For decades, Nigeria has been the bellwether of change in global oil markets. Today, the country is struggling to find buyers for its oil. French refining sector strikes and seasonal maintenance elsewhere have cut demand for Nigerian barrels — a problem compounded by the country’s success in boosting output.
The term “credit” has yet to be mentioned in coverage of Nigeria’s difficulties. However, the trading companies buying the oil are likely paying close attention to credit terms and the shape of the forward price curve. Brent crude is still in backwardation, although it is declining, and trading firms are unlikely to step forward and buy Nigerian oil until Brent shifts into contango. But to create sufficient contango to re-establish a satisfactory market for Nigerian crude, Brent would probably need to fall to $55 per barrel from around $78 now. Such a drop would also probably spur Opec-plus to cut output.
Worried Yet?
Many in the industry still seem to be relaxed about the danger of financial contagion. At the recent FT Global Commodities Summit in Lausanne, Switzerland — held just after the country’s authorities forced Credit Suisse to merge with UBS — speakers downplayed the risk, suggesting the crisis would likely be contained and not prove a repeat of the great financial meltdown of 2007-08. Nor do they think it will have a material impact on demand. Some executives from major trading firms did, however, admit that smaller traders could face credit constraints — particularly in the hubs of Geneva, Zug and Lausanne, where Credit Suisse, UBS and the country’s cantonal banks provide a significant chunk of traders’ lines of credit.
The truth is that commodity traders and the oil industry should be very worried. The banks’ unwillingness to lend will force firms to reduce oil stocks. Nigerian excess output will also depress crude prices. Gasoline and diesel demand growth will be slowed as construction activity decreases. Oil, then, could become the collateral damage of financial contagion.
Philip Verleger is an economist who has written about energy markets for over 40 years. A graduate of MIT, he has served two presidents, taught at Yale and helped develop energy commodity markets since 1980. Kim Pederson is editorial director of PKVerleger LLC. The views expressed in this article are those of the author.
Oil Industry Faces Credit Crunch Copyright © 2023 Energy Intelligence Group
The oil industry seems to be once again ignoring key and obvious signs of jeopardy from external sources. This time its survival may be at stake, as reverberations from the collapse of Silicon Valley Bank continue to spread through an already-stressed global financial system and still threaten to overwhelm it. Oil executives and ministers ignore the danger of being sucked under by a sinking financial system at their own peril. Governments and central banks will save the financial system, as they often have. No one, though, will throw a life vest to the oil industry. And even if a major financial shock is averted in the near term, the effects of this crisis will still be felt for years to come in much tighter credit conditions.
The global financial system is in trouble as March ends. Bankers have failed to adjust their reserves for the rise in interest rates, and deposits have flown as their owners have realized this. They are thus unlikely to lend to even the most creditworthy customers and are instead slamming lending windows shut, slashing credit lines, and rejecting loan applications from long-standing patrons. The banks that survive will be those that lend the least.
The “bureaucratic and process-oriented” nature of bank examination has been key to these meltdowns. Regulators were slow to recognize Silicon Valley Bank’s fragility. But another far more important development is the newfound ability to move money with a smartphone. In past times, deposit outflows were modulated by how fast tellers could dispense cash or ATMs could be refilled. Customers who wanted to close their accounts or move large sums had to visit their branch office. That gave regulators and executives time to craft a plan to calm anxious patrons.
Flight to the Fed
A further headache for central banks and oil traders is that the money being withdrawn from US commercial banks is moving to the Federal Reserve rather than other banks. This development constitutes the greatest threat to the economy and those in the oil industry.
Research by economists at the Federal Reserve Bank of New York shows that, by increasing its discount rate, the Federal Reserve Board gave money market funds the incentive to move funds to the Fed through “reverse repurchases” or “reverse repos.” Funds transferred to the Fed pay 4.8% now, up from 0.05% a year ago. And between March 2021 and October 2022, money market balances held in reverse repos rose from “a few billion” to over $2.2 trillion, according to the Fed economists. In the following six months, the flow to money market funds increased by another $500 billion. Perhaps half of that occurred in the last few weeks.
This increase was mirrored by a decline in bank reserves. From the end of December 2022 to the week ending Mar. 16, 2023, bank deposits declined by almost $500 billion or 3%. Deposits at the 25 largest banks dropped by $200 billion or 2%. The problem for the economy is that the money going to the Fed cannot be lent by banks to customers to, say, buy oil or purchase a car. Shorn of deposits, banks will need to fund loans through commercial markets where interest rates are now much higher. This will lead, in turn, to higher lending interest rates and stricter loan standards.
European Jitters
Banks in Europe are less exposed than in the US, but can’t ignore the crisis, as Credit Suisse’s failure shows. Contagion from that has already spread to Germany. The problem relates to AT1 bonds — an obscure financial instrument also known as “contingent convertibles” or “CoCos,” which systematically important banks are required to issue. CoCos shift the cost of a bank failure from governments to the private sector. They are specifically designed to act as a buffer for banks if capital levels drop below a specific threshold. The reward to investors from these long-term euro-denominated bonds is quite large today compared to rates on long-term bonds issued by European governments. But with that comes the risk that the bonds will be converted to equity or, alternatively, get wiped out.
A Swiss decision to wipe out the holders of Credit Suisse bonds has some worrying now that banks may no longer be able to use these instruments to meet the reserve requirements mandated by central banks. Goldman Sachs has reportedly advised its clients that it was no longer possible to assess credit spreads on AT1s. Following the Swiss action, the prices of AT1 bonds issued by Deutsche Bank and others also fell. These declines emphasize the fact that European banks, like their US counterparts, will face difficulties raising operating funds. The consequence is that lending will be cut, and the cost of lending will rise.
Shooting Star – The Condensate Star Has Faded, But What’s Next In The Conde Market? | RBN Energy
Way back when—before 2012—few outside a small cadre of oil producers and marketers paid any attention to condensates, or even knew they existed. Then two events shook the condensate world. First came rapid growth in the Eagle Ford, where crude oil production turned out to be almost half condensates. Then the Department of Commerce started allowing condensate exports while maintaining the ban on international sales of mainstream crude oil. Suddenly condensates were the star of the show. But like the careers of one-hit rock & roll wonders, the stardom didn’t last long. The crude oil price crash hit Eagle Ford hard, resulting in a disproportionate decline in condensate production. Congress then sent condensates further back into obscurity by removing the export ban for all crude oil in December 2015, eliminating any special status for the product. That was the end of the road for the condensate story, right? Wrong. Because during condensate’s day in the sun, billions were spent on pipelines, stabilizers, splitters, export facilities and refinery modifications, all focused on providing new markets for condensates. Oops. Today we consider how the next chapter of the condensate saga will play out.
This blog continues the Faded Love series on condensates (conde for short) that we started posting a few weeks back. In Part 1 we showed that while condensates (super-light crudes) are produced from all of the major basins across the U.S., the Eagle Ford in South Texas has been responsible for most of the production growth over the past five years, and that the Eagle Ford has been hit harder by low crude prices than any of the other major shale plays, resulting in declines in condensate production. We then touched on the splitters built to process condensates in the U.S. and on other infrastructure to handle segregated processed condensate for export –– now no longer required since the lifting of the crude/condensate export ban. Then in Part 2 we got into the weeds, looking at condensate production trends using the newly enhanced Energy Information Administration (EIA) dataset called the EIA-914, which gives us crude oil production statistics in 10 API gravity categories, including the two API gravity buckets above 50 degrees API where condensates reside. At that time the data confirmed that condensate production was falling, particularly in Texas. Since then, condensate production has continued to decline.
Figure 1 shows conde production in two of EIA’s 914 production data categories. The brown line is total U.S. production greater than 55 API, which fell from about 550 Mb/d to less than 470 Mb/d in May 2016. Slumping Eagle Ford production has been responsible for most of this decline. The blue line shows Texas production greater than 50 API. (EIA consolidates the 50-55 and 55+ categories for individual states for confidentiality purposes.) Even though the data is not apples-to-apples, it is still quite apparent that production of the lightest condensates is down by about 15% and that the decline shows no sign of abating.
One implication of the decline in production is a corresponding drop in conde exports. As shown in Figure 2 below—based on data from our friends at ClipperData—condensate exports ramped up from next to nothing in mid-2014 to 160 Mb/d by June of last year, then fell during the summer of 2015 as domestic demand for naphtha-range material pulled barrels out of the export market. Over the first five months of 2016, exports kicked back in again, but those gains came to a screeching halt in July when confirmed export volumes dropped to only 20 Mb/d. In the first few weeks of August, exports moved back to about 70 Mb/d (orange dashed circle).
Even though exports have been down lately, total conde volumes moving via water have been higher than might be expected considering that the price differential between Brent crude (the international benchmark) and Light Louisiana Sweet (LLS, the Gulf Coast benchmark) has averaged only about $0.30/bbl since June 2015. Conde prices tend to be loosely pegged to these two benchmarks. Thus it would seem that there would be little economic justification for moving this super-light crude from the Gulf to global markets if prices in the two markets are about the same, even though tanker freight rates are currently at ridiculously low levels. Nevertheless, barrels have moved –– a significant portion of them to U.S. refiners.
As shown in Figure 3 (left graph), the Texas Gulf Coast has been responsible for 76% of total condensates moved from U.S. port facilities. These volumes include both exports and cargoes on Jones Act-compliant vessels destined for markets in the U.S. About half of that total has come from Corpus Christi (orange pie segment, all Eagle Ford volumes), with much of the rest shipped out of Houston and Beaumont. Most of the remainder of condensate shipments has moved from the East Coast, with conde from West Virginia (blue segment) accounting for 10%, followed by New Jersey (7%) and Pennsylvania/Ohio (5%). (For more about East Coast condensates see our series titled in Whole Lotta Splittin’ Going On.) We’ll have more on Ohio condensates in an upcoming blog covering Marathon’s Cornerstone Pipeline plan.
The right graph in Figure 3 indicates the destination for these barrels. More than one-third of total shipments have gone to Europe (green pie segment), with most of the volume moving to the Netherlands, France and Italy (see our previous analysis of these condensate destination markets in What Condition My Condensate Was In). The second-largest recipient of U.S. waterborne condensate has been (drum roll, please) – the U.S. (aqua blue segment). Most of these barrels have been going to six destinations for use by refiners, splitters and blenders: Marathon at Garyville, LA; Petrobras at Pasadena, TX; Total at Port Arthur, TX; Hunt at Mobile, AL; Sunoco at Nederland, TX; and Plains All American at St. James, LA. For the most part, these condensates are moving directly or indirectly into the U.S. refining system, ending up as motor gasoline, including gasoline exports (see It’s a Small World After All). The remaining condensate outbound volumes have moved to the Middle East (10%), Latin America (10%), Asia/Pacific (9%) and various other destinations, some not yet determined (16%, black segment). Note that this last category includes a few ships that are apparently being used for floating storage – the ships have been anchored in the Caribbean for weeks.
Figure 4 shows how the sources of these volumes have shifted over the past two years. All along, the big driver has been Texas, with most volumes loading at Corpus Christi, Houston and Beaumont (orange bar segments, left graph). West Virginia (blue segments) was growing fast in 2015, but came off hard this year, mostly due to low crude prices that have discouraged drilling for wells with high condensate yields. Total volumes virtually collapsed in July (2016) due to lower production and seasonal demand in the U.S., recovering somewhat in August (red dashed box). The right graph indicates that Europe (green bar segments) continued to be the largest recipient of U.S. condensates, with the Louisiana market (red segments) taking a significant portion of barrels destined for U.S. markets.
So does all this mean that the conde star has faded and the product will forever be relegated to second-tier venues and sad reunion gigs? Hard to say. While ClipperData can identify the condensate moving out as “neat” product (that is, identified on the Bill of Lading as condensate), there also are conde barrels moving out as blend stock in light crude exports, mixed up with various other heavier crudes to create cocktails that can be labeled as “Domestic Sweet” or the generic “U.S. Crude”. That means that condensate still has a role as an opening act, if no longer the headliner. It is a similar story at the crude oil hub in Cushing, OK, where condensates from Oklahoma’s prolific SCOOP and STACK plays (acronyms for South Central Oklahoma Oil Province and Sooner Trend Anadarko Basin Canadian Kingfisher) are sought out as blendstock for various brews destined for domestic refiners.
But with condensates still moving to exports, local refineries and blend markets, what has happened to the condensate splitters built during the conde heyday to absorb what was then expected to be a surplus of this super-light crude? We will explore that issue in the next episode of this series.
Source: Shooting Star – The Condensate Star Has Faded, but What’s Next in the Conde Market? | RBN Energy
Pound-Dollar Parity Is Now A Possibility For Options Traders
What was close to unthinkable for the pound before the Brexit vote is now firmly on some traders’ minds.
They’re betting sterling will tumble to parity with the dollar, a level unseen in the U.K. currency’s history. In recent days, a number of wagers were put on for a one-for-one exchange rate, according to Depository Trust & Clearing Corp. data.
Options with strikes at parity
The pound, which had already been struggling this week amid growing talk of a so-called hard Brexit, plunged 6.1 percent in Asian hours on Friday to a 31-year low of $1.1841. The slump has made the possibility of a historic $1 level more real: a Bloomberg forecasting model, based on implied volatility, shows about a 7 percent chance of it happening within a year, compared with 3.2 percent yesterday.
“Certainly there are a few calls for parity, yes — there are a few that are positioned for it, that is their target and objective, or they’re hedged for fear it might go in that direction,” said Neil Jones, head of hedge-fund sales at Mizuho Bank Ltd. in London. “I wouldn’t say it’s a mainstream view,” but “the structural downtrend is probably still intact for now.”
The pound was down 2 percent at $1.2368 as of 1 p.m. London time, set for a weekly drop of 4.7 percent. That’s about the same as its slide during the week of the June 23 referendum, when Britons voted to quit the European Union. Sterling sank 1.9 percent to 90.01 pence per euro after touching 94.15 pence, the weakest since March 2009.
The lowest the pound has fallen versus the greenback in the past four decades is about $1.05 in February 1985. Bank of England data show it hasn’t dropped to parity for at a century.
The cost of hedging against sudden declines in sterling increased, according to risk-reversals data compiled by Bloomberg. The premium on six-month options to sell the currency versus the dollar over those to buy widened to 2 percentage points in the biggest jump since the Brexit result.
Why did the pound crash and what’s happening now?