Energy Commodities: Oil, Gas, and the Power Markets
Book: Commodities: Markets, Performance, and Strategies
Editors: H. Kent Baker, Greg Filbeck, Jeffrey H. Harris
Publisher: Oxford University Press, 2018
ISBN: 9780190656010
Chapter 9 comes from Michael Penick and Lynn Riggs, both economists at the U.S. Commodity Futures Trading Commission (CFTC). They bring a regulator’s perspective to energy markets, which makes this chapter particularly interesting for understanding not just how energy trades, but how it is governed.
Why Energy Markets Are Different
Energy markets share a few features that set them apart from other commodities. The biggest one: demand is very inelastic in the short term. When natural gas prices spike, homeowners might lower their thermostat a bit, but they are not going to stop heating their homes. When gasoline prices jump, people grumble but keep driving to work.
But in the long run, things change. High prices drive innovation. The authors point to hydraulic fracturing (fracking) as a perfect example. After years of high natural gas prices in the 2000s, fracking technology expanded U.S. production capacity dramatically, contributing to much lower prices in the 2010s. The same happened with crude oil. A 73 percent increase in U.S. crude oil production between 2008 and 2014 helped push prices from above $100 per barrel to around $60 or below.
High prices also reduce demand over time. Consumers buy more fuel-efficient cars. Manufacturers convert from oil to natural gas. Google announced it would run entirely on renewable energy by 2017, citing low price volatility as a reason. All of this shows long-run demand elasticity at work.
Seasonality and Storage
Natural gas prices are highly seasonal. Demand peaks in winter for heating and again in summer for air conditioning. During spring and fall “shoulder” seasons, demand drops. Natural gas gets stored in salt caverns, with levels building during warm months and draining during cold months.
The Energy Information Administration (EIA) publishes weekly data that markets watch closely. Natural gas storage estimates come out Thursdays at 10:30 a.m. Eastern. Crude oil and refined product data typically drops on Wednesdays at the same time. When EIA numbers differ from market expectations, prices can move fast.
Crude oil prices also show seasonality, but it is less straightforward. Gasoline prices tend to rise in summer because of higher driving demand and stricter emissions requirements. Heating oil demand peaks in winter, especially in the northeastern U.S.
The Two Benchmark Crude Oil Contracts
The NYMEX West Texas Intermediate (WTI) and ICE Brent contracts are the two most important crude oil futures in the world. In 2016, WTI traded 277 million contracts while Brent traded 211 million.
The WTI contract delivers 1,000 barrels (42,000 gallons) of light sweet crude oil at Cushing, Oklahoma. Quick terminology note: “light” means lower density and viscosity. “Sweet” means lower sulfur content. Light sweet crude is easier and cheaper to refine, so it commands higher prices than heavy sour crude.
Brent crude is also light and sweet, delivered under a different mechanism. The ICE Brent contract is cash settled based on an exchange-provided index, but with a physical delivery option.
The history is fascinating. NYMEX launched its crude oil contract in 1983 on the same day the Chicago Board of Trade launched a competing Louisiana-based contract. NYMEX won, partly because it already had successful gasoline and heating oil contracts, making it easy to trade crack spreads (the price difference between crude and its refined products) on a single exchange.
Natural Gas: More Derivatives Than Any Other Commodity
NYMEX launched its natural gas futures contract in 1990. It delivers 10,000 MMBtu at the Henry Hub in Louisiana, which is also the primary cash market benchmark. Volume hit 97 million contracts in 2016.
What makes natural gas unique is the sheer variety of derivative products. While natural gas itself is pretty uniform in quality (unlike crude oil), prices vary widely by location. So the market developed basis swap contracts that settle on the difference between the NYMEX price and the spot price at specific locations like Chicago or New York.
There are also swing contracts based on daily prices, allowing traders to hedge not just monthly but daily price changes. A trader can combine NYMEX futures, a basis contract, and a swing contract to create a synthetic futures contract reflecting daily price changes at a specific location. That is a level of customization you do not see in most commodity markets.
The Enron Effect
The chapter covers how OTC energy trading evolved, and Enron is central to the story. In 1999, Enron created EnronOnline, an electronic platform that briefly dominated energy derivatives trading. Enron was the counterparty to every trade on the platform.
When Enron declared bankruptcy in late 2001, the OTC energy market nearly collapsed. Everyone suddenly worried about counterparty credit risk. Two winners emerged: ICE (founded in 2000 by a consortium of energy firms and banks) and NYMEX. Both offered clearing through their respective clearinghouses, which eliminated the counterparty risk that had made OTC trading so dangerous.
By 2011, OTC energy clearing generated about $400 million (30 percent of revenue) for ICE and about $300 million (9 percent of revenue) for CME.
Futurization: When Swaps Became Futures
This is the most interesting regulatory story in the chapter. On October 12, 2012, ICE converted all of its OTC energy swaps to economically identical futures contracts overnight. More than 800 contracts were switched. NYMEX saw a similar migration, though less abruptly.
Why? Because October 12, 2012, was when the Dodd-Frank Act’s swap definition went into effect, triggering new regulations including swap dealer registration, reporting requirements, and potential position limits. By converting to futures, market participants avoided all of these requirements.
Before that date, OTC swaps were 90 percent of ClearPort activity. One week later, block-traded futures contracts accounted for 70 percent of volume. More than half of the estimated $18 trillion in daily energy swap trading moved to futures.
This “futurization” was a direct response to regulation. It was not that futures were better products. It was that swaps suddenly came with a regulatory burden that futures did not. The irony is that Dodd-Frank was designed to bring more oversight to the energy derivatives market, but a large chunk of that market simply reclassified itself to avoid the oversight.
Speculation: Helpful or Harmful?
The chapter addresses the ongoing debate about speculation in energy markets. Between managed futures, commodity index swaps, and ETFs, speculative investment in energy grew enormously from the 1980s to 2008. Assets under management in managed futures alone went from less than $1 billion to over $200 billion by 2008.
A 2006 Senate report argued that speculation was pushing up U.S. energy prices. A 2007 follow-up found that a single speculative hedge fund was able to dominate the U.S. natural gas market in 2006.
But the research picture is mixed. Some studies show that speculative positions largely offset hedgers’ positions, which is exactly what theory says should happen. The chapter cites work showing that financial end-users (speculators) hold net long positions that offset the net short positions of commercial end-users (hedgers). Swap dealers sit in between, intermediating both sides.
My Take
The Enron story and the futurization of swaps are the standout sections. They show how market structure and regulation interact in ways that policymakers do not always anticipate. Dodd-Frank tried to regulate swaps. The market responded by converting swaps to futures. The products are economically identical but the regulatory treatment is completely different.
The chapter also reinforces how much energy markets rely on storage and seasonal patterns. If you want to understand natural gas prices, look at the weather forecast and the EIA storage report. Everything else is secondary.
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