the demand for oil in April and May of 2020 may decrease to 30 million BPD (Kool, 2020a).

The following day after Russia said no to cutting its production, the Saudis announced it would ramp up production by about 20 percent, causing the biggest one-day fall in oil prices in nearly three decades (Prince, 2020).

All of this has caused a price war and because of this we have seen huge changes in the price of stock of energy companies, especially with companies that were caring large debt because they had acquired other lands, assets or companies, and generally within the unconventional plays or oil sands. 

Issue with unconventional plays

In North America the new multi-stage horizontal unconventional wells are notorious for the high break even prices and high decline rapidly depleting 70% - 75% of their reserves in the 1st year, forcing unconventional companies to continue drilling new wells to replace lost supply (Domm, 2019), especially if they gained their capital through Reserve Base Loans (RBL) where the loan is secured by the undeveloped reserves of oil and gas of a borrower. The fundamental component of RBL is the valuation of the borrower's oil and gas reserves, which determine the amount of credit the lender will extend to the borrower.

Therefore, it is important to do a geomodel and a reservoir simulation and we need to look at the P10, P50 and P90 cases.  The reserves that we book is a contract between the oil and gas company and the market.  Using a reservoir simulation, calculated from the geomodel, which is calibrated to the production history, can be used to estimate the well’s ultimate recovery (EUR).  EUR is a measure of production potential and companies use this as leverage to borrow capital (Verdazo, 2016).

The steep decline rates of these new unconventional wells result in the production being heavily weighted towards the early life of the well.  The point at which 50% of the well’s estimated ultimate recovery (EUR) is produced (half-life) occurs at 20% of the well’s life.  Half-life of a well correlates strongly with the point where 80% of a well’s value has been achieved (Verdazo, 2016).

The other pertinent issue around the unconventional producers is a lot of the companies have spent more than they have earned over the last decade.  Even some of the bigger companies like Hess, Marathon, Pioneer Natural Resources have posted negative cash flow (Cunningham,2020).

There is a big benefit with the unconventional plays and that is the ability to bring unconventional wells on-line and produce a large portion of reserves in 18-24 months which can greatly increase the payout for a producer.  The producer is also not affected by changes in the price of oil as much since it is a short duration to produce 80% of the well compared to a deep water well which takes years to produce 80% (Lynch, 2019).

2019 not a good year

When unconventional plays began it was easy to get debt financing, as investors were willing to gamble on the idea that wells could start producing in a fraction of the time it took more conventional plays such as deep water, and the payback on unconventional wells was much faster (Domm, 2019).  With hopes that higher oil prices would sustain them, many financed their production growth by becoming deeply indebted (Elliot and Matthews, 2019).
The U.S. producers have no government deciding production levels, and its only constraints are economic and financial.  With oil prices in 2019 hovering around $56 per bbl, some were producing below their break-even level much of the year (Domm, 2019).

The pressures are due to companies struggling to service debt and secure new funding, as investors question the unconventional business model (Elliot and Matthews, 2019). 

The problem is not the price of oil like it was in 2016 when 70 U.S. and Canadian oil and gas companies filed for bankruptcy (Elliot and Matthews, 2019).  The issue is many companies took on debt after the 2016 slump believing the price of oil will just continue to go up.  The issue is debt maturity in the next four years (Elliot and Matthews, 2019).  $9 billion came up near the end of 2019 and about $86 billion will come due by 2024 (Egan, 2020). 

All of this caused U.S. and Canadian oil and natural gas exploration and production companies bankruptcies totaling 55 in 2019 with 33 oil and gas producers: 15 oilfield services and 2 midstream (Khandelwal, 2019).

How oil and gas companies get funding

Companies gain financing depending upon the size of their company.

Small Cap companies

There are a wide range of small cap companies.  Companies that are lacking cash flow from their operations or with their risk concentrated in a single project may have a tougher time raising capital.  To obtain the necessary capital, small cap companies need to show that they can deliver what they promise, have a proven track record and have the ability to communicate the risks and opportunities (Brogan, 2014).  They can raise capital through (Brogan, 2014):

1. IPO;
2. Farm-out transactions;
3. Mergers;
4. and loan arrangements with service providers. 

Some innovative ideas are to buy services by offering an interest in a well that the small cap company were going to drill.  It is through making creative deals that small cap companies can develop into bigger companies.  Small cap companies tend to be the source of innovation which is then picked up by their larger peers (Brogan, 2014).

Mid-to large-cap independents

These companies tend to be involved in the development and production of fields.  They tend to use RBL to obtain capital.
Like the small cap companies, mid to large independents use (Brogan, 2014):

1. RBL;
2. Private equity;
3. Mezzanine financing - hybrid of debt and equity financing that gives the lender the right to convert to an equity interest in the company in case of default;
4. Retail bond - allows companies to raise extra capital by borrowing from an investor at a fixed interest rate for a set period;
5. Convertible bond - fixed-income debt security that yields interest payments but can be converted into a predetermined number of common stock or equity shares;
6. Private placement - sale of stock shares or bonds to pre-selected investors and institutions rather than on the open market.

International oil companies

The primary source of funding tends to be their massive operating cash flows.  Cash flow can be impacted by factors outside the company’s control such as commodity price.  Cash flows don’t tend to cover all the planned capital expenditures, so companies divest non-core assets or parts of the business that struggle to compete for internal capital allocation, and re-invest that capital into higher return areas of the business (Brogan, 2014).

National Oil Companies (NOC)

Some of the National Oil Companies are Sinopec; Saudi Aramco; China National Petroleum Corporation; Kuwait Petroleum Company; Petroleos de Venezuela; Abu Dhabi National Oil Company; Nigerian National Petroleum Corporation and Sonatrach.  NOC’s tend to have larger capital budgets than their International Oil Companies counterparts and are actively seeking cost effective ways of funding their domestic resource development plans or financing the acquisition of international assets.

An example of global diversification of NOC’s is Saudi Aramco, which is the owner of the Port Arthur, TX refinery Motiva, the largest refinery in the U.S. (Wald, 2016).  Motiva has the right to exclusively sell Shell-branded gasoline and diesel in Georgia, North Carolina, South Carolina, Virginia, Maryland and Washington, D.C., as well as the eastern half of Texas and the majority of Florida.  So, if you buy gasoline from anyone of these states you are buying it from Saudi Aramco and not Shell.

In Western Canada we have seen Petronas acquiring Progress, which operates assets within North Montney, and the Petronas-Sasol Montney partnership.

Break-even prices

The break-even prices for new wells in the unconventional plays in the U.S. is about $50 per barrel, and for existing wells the break-even prices are between $24 to $38 per barrel (Oil and Gas 360, 2019).  In the deep water the break-even price has been lowered to $30-$40 per barrel.
In a Rystad Energy (2020a) impact analysis it was shown that U.S. drilled but uncompleted wells (DUCs) breakeven costs are now only dollars away from market prices and they may be the first assets to be threatened by the newly formed low price environment. 
We need to be careful about break-even prices because they depend upon several factors such as:

1. Geology, which drives the EUR but we tend to not understand the geology until we have drilled several wells.  This is where technology such as machine learning incorporating different sources of data may help;
2. Drilling and completion costs;
3. Operating expenses;
4. Experience drilling wells in that basin;
5. Land costs. 

With these low prices it will be hard for small producers to keep up this production needed in the unconventional plays.  The mid-size companies will resort to mergers to survive and the large cap companies may see their market share increase.  The larger cap companies can also keep some drilling activity going which will allow them to be able to negotiate the best drilling rates.

Effect of oil price drop on oil companies

The companies that were hit the hardest were those caring high debt or highly leveraged.  Debt is not a problem unless a company cannot easily pay it off, either by raising capital or with its own cash flow.  Sometimes companies may be forced to raise new equity capital at a low price, thus permanently diluting shareholders (Simply Watt St, 2019).

In Canada we saw oil and gas stocks plummeting with many that were carrying high debt being hit the hardest because of fears they might not be capable of managing their debt obligations in a new year of low oil prices (Ray, 2020).

The response caused by this drop in oil price and loss in share value was the immediate reactions from the oil companies, with most cutting their capital expenditures (CAPEX), dividends, and deferring work that would be done in 2020.  Some will not be increasing their crude oil production in 2020 others will significantly reduce their drilling, completion, and facilities budget.  We may see the Alberta government using the curtailment tool to ensure survival of their producers (Kool, 2020b).

We probably will not see the larger scale oil and gas acquisitions like we did with the Occidental-Anadarko merger mostly due to their recent commitments to being net zero emission (Shell, BP, Eni, Equinor, Total, Repsol, CNRL, Cenovus, Meg Energy to name a few) to attract investment (Hittle et al., 2020).

With a higher risk and a rising cost of capital, higher hurdle rates (minimum rate of return on a project or investment required) will be attached to oil and gas projects (Hittle et al., 2020).  In order to determine the hurdle rate associated risks, cost of capital, and the returns of other possible investments or projects need to be taken into consideration (Kenton, 2020).

One company has even cut the salaries of its president, executives, management committee and vice presidents which shows unprecedented leadership in these trying times.

Saving grace – hedging

Hedging in the oil and gas industry is an insurance policy against sudden changes in the price of oil or gas.  Hedging reduces potential risk and it also chips away at potential gains.  It is used to reduce and control their exposure to risks (Reiff, 2020).

Oil and gas producers sell contracts called "futures", which is an agreement to sell some portion of their oil or gas at a set price.  They can also offset potential losses through taking financial positions in the options market that are equal and opposite to their own holdings (Healing, 2018).
When the price of oil or gas drops companies gain from hedging, but if the price goes up then companies lose because they are now selling their oil or gas at a lesser rate such as what happened in 2000.  Hedging is considered especially prudent when companies make large spending commitments on major long-term projects such as oilsands or deepwater wells.

An example of hedging is a Canadian company recently stated in its announcement on changes in its 2020 budget that the company had positioned itself to withstand further crude oil price volatility by protecting for 43% of their oil production in the first half of 2020 using derivative contracts at US$58.21/bbl.  In the second half of 2020 26% of its oil production is protected with derivative contracts at US$55.32/bbl.  They are expected to earn $42 million through their hedging.

In a study of 30 unconventional drillers, accounting for 38 percent of total U.S. oil production, 50 percent of their output is hedged with an average price of $56 per barrel.  If WTI stays roughly where it is now and averages $25 then the hedge will save the company $17 billion (Kool, 2020b).
Most of the oilsands producers have already hedged their oil by locking in price contracts today for deliveries to be made months or years from now (Healing, 2018).

With the hedges in place, producers will continue to pump oil instead of cutting back as they should (Burns, 2020).  We are seeing 405 rigs still operating in the Permian and 67 in the Eagle Ford.  The number of rigs in the U.S. has not really changed that much since the price has dropped while in Canada the rig count has changed from 240 to 98 but this could be due to the upcoming road bans and the fact that drilling in Canada predominately occurs over the winter.

It also may be too early to tell since the drop in the price of oil was only weeks ago and commitments to drill have been made months ago.  With changes to their CAPEX, generally cut in half, a lot of companies are talking about reducing their rig count in the next couple months by 50% as well.

Purchasing oil for storage

To help with the oil price, the U.S. government bought 77 million barrels oil for their SPR or strategic petroleum reserves (Burns, 2020).  SPR’s are intended to be used to cover short term supply disruptions, or have been used in the past when there was a severe increase in the price of oil causing an increase in the cost of petroleum products such as gasoline, diesel, bunker fuel, jet fuel, etc.  The increase in the price of petroleum products drives the costs of the average goods up and subsequently operating expenses of companies outside of oil and gas and may lead to a recession.

SPR’s are required for all 28 members of the International Energy Agency (IEA), and the SPR must equal to 90 days of the previous year's net oil imports for their respective countries (Baker et al., 2000; Wikipedia, 2020).  The only members of the IEA exempt from this requirement are net-exporter members like Canada, Denmark, Norway, and the United Kingdom (Wikipedia, 2020).

It is expected during this period of low oil prices other countries like China will buy oil for their SPR’s which may increase the demand temporarily.
Western Canada’s storage infrastructure has a maximum storage capacity of 40 million barrels.  It is believed more than 30 million barrels of crude oil and diluted bitumen is already held in storage and because of that Western Canada’s oil production will need to be cut by 440,000 BPD in April as they are running out of available storage capacity (Rystad Energy, 2020b).  There is expected to be steep reduction in crude-by-rail exports this year.

The problem is if the market struggles to find a home for surplus barrels, then oil prices might have to trade down into the teens (Burns, 2020).  We are also seeing that crude imports for refining are also expected to decline because there is less demand for gasoline, bunker fuel, and jet fuel.  With the closing of the borders, few are flying, going on cruises, or driving globally due to Covid-19.  Overall crude imports for refining and storage are expected to be down by 5% or 500000 BPD (Wood Mackenzie, 2020).

If the price of oil goes into the teens, the U.S. and Canadian producers will be taking a large loss when their hedges run out (Burns, 2020).  We also know a lot of debt will be maturing by 2024.  The prices of bonds issued by heavily indebted oil and gas producers have dropped sharply in recent weeks and they are becoming the biggest issuers of junk bonds or high yield bonds, accounting for more than 11 per cent of the US high-yield market (Rennison, 2020).

Junk bonds are bonds that carry a higher risk of default than most bonds issued by corporations and governments, because they are issued by companies that are struggling financially and have an elevated risk of defaulting or not paying their interest payments or repaying the principal to investors (Chen, 2020).

The junk bonds pay higher yields because they need to attract investors to fund their operations and have larger price swings than bonds of higher quality (Chen, 2020).  An investor can monitor a bond’s level of risk by reviewing the bond’s credit rating and this is why when a company’s or government’s credit is devalued there is an announcement in the news (Chen, 2020).

Solutions for distressed companies

Companies drilling the unconventional plays need to preserve low leverage and generate free cash flow positions during these challenging times and that means more financial discipline.  This is what the financial institutions have been asking for since 2019.

Many companies with junk-rated bonds have been defaulting on interest payments at record levels.  This has been occurring as smaller producers have saddled themselves with too much debt and have been going bankrupt or forced to merge (Kimani, 2019).

This could be an opportunity for strategic distressed debt investors that buy these distressed companies.  They tend to purchase these companies by buying their debt and then holding onto the debt through a bankruptcy.  After the bankruptcy they convert the stake to equity and seize control.  They may purchase more than one company and force the companies they have seized control over together in what is known as “smashco” hoping to achieve the best combination of assets and management (Giel, 2019; McNeely, 2019).

In unconventional plays because we like long horizontals, which are drilled parallel to the minimum horizontal stress but may not be parallel to the lease boundaries.  To maximize these wells, we prefer to have contiguous properties across an area.  We saw this in the vying for the purchase of Anadarko by Chevron and Occidental who both held lands next to Anadarko in the Permian (Nair and French, 2019).

Other times private equity investors may buy unwanted assets or companies, replace the management teams, and look for a buyer (McNeely, 2019).
There is an another alternative and that is to buy the proved developed producing reserves (PDP) at cheap prices and hedge (McNeely, 2019).

One of the tried and proved strategies small oil and gas companies are thinking of applying is asking the service providers to cut their prices.  This was done during the price downturn in 2014 when the price for drilling and completing wells were high but currently there was already a 23 percent drop in rig count from February 2019 (857 oil wells, 154 gas wells) to end of December 2019 (677 oil wells, 125 gas wells) and double-digit price deflation among service companies which left many service companies bidding competitively for low-cost jobs (Hittle et al., 2020; Kool, 2020b).

Larger companies that can keep rigs busy throughout 2020 are able to workout discounts with the service providers based upon continual commitment.  These companies can also demand for the more experienced people to work on their projects. 

Application digital technologies

Companies should be looking at the application of digital technology, automation, machine learning, data visualization, virtual reality, and utilizing AVO seismic inversion in order to improve the precision of drilling the long horizontal laterals and staying in the sweet spot. 

One of the recent changes in the unconventional plays is the drilling of multiple zones from a single borehole since we are likely to find unconventional plays in deep basins that tend to have

vertically stacked plays.  Even in the zone of interest, like the Montney, there may be multiple stacked zones to produce from. 
To do this, we need to utilize geomodels and frac modelling.

There needs to be higher levels of production discipline with wells needing to be shut-in, focus on core liquid rich / oil areas; decrease in drilling and lowering of drilling and completion costs.  We have been here before in 2014 to 2016 and we were able to change how we drilled and completed the wells, which significantly lowered the break-even prices.  We just need to do it again.

Government interaction

With the demand for oil being so low, and storage running out, there is little that can be done except to return to what has worked in the past.  A senior U.S. Energy Department official will be sent to Riyadh for months to work closely with Department of State officials and the existing energy attaché, to negotiate with Saudi Arabia and Russia and convince them to match cuts with a similar cut in production in Texas (Reuters News Agency, 2020).

As it was in the past, the Texas Railroad Commission, the body that regulates the state's oil and gas industry, will probably oversee and enforce the production cuts (Reuters News Agency, 2020).

Issues with Alberta and the federal government

Many in the oil and gas industry see production limits have proven ineffective and harmful and believe there is no reason during this time to try to imitate OPEC.  The Alberta government on the other hand has used curtailment of production recently to reduce the differential between WCS and WTI.

Canada, in the past, has not politically leveraged their position of being the 4th largest producer, because of our decentralized private sector oil industry and also the issues between Alberta and Ottawa (Vredenburg and Marchant, 2016).

The issue in Canada is who is really in charge when it comes to oil.  We have a Minister of Foreign Affairs, and Natural Resources who could be a part of this, and in the provinces, we have a Minister of Energy.  Who would be involved with working with OPEC+ and the upcoming global talks on oil production is a big question.

If Canada relies on the U.S. to negotiate production cuts, then Western Canada may be left out of this.

An example of who is in charge of oil is in 1986 when there was a crash in the oil price and Premier Getty reached out to the Saudi Oil Minister Sheikh Zaki Yamani offering to make a cut in production.  The Saudis liked the idea and, three weeks later, Yamani asked Canadian Foreign Minister Joe Clark to come through on Getty's offer.  Canada's formal response to Yamani's request was to say that only the market would set Canada's production levels, and this has been the policy since.

Shutting in unconventional wells

With all that has happened with the shutdowns around the spread of Covid-19, the demand for oil and natural gas has significantly dropped to about five million barrels a day according to estimates by the IEA.  This is mostly due to the shutdown in the airlines, cruises, and people are driving far less during this crisis (Evans, 2020).
The pipeline companies in U.S. are asking proof from the companies that they have buyers in place for the oil that they produce so that the oil does not sit in storage facilities (DiLallo, 2020a).  Companies in the U.S. and Canada have cut their capital spending plans and production guidance, which will ease the near-term glut of oil (DiLallo, 2020b).
Typically, companies cut their drilling and completions programs because of the issues surrounding shutting in wells, but the major issue is with the current drop in demand we really need a drop in production.  There are costs associated with the shutting in of wells that will affect  the production in adjacent wells and have a material effect on the ultimate recovery of oil from the property (Nickerson, 1929). 
There also can be issues with royalty owners not receiving royalty payments because the production has ceased, and the cessation of production can potentially lead to the termination of the oil and gas lease.  Most leases are perpetuated by production so any cessation in production may require a decision from the land department as well (Seely, 2018).
An alternative method to reduce production is using a choke at the well head or downhole.  There are many reasons to use a choke in a well, not just to limit the production, such as (Lea and Rowlan, 2019):

1. Delaying of water/gas breakthrough;
2. Longer well life;
3. Higher cumulative oil production;
4. and increase in net present value (NPV) which is the difference between the present value of cash inflows and the present value of cash outflows over a period (Kenton, 2019).

Heavy oil (WCS)

WCS has already fallen below $5 a barrel which could put the profit earned by WCS to be a loss or at zero due to the price of condensate that many producers use as diluent and costs to ship by rail (Healing, 2020).  It is tough to shut-in steam-assisted gravity drainage (SAGD) or cold heavy oil production with sand (CHOPS) operations and later re-start them.  Chokes can also be used in the SAGD wells and CHOPS.

WCS price differential

There are 3 variables that drive the WCS price differential with WTI and they are (Oil Sands Magazine, 2018):

1. Quality and the two most important indicators are density and sulfur content, especially with the changes in IMO 2020 banning ships from using fuel with a sulfur content higher than 0.5 percent;
2. Marketability, which is governed by supply and demand.  Complex refineries will pay more for lower quality crude while simple refineries see lower profit margins with heavy oil, so they only buy if the crude has a significant discount;
3. Logistics which is the transportation of oil to market.  Western Canada has been sending most of its heavy crude by rail which is the most expensive way to transport it.  In Western Canada there will be three pipelines being built which will be effective: Trans Mountain Expansion; Keystone XL, and Enbridge Line 3 replacement.  Heavy oil from Western Canada will not compete with light oil from the unconventional plays and are needed as feedstock for complex refineries. 

Impending financial crisis

With all of this occurring we will see issues in the junk bonds, small oil companies unable to make their interest payments, and we could see an economic crash like we did in 2008 with the housing market and the junk bonds for mortgages.

Currently we are seeing about one-third of the junk bonds in the Bloomberg/Barclays high-yield energy index trading at distressed levels and at those levels, highly leveraged oil and gas producers have effectively been locked out of the junk bond market (Egan, 2020).  These companies that are locked out of the junk bond market will need to raise cash, slash costs, sell assets, accept harsh borrowing terms from a hedge fund or seek a financial lifeline through a merger and some debt-riddled oil companies will declare bankruptcy and close (Egan, 2020).

We also know by 2024 exploration and production companies have roughly $86 billion of debt maturing (Egan, 2020).

Conclusion

In challenging times like this, it might be better to go back to what has proven in the past to work:

1. Finding efficiencies to improve our production and minimize our cost.  We have seen this all the way back to Standard Oil;
2. Cut production drastically to meet the current drop in demand caused by Covid-19.  We have done similar things in the 1930’s in Texas;
3. Develop innovative technologies such as the use of distributed fiber-optic technology (DFO) with downhole internal pressure gauges placed in monitoring wells on the same development unit to measure cross-well strain.  By measuring cross-well strain, information on how much fluid and proppant can be squeezed between wells before the newly created fractures touch an offset well can be obtained.  This information can be used to control the amount of fluids and proppants used which has a direct effect on the price of completions (Jacobs, 2020) as well it can indicate if the inter-well spacing is too tight (Schulte et al., 2019);
4. Working globally together on a better price for oil that can sustain companies and alleviate the issues with oil storage.  This has not been implemented before, but we have never had anything like Covid-19 with one third of the global population on lockdown, borders closed, over 1 million infected, virtual shutdown of passenger flights, etc.;
5. In these negotiations with OPEC+ there will probably be a push of removal of sanctions that are more in place to gain a market advantage such as Iran and Venezuela since both are members of OPEC+.

Update as of April 10, 2020

Since this article was written, on March 31, 2020 Parsley Energy and Pioneer Natural Resources asked that the Texas Railroad Commission hold an emergency meeting and order production cuts, as record low crude prices threaten hundreds of thousands of industry jobs (Chapa, 2020).

On April 10, 2020, OPEC+ agreed to cut 10 MMBPD, or 10% of the World’s oil production, which is the largest production cut in history.  By doing this OPEC+ hopes the G20 oil ministers will cut another 5 MMBPD to offset the drop in demand due to Covid-19.  If the G20 oil ministers refuse to do so there could be a significant drop in the price of oil since the production has not be curtailed enough to deal with the current 25% drop in demand for oil & refined products (Sheppard et al., 2020).

It is expected that Canada will cut back roughly a third of its total domestic oil production – or 1.7 MMBPD (Morgan, 2020).  This would directly affect jobs and projects across Canada, especially in the oil sands, and it could affect the demand for condensate from the deep basin.

There are concerns also about the price of natural gas, since the Henry Hub Natural Gas Spot price has fallen from $2.57 MMBtu in 2019 to $1.86 MMBtu which is a drop of 28%.

We have also seen the price for LNG for Asia fall down to $2.40 MMBtu because of lack of demand for LNG by China during this pandemic.  The price for LNG in Europe has also been low since they had a very mild winter, they lack storage capacity for LNG, and because of the pandemic which has caused most of Europe to shutdown.  The price for LNG is currently $2.71 MMBtu, down from $5.00 MMBtu one year ago or 46%.

The price of LNG is coming close to the cost to produce LNG.