The Myth of 6David Forest
There was a lot of talk this week about the number 6. In the oil and gas world, 6 is an almost magical number. It is supposedly the "proper" ratio between the prices of oil and natural gas. Today, the ratio sits at 18. Does this mean gas is a screaming buy? A lot of investors believe so. This week we look at some surprising numbers showing that "the rule of 6" may not be as firm as many think. Conditions in the gas market are not normal right now. And in abnormal times, we get abnormal numbers. We'll look at what's happened to make gas and oil prices go to such extremes, and what it might take to get them back together. If you're considering investing in natural gas over the next couple of years, I think you'll find this letter extremely valuable.
We'll also look at this week's action in the U.S. bond market. This was a watermark week for U.S. bonds, with the government auctioning over $100 billion in new notes. A number of analysts noted the large jump in yields on these new issues, raising fears that investors are moving away from Treasuries at a time when the U.S. needs a lot of new buying in order to finance its deficit spending. We'll look at those numbers and also at a different, less-reported statistic on these auctions that shows investor interest may be stronger than is widely believed. But first let's jump into the oil and gas market...
The Rule of 6
For years, there's been a problem in the oil and gas industry. How to compare oil reserves to gas reserves. Analysts love to compare companies across an industry, to benchmark which outfits are in the top quartile or decile (and which are in the lowest). But comparisons are difficult in the petroleum sector because the industry is in fact two largely separate businesses. Oil production and gas production. True, both of these commodities are produced by drilling and transported by pipelines. But in terms of physical properties, markets and value, oil and gas are very different.
This hasn't stopped analysts from trying to lump the two together. The prevailing method for comparing oil to gas has been "the rule of 6". The rule is based on energy equivalents. If you burn a "standard" barrel of crude oil, it will release about 6 million BTUs of energy (the definition of a standard barrel is also a problem, but we'll leave that aside for the moment). If you burn one thousand cubic feet of gas (one Mcf), it releases about 1 million BTUs. Therefore analysts decided that one barrel of oil (6 million BTU) is equivalent to 6 Mcf of gas (at 1 million BTUs per Mcf).
Suddenly it became easy to compare oil and gas reserves. Say we have two producers, one focused on oil and one on gas. The oil producer owns 50 million barrels of reserves. The gas producer holds 300 million Mcf of reserves. If we want to compare the two, we simply divide the gas producer's reserves by 6 to get a "barrel of oil equivalent" number. Also called BOE. So 300 million Mcf becomes 50 million barrels of oil equivalent. The two companies have roughly equal reserves. Simple. Less commonly, analysts convert oil reserves to "Mcf equivalent" by multiplying 6. Either way, we get numbers that can be plugged into an industry-wide report to see who is holding the largest amount of energy in the ground.
The rule of 6 worked so well for comparisons that it has become standard throughout the oil and gas industry. Even regulators use it. Public petroleum companies regularly report reserves in barrels of oil equivalent, dividing by 6 to convert gas to oil. Even the IRS embraces the rule, officially defining a barrel of oil equivalent for tax purposes as an amount of fuel containing 5.8 million BTUs.
Energy Versus Value
The problem with the rule of 6 is that it's come to be recognized as an indicator of value. If an Mcf of gas contains one-sixth the energy of a barrel of oil, then the gas price should trade at one-sixth the oil price, right? Investors particularly have used the rule as an investment timing indicator. If the oil price is trading at more than six times the gas price, either gas is undervalued (go long) or oil is overvalued (go short). If the ratio falls below six, it's time to short gas and buy oil. Thus the oil/gas price ratio became one of the investment community's most-watched metrics.
This is where things get tricky. It turns out that energy content and price aren't always correlated. To understand why, let's look at some of the theory behind the argument.
The idea that oil and gas prices should be related to energy content is based on the concept of fuel-switching. Fuel-switching is the ability of companies that generate electricity or heat to use different fuels to fire their boilers or generating equipment. Some electric utilities have the ability to fuel their power plants with either natural gas or oil (usually semi-refined into distillate or residual fuel oil). Some manufacturers who generate their own heat or power for their operations also have the ability to switch between different fuels for their equipment.
In theory, fuel-switching should ensure that oil and gas prices stay linked on an energy-content basis. Suppose a power plant operator needs 600 million BTUs of energy from fuel to in order to power its turbines and generate 1 MW of electricity. Those 600 million BTUs could come from burning 600 Mcf of gas (at 1 million BTUs per Mcf) or 100 barrels of fuel oil (at 6 million BTUs per barrel). If the power plant has the ability to switch between oil and gas, the operator will simply use whichever fuel is cheaper. If gas is trading at $7/Mcf and oil at $70/barrel (a 10-to-1 ratio), gas is the cheaper option. 600 Mcf of gas at $7 costs the company $4200, while 100 barrels of oil at $70/bbl would cost $7000. At these prices, users will switch to gas. This drives up gas demand and prices, and lowers oil demand and prices. This will continue until the oil/gas price ratio falls back to 6-to-1, at which point oil is equally affordable as fuel to generate the 600 million BTUs. If the oil price falls further, oil will be cheaper than gas and power plants will switch. This drives up oil prices and drives down gas prices. Theoretically, prices should settle around the 6-to-1 ratio.
That's the theory. In practice, things are a lot less perfect. The main problem is that not all power and heat generation has the ability to switch between fuels. Fuelswitching requires specialized equipment. In the U.S. there's about 450 gigawatts of total installed electricity and heat generation capacity. Only 145 gigawatts (30%) of those facilities have fuel-switching ability. The rest are designed to run only on oil or only on gas. Period.
And even those generators that have the technical ability to switch fuels are often constrained by other factors. Federal or state environment regulations restrict generators from burning oil in some areas because this is seen as being a dirtier fuel. Often operators must apply to regulators for permission to switch. And getting permission can take time, at which point the price disparity between oil and gas might have been lost. Some operators are also constrained from switching because they've purchased oil or gas on long-term contracts. They can't simply cancel their purchases because they've decided to switch fuels. In some areas, there simply isn't a viable supply of oil or gas, despite the facility's switching ability.
These factors greatly restrict the number of generators that can practically switch between oil and gas. Of the 145 gigawatts of switchable U.S. generating capacity, only about 60 gigawatts have no factors that limit the operators' ability to quickly change fuels. The other 85 gigawatts are restricted in their choice by some or all of the issues mentioned above. The end result being that only about 15% of overall U.S. generating capacity has the practical ability for fuel-switching.
The International Price Breakdown
Fuel-switching is one of the reasons for the supposed "6-to-1" link between oil and gas prices. Outside of the U.S., the development of contracts for international trading of gas has also helped tie oil and gas prices together. Particularly when it comes to liquefied natural gas (LNG).
One of the earliest buyers of LNG was Japan. At the time the initial Japanese LNG purchase contracts were signed, much of Japan's power generation came from oilfired generators. It was therefore decided that LNG purchase prices should be based on oil prices. LNG was priced in relationship to the "Japanese Crude Cocktail". There wasn't any market reason for the pricing relationship, as almost no Japanese generators had the ability to switch between gas and oil. The oil price simply provided a convenient benchmark for price discovery in the new LNG market.
Other markets around the world also embraced oil as an easy scale for setting gas prices. Much of northeast Asia adopted the Japanese pricing model. Continental Europe also chose to link its gas prices to oil. The Netherlands became the Continent's premier gas exporter in the early 1960s when the super-giant Groningen gas field was discovered. The Dutch government decided at the time that gas should be priced at the value of the fuels it was displacing. And at the time gas was mostly displacing oil. The Dutch applied this pricing formula to their gas exports to the rest of Europe, and the oil-to-gas price linkage became the effective policy throughout much of the Continent.
Because of this history, much of the gas traded in Asia and Europe is still priced based on oil (the Japanese Crude Cocktail in Asia and generally Brent Crude in Europe). However, even in these markets the 6-to-1 ratio has broken down over the last few years.
Take Asian LNG prices, for example. About 80% of LNG is sold on long-term contracts. LNG producers need to lock-in long-term sales in order to secure the billions of dollars in debt financing they need to build facilities to process and transport the gas. Banks simply don't want to take the risk of spot prices collapsing and the producer not having enough cash flow to pay back the loan. Because longterm contracts are a requirement, LNG buyers have a lot of clout when it comes to negotiating prices. And over the last few years buyers became very concerned about linking gas prices to oil prices. In early 2003, the "energy equivalent" gas price based on the prevailing oil price was about $5/Mcf. By mid-2005 this had doubled to $10 as oil approached $100 per barrel. This was more than most contract LNG buyers wanted to pay.
The solution was "S-curves". Buyers began to negotiate these curves into their purchase agreements in order to moderate the effect of rising oil prices. Basically, an S-curve changes the rate at which gas prices increase with an increasing oil price. For a typical S-curve, if oil jumped from $25 to $50 per barrel the curve might also allow the gas purchase price to double, say from $4 to $8 per Mcf. But if oil rose above $50, the curve prescribed a much slower increase in gas prices. A rise in oil from $50 to $100 (a 100% increase) might only cause gas prices to rise from $8 to $12 (50%). Thus LNG buyers were somewhat insulated from skyrocketing oil prices.
These S-curves had a major impact on the ratio of oil prices to LNG gas prices. Up until 2003, oil and gas prices held almost exactly around the 6-to-1 ratio. But when S-curves began to be introduced and the rise in gas prices was capped, the ratio rose. Oil got expensive faster than gas. By late 2006, Japanese Crude Cocktail oil was selling for 10 times the price of contract LNG. The 6-to-1 ratio had broken down.
Gas Versus Gas
A final factor involved in distorting the 6-to-1 ratio is the availability of gas supply. Jensen Associates have produced some very revealing research on this aspect of the gas market. Jensen (www.jai-energy.com) are one of the leading groups in studying the economics of natural gas markets. They draw on a wealth of data from LNG and land-based gas around the world, and their views often differ considerably from the "conventional wisdom" on these markets.
Jensen found that a surplus or shortage of gas supply is a critical factor in determining whether the 6-to-1 rule holds true. To understand this, let's look at the types of gas users we have in a typical market. As discussed above, a certain portion of gas users are electrical generators and manufacturers who have the ability to use either gas or oil to fire their equipment. This group represents the "marginal demanders" in the gas market. They can take or leave gas depending on the price. If gas supply rises slightly the gas price falls and we get a ratio above 6- to-1. The marginal users will switch to gas. Gas demand thus increases and gas prices rise, restoring the 6-to-1 ratio. If gas supply falls slightly the gas price rises and we get a ratio below 6-to-1. Marginal users now switch to oil. Gas demand falls and gas prices drop back to 6-to-1. Simple enough.
But what happens if gas supply changes drastically? For example, in the U.S. during hurricanes Katrina and Rita, when most of Gulf of Mexico gas production was temporarily shut-in. Or when a gas-producing region reaches peak production and begins to decline, like the British North Sea during the last few years. Then gas prices begin to be set by a different group of gas users, the "inelastic demanders". These are generators and manufacturers who must use gas. Utilities whose generating equipment is only designed to use gas as an input. Or manufacturers like fertilizer producers who need gas as one of the feedstocks to make their product. These groups don't have the option of switching fuels just because the gas price rises. At 4-to-1 or 2-to-1 or 1-to-1 pricing, they still need gas. Or they have to shutdown completely (not an easy option if you're an electrical utility supplying a major city).
Because the inelastic demanders have no choice but to buy gas, they will paywhatever it takes to secure supply (assuming they can still make a profit). This is where gas supply becomes critical. If supply is relatively plentiful, these users can get all the gas they want. And there's enough gas left over that the marginal demanders (the users who can switch between oil and gas) can get the supply they need. In this case, the marginal demanders become the ones setting the gas price, and they will set the price near the 6-to-1 ratio. But if gas supply becomes restricted, there may not be enough left for the marginal demanders. The inelastic demanders (who use only gas) will bid against each other to secure the valuable gas supplies, driving the price up independent of the oil price. Thus oil and gas prices get "decoupled" and the 6-to-1 ratio becomes meaningless.
We can also get the reverse scenario. A severe oversupply of gas. If for some reason a large amount of new gas supply enters the market (we'll look at why that might happen in a moment), the demand pattern changes again. Now the inelastic demanders can get all the gas they want. So can the marginal, switchable demanders. And even after all of these users have taken all the gas they want, there's still gas left over. So gas suppliers will start trying to undercut each other, lowering their prices in an attempt to sell their uncontracted gas. These suppliers don't care what the oil price is. They'll sell at a 10-to-1 or 15-to-1 gas price. Any sale is better than nothing.
Obviously in this situation all the switchable users will change to cheap gas. But even with this extra demand, there is still more than enough gas to go around. Because of the gas surplus, the marginal demanders lose their ability to set gas prices. Prices are determined by "gas on gas" competition, as various gas suppliers battle to find a market for their products.
Know Thy Market
All of this means that anyone interested in the gas market (including investors) should take caution in using the oil-to-gas price ratio as an indicator. Looking at the number alone is simply not enough. We need to ask ourselves whether gas supply and demand in the market we're looking at are balanced enough for the 6-to-1 ratio to be expected to function.
Here again, Jensen Associates provides some critical data on just how often the 6- to-1 ratio holds true in the world's major gas markets. Looking at the U.S. over the last 17 years, there has in fact been only one, relatively short period when the 6-to-1 relationship existed. In 2003 to 2005, Henry Hub gas traded at 6.5-to-1 in relation to WTI oil. Close to 6. But for the rest of the study period, the relationship wasn't even close. Between 1991 and 2000, the average ratio was 9.5-to-1. From 2006 to 2008, the ratio was even more skewed at 10-to-1. Through almost two decades, the 6-to- 1 rule held true (more or less) for only three years! Hardly a reliable indicator.
Why did the 6-to-1 rule fail so badly? For the reasons we discussed above on gas supply. I mentioned there were two periods when U.S. gas appeared underpriced relative to oil: 1991 to 2000 and 2006 to 2008. Both of these periods were times of rising gas production in the U.S. Between 1990 and 1998, American production rose by 2.5 trillion cubic feet yearly. Largely due to accelerated development in the Gulf of Mexico after taxes in the region were reduced. This growing production kept the U.S. market well supplied, creating gas on gas competition and keeping prices low.
After 1998, the U.S. production profile changed. Between 1998 and 2004, overall U.S. production held flat as new Gulf of Mexico discoveries became fewer and output from old wells declined. In 2005 and 2006, production actually declined by about 500 billion cubic feet yearly. This "restricting" of gas supply probably explains why gas prices moved closer to the 6-to-1 ratio during this period. With less gas supply to go around, gas on gas competition decreased. Marginal demanders began to set gas prices in relationship to oil prices.
Then in 2007, something new happened. Shale gas. The widespread development of new shale gas plays across the U.S. created the first major boost in national gas production since the late 1990s. In 2007, U.S. gas output rose by 1 trillion cubic feet. In 2008, production grew by a further 1.5 trillion cubic feet. With this increased supply, gas on gas competition returned and the 6-to-1 ratio broke down, falling back to 10-to-1.
This is where we find ourselves today. U.S. production for March 2009 (the last month for which we have data) came in at a record 2.28 trillion cubic feet. Gas to gas competition in the U.S. is back! Of course, how long it will last depends on the level of new drilling and new production adds (both of which are declining with low prices). But to simply assume that gas is undervalued because today's oil/gas price ratio is above 6-to-1 ignores history. In some markets, the 6-to-1 ratio just doesn't apply.
Increased gas on gas competition may also be ahead for the global LNG market. The past decade has seen a large build-out of LNG capacity. Between 2000 and 2007, global LNG shipments have risen by 70% to 170 million tons yearly. And there is a huge amount of new capacity set to come online over the next five years. All of these projects were built on the assumption that the world needed more gas supply, which indeed appeared to be true over the last few years with spot LNG prices rising as high as $20/MMbtu. But the world has changed. Gas demand is dropping in many of the world's demand centers as the global recession shuts down manufacturing. U.S. gas consumption fell 23% in the first quarter of 2009 alone. Many LNG operators assumed that the U.S. would be the "market of last resort" if they failed to sell their product in Asia or Europe. But with U.S. demand falling and domestic shale gas production rising, it's now doubtful whether America will need much (or any!) of the new global LNG supplies.
This combination of rising LNG production and declining demand may create global gas on gas competition as suppliers slash prices to try to sell their cargos anywhere they can. If so, we could see a worldwide breakdown in the 6-to-1 price ratio as cheap LNG decouples global gas markets from oil prices.
Note: The information provided in this newsletter is based on the independent research of Dave Forest and Notela Resource Advisors Ltd. and is intended solely for informative purposes and is not to be construed, under any circumstances, by implication or otherwise, as an offer to sell or a solicitation to buy or trade any securities or commodities named herein. Information contained in this newsletter is obtained from sources believed to be reliable, but is in no way assured. All materials and related graphics provided in this newsletter and any other materials which are referenced herein are provided "as is" without warranty of any kind, either express or implied. No assurance of any kind is implied or possible where projections of future conditions are attempted. Readers using the information contained herein are solely responsible for verifying the accuracy thereof and for their own actions and investment decisions. Neither Dave Forest nor Notela Resource Advisors Ltd., make any representations about the suitability of the information delivered in this newsletter or any other materials that are referenced herein for any purpose whatsoever. The information contained in this newsletter does not constitute investment advice and neither Dave Forest nor Notela Resource Advisors Ltd. are registered with any securities regulatory authority to provide investment advice. Readers are cautioned to consult with a qualified registered securities adviser prior to making any investment decisions.The information contained in this newsletter has not been reviewed or authorized by any of the companies mentioned herein.
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February 27th, 2021
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