Brexit's impact on oil and gas

The World Bank's June 2016 pre-Brexit Outlook reduced their growth forecast from 2.9% to 2.4%, citing "weaker growth among advanced economies and low commodity prices." The UK's GDP is the fifth largest in the world and the UK is one of the few economic powerhouses in Europe. The US is already seven years into this expansion cycle, with history strongly suggesting that US economic recoveries almost never last longer than eight years. China's economic slowdown has been well documented.

The UK currency (GBP) immediately plummeted post-vote (down from $1.47 to the low $1.30's), signaling a consensus expectation that the economy of the UK will be adversely impacted by the exit from the EU. Various economists' initial estimates of the resulting decline in UK GDP range from 1-6% (Wall Street Journal June 27, 2016). For perspective, recall that the US decline in GDP during the Great Recession was approximately 4.3%.

S&P has downgraded UK's credit rating from AAA to AA and says, "in our opinion this outcome [Brexit] is a seminal event." A decline in the economy of the UK and other EU countries would likely impact the demand side of the crude equation as well. Interestingly, the GBP began to rebound to the mid-$1.30s as of June 29.

Concurrently the US dollar appreciated as investors continued seeking a safe harbor and small but positive bond returns. These Brexit-driven currency shifts will likely affect the price of crude. Note that Brent hit a seven-week low on June 28, 2016 in part based on the dollar rally.

To the extent that the USD continues to strengthen in the aftermath of Brexit, the price of crude would be expected to weaken correspondingly. According to a recent Morgan Stanley publication, an additional 5% increase in the strength of the dollar against a basket of currencies could push crude down by 10% or more. A simple linear regression, which is admittedly an oversimplification, suggests that as much as 50% of the price variance in crude can be explained by movements of the USD.

This regression helps us rationalize the Morgan Stanley prediction above. We believe that a more complex multi-variable regression analysis suggests that longer-term, approximately 30% of the movement in crude pricing is attributable to the USD's movement against a basket of currencies.

OIL PRICING

What does a Futures Curve really represent? The Futures Curve represents the consensus of market participants regarding the expected (not the actual) future spot price. It is a classic point at which expected supply meets expected demand (Investopedia).

What the Futures Curve is NOT is ''right" in the sense of predicting the actual future spot price of crude. Buyers of futures contracts are simply willing to buy crude at the contract price on the contract date. Sellers are willing to sell at that future contract price. Many of these players have an orientation toward hedging versus "betting." Speculators, on the other hand, have expectations that the future spot price will differ from the contract price one way or the other and make their bets accordingly. Note in Figure 2 the extent to which the actual spot price of crude in May of 2016 differed from the May 2016 futures contract price, which traded as high as the $90s in 2012-13 and early 2014.

What is the Futures Curve telling us about the price of oil? In January of 2016, the spot price of crude was about $27 and the crude Futures Curve was steeply positive, reflecting the almost universal expectation that crude had to trade up substantially from the high $20s. The current Futures Curve has flattened considerably and shows oil prices rising slowly over the next five to six years (Seeking Alpha, June 15, 2016).

This trend illustrated in Figures 3 and 4 suggests the following:

WHAT DOES $50 TO $60 CRUDE REALLY MEAN?

Crude prices at these levels are generally good for the overall US economy. Lower energy prices provide for more disposable income for consumers and the US economy is heavily impacted by consumer spending. They also allow for lower operating costs for energy- intensive industries.

These price levels are not good news for the banking community. Oil and gas lenders have significant loans outstanding, perhaps as much as $123 billion (Bloomberg, February 23, 2016), to E&P companies and to service companies. It has been estimated that 50% of all energy loans are classified by the regulators and/or are on the watch list (The Wall Street Journal, March 24, 2016).

Assuming a crude price in the $50 range, the reserve loans to the E&P companies are likely not a disaster. Lenders making reserve loans typically lend at LTV's of about 50% using a price per barrel which approximates the Futures Curve pricing in place at the time of the loan. At $50, rampant charge-offs of reserve loans are not expected. Note the contrast between the current situation and the 1980's when crude declined from $107 to $14 (inflation adjusted) and stayed in that range for years. This decline in crude pricing was the direct cause of the Continental Illinois problem (one of the first "too big to fail" scenarios), as well as the shotgun weddings or closure of every major Texas bank holding company. A spot price averaging $50 will preclude any wholesale disaster on the reserve loans. Pricing at sharply lower levels, say below $30, could yield a different conclusion with respect to certain bank E&P loan portfolios.

The loans to service companies are, for the most part, train wrecks. Many service companies can barely cover operating costs before debt service at current activity levels. A significant majority of the drilling rigs in the US are currently stacked, and day rates have also been crushed by competition and customer demands. The service company workouts we have orchestrated during this cycle have had the following characteristics:

• The lenders do not want the collateral back in current market conditions. They generally prefer that the collateral remain in the possession of the borrower, as the low-cost alternative to taking possession in foreclosure, in a market where collateral values are severely impaired and buyers are scarce.
• Lenders do not want to have to lend additional funds to the service company borrowers to subsidize overhead. Once a loan is regulatorily classified, any additional advances to the same borrower are also automatically classified. In some cases, this results in a lender having to make additional provisions to their loan loss reserve the same day they make the additional advance.
• So long as a service company can cover overhead and maintain the collateral in good order, we expect fairly benign conduct from the lenders, particularly in the absence of money-good guarantors.

Even if one imagines a meaningful decline in crude prices from current levels, we do not foresee that this will become the next big US banking catastrophe for the following reasons:

• Unlike the R/E crash in the Great Recession, very few US banks have significant exposure to energy lending. The few that do are the classic, "too big to fail" institutions like Wells, JP Morgan Chase, Citigroup, and Bank of America. Note that these large banks also very recently received good grades on their "stress tests."
• Table 1 shows that while these banks have significant oil and gas exposure in dollar amount, the industry exposure is not a significant percentage of the big banks' capital accounts.
• A handful of smaller banks located in oil country are at more significant risk and the prognosis with respect to these banks is less clear. These banks in many cases have higher concentrations of oil and gas loans, in some cases as high as 20% of their total loan portfolios, by virtue of geography. They are also more exposed to the collateral damage of loan problems to borrowers who are not in the oil business but are wounded by virtue of being in oil country, residential developers as just one example. Taking the hypothetical of a bank with a 70% loan-deposit ratio, 20% loan concentration in oil and gas, and a 10% capital ratio, a charge-off rate of 25% of the energy loans would deplete the bank's capital account by approximately 35%. Another metric in our hypothetical is that a charge-off of 25% of the bank's energy portfolio would equal several years' net income for the bank, a substantial downdraft for future earnings but not an imminent cause of pervasive bank failures.
• The conclusion is that while energy loans will be a drag on earnings of the big banks and may cause more serious problems for a handful of local and smaller regional institutions, it will not bring the US economy or banking community to the precipice of financial destruction like the R/E meltdown of the Great Recession.
• Given today's keen regulatory scrutiny on energy loans, we expect to see limited new funding to the industry from the banking community, other than to the best credits in the industry, as pressure builds to reduce classified assets. The big banks in the energy space are still lending, albeit more cautiously. Our interviews with these bankers suggest that prior to the most recent downturn, perhaps 50 banks in the US were active players in reserve lending. Currently approximately 10-15 are still actively lending in the space. There has clearly been a flight to quality that will continue. The smaller banks where energy loans already make up 20% of their loan portfolios have different challenges. They are already too concentrated in oil and gas loans and are facing more serious regulatory scrutiny and pressure to reduce their energy lending exposure. They will not be active lenders, other than the occasional protective advance to preserve their collateral. It is likely that smaller regulated lenders will begin to sell a portion of these loans, rather than trying to work them out over the longer term.
• The result is that regulated lending industry has effectively "redlined" the smaller non-prime credits, until some measure of stabilization and profitability can resume and regulatory pressure can subside.

CONCLUSIONS

We believe that the world's economies were already slowing and that we can expect a moderation in growth of crude demand over the next several years. The supply overhang will moderate but not disappear in 2017 as non-OPEC countries cut their production investments (WSJ).

There is every reason to believe that Brexit will result in some incremental economic fallout which will further adversely impact the demand curve.

The world's desire for safety and for positive, albeit small, bond returns, in a yield-starved world of zero and negative interest rates will continue to support the strength of the US dollar, with the obvious inverse impact on crude pricing.

Oil and gas lending will continue to be a drag on lender earnings but will not cause global chaos on the scale of the R/E catastrophe of the Great Recession. The net impact of the current energy challenges on the banking community will be manageable and wholesale bank failures will not occur.

Other unregulated lenders and equity providers will begin to enter the space to provide investment capital to an out-of-favor industry sector sorely in need of alternative sources of capital. This will take the form of both purchases of distressed loans from existing lenders and direct investment with industry players. The diminished liquidity available from capital providers will result in increased pricing and higher spreads on all tranches of the capital stack. Strong credits and good projects will still have access to capital, although at higher costs. Marginal projects and borrowers will have an impossibly difficult time obtaining financing in these market conditions.

Since the GBP has rebounded and recovered more than half of its initial losses, and since world equity markets have also recovered about half of the Brexit-driven declines, we conclude the following:

The world's smart money hates surprises and Brexit was a huge surprise. A large part of the sell-off was driven by the "surprise" factor rather than by the fundamentals.

• The fact that both the GBP and world equity markets have reclaimed a good portion or all of their initial losses suggests strongly that the world's smart money, upon further reflection, has concluded that Brexit is not a Black Swan event.
• However, a subset of risk is the Principle of Unintended Consequences. There always are unintended consequences and there almost certainly will be from Brexit. The challenge is that unintended consequences are also difficult or impossible to foresee. One could construct any number of scenarios that could occur that have not yet been foreseen or discounted. We don't pretend to be able to define or quantify those unintended consequences but it seems very likely that some will occur, with unknown severity or timing.

ABOUT THE AUTHOR

J. Michael Issa is the managing principal of the Irvine, Calif. office of GlassRatner Advisory & Capital Group LLC. He is a former banker, a CPA (inactive), a FINRA licensee, and a court-appointed fiduciary for corporate bankruptcies in the Central District of California. Issa is an authority on oil and gas matters, having worked on dozens of transactions, including both capital formation and workouts, in his multi-decade career. His clients have included E&P companies, service companies, and refineries. Issa is currently functioning as chief restructuring officer for several oil and gas service companies. GlassRatner's headquarters are in Atlanta, Ga., with offices in a number of major US cities.

OTHER CREDITS

Research assistance was provided by Yuichi Yokoi, a GlassRatner intern. Editorial assistance was provided by Adam Connors, a managing director at Northland Capital Markets.

Brexit vote undermines North Sea oil

Since taking office on July 13, UK Prime Minister Theresa May has been busy visiting Scotland, Wales, and Northern Ireland in an effort to minimize fallout over the unexpected UK vote on June 23 to exit the European Union. In the case of Scotland, May would like to stave off any attempt by Scotland to hold another referendum on Scottish independence, which if successful, could remove a large portion of the UK's share of North Sea oil and gas from the nation's tax base.

Scotland's own First Minister, Nicola Sturgeon, has gone on record saying that she will do "whatever it takes" to keep Scotland in the EU despite Brexit. In a recent speech in Edinburgh, she said, "It may well be that the option that offers us the greatest certainty, stability, and the maximum control over our own destiny is that of independence."

The uncertain investment environment in the UK has created unfavorable market conditions in which the pace of shutdowns of offshore oil fields is increasing. Idle rigs have dotted British harbors on the North Sea, partly as a result of the economic downturn in the petroleum industry. The UK voters' decision to leave the EU has accelerated the number of oil rigs taken out of service and increased unemployment among oil industry workers.

Projected spending on decommissioning in the British sector of the North Sea in the coming decade has risen to 16.9 billion pounds ($22.2 billion), according to Oil & Gas UK, an industry group. That is 16% greater than a 10-year forecast made in 2014.

Wood Mackenzie, the Edinburgh-based consulting firm, forecasts even higher spending on decommissioning - up to 23 billion pounds (about $30.2 billion) - due largely to "political uncertainty" in the UK and the fact that so little decommissioning has occurred so far. Wood Mackenzie says that about a third of North Sea platforms are more than 30 years old, well beyond their original design life.

With their high recovery costs, oil and gas producers in the North Sea have been especially hard hit by the nearly two-year-long slump in oil prices. Already, an estimated 120,000 jobs have been lost because of the downturn, according to industry sources. The Brexit vote appears to be further undermining the British oil and gas industry.