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In the petroleum industry, refinery executives are most concerned about hedging the difference between their input costs and output prices. Refiners’ profits are tied directly to the spread, or difference, between the price of crude oil and the prices of refined products: gasoline and distillates (diesel and jet fuel).

This spread is referred to as a crack spread due to the refining process that cracks crude oil into its major refined products.

The Role of the Crack Spread

A petroleum refiner, like most manufacturers, is caught between two markets: the raw materials he needs to purchase and the finished products he offers for sale. The price of crude oil and its principal refined products are often independently subject to variables of supply, demand, production economics, environmental regulations and other factors. As such, refiners and non-integrated marketers can be at enormous risk when the price of crude oil rises while the prices of the refined products remain stable or decline.

Such a situation can severely narrow the crack spread, which represents the profit margin a refiner realizes when he procures crude oil while simultaneously selling the refined products into a competitive market. Because refiners are on both sides of the market at once, their exposure to market risk can be greater than that incurred by companies who simply sell crude oil, or sell products to the wholesale and retail markets.

In addition to covering the operational and fixed costs of operating the refinery, refiners desire to achieve a rate of return on invested assets. Because refiners can reliably predict their costs, other than crude oil, an uncertain crack spread can considerably cloud understanding of their true financial exposure.

Further, the investor community may use crack spread trades as a hedge against a refining company’s equity value. Other professional traders may consider using crack spreads as a directional trade as part of their energy portfolio, with the added benefit of its low margins (the crack spread trade receives a substantial spread credit for margining purposes). Together with other indicators, such as crude oil inventories and refinery utilization rates, shifts in crack spreads or refining margins can help investors get a better sense of where some companies,  and the oil market, may be headed in the near te

Did you know: There are several ways to manage the price risk associated with operating a refinery. Because a refinery’s output varies according to the configuration of the plant, its crude slate, and its need to serve the seasonal product demands of the market, there are various types of crack spreads to help refiners hedge various ratios of crude and refined products. Each refining company must assess its particular position and develop a crack spread futures market strategy compatible with its specific cash market operation.Simple 1:1 Crack Spread

The most common type of crack spread is the simple 1:1 crack spread, which represents the refinery profit margin between the refined products (gasoline or diesel) and crude oil. The crack spread, the theoretical refining margin, is executed by selling the refined products futures and buying crude oil futures, thereby locking in the differential between the refined products and crude oil.

The crack spread is quoted in dollars per barrel; since crude oil is quoted in dollars per barrel and the refined products are quoted in cents per gallon, diesel and gasoline prices must be converted to dollars per barrel by multiplying the cents-per-gallon price by 42 (there are 42 gallons in a barrel).

If the refined product value is higher than the price of the crude oil, the cracking margin is positive. Conversely, if the refined product value is less than that of crude oil, then the gross cracking margin is negative.

When refiners look to hedge their crack spread risk, they are typically naturally long the crack spread as they continuously buy crude oil and sell refined products. If refiners expect crude oil prices to hold steady, or rise somewhat, while products prices fall (a declining crack spread), the refiners would sell the crack; that is, they would sell Gasoline or Diesel (ULSD) futures and buy Crude Oil futures. Whether a hedger is selling the crack or buying the crack reflects what is done on the product side of the spread, traditionally, the premium side of the spread.

CME Group offers a Crack Spread Conversion Calculator

Example of 1:1 Crack Spread

In January, a refiner reviews his crude oil acquisition strategy and his potential gasoline margins for the spring. He sees that gasoline prices are strong, and plans a two-month crude-to-gasoline spread strategy that will allow him to lock in his margins. In January, the spread between April crude oil futures at $50.00 per barrel and May RBOB gasoline futures at $1.60 per gallon or $67.20 per barrel, presents what the refiner believes to be a favorable 1-to-1 crack spread of $17.20 per barrel.

Typically, refiners purchase crude oil for processing in a particular month and sell the refined products one month later.

The refiner decides to sell the crack spread by selling RBOB Gasoline futures and buying Crude Oil futures, thereby locking in the $17.20 per barrel crack spread value. He executes this by selling May RBOB Gasoline futures at $1.60 per gallon or $67.20 per barrel, and buying April Crude Oil futures at $50.00 per barrel.

Two months later, in March, we see prices have risen.

The refiner now purchases the crude oil at $60.00 per barrel in the cash market for refining into products. At the same time, he also sells gasoline from his existing stock in the cash market for $1.75 per gallon, or $73.50 per barrel. His crack spread value in the cash market has declined since January, and is now $13.50 per barrel

Since the futures market reflects the cash market, April Crude Oil futures are also selling at $60.00 per barrel in March — $10 more than when he purchased them. May RBOB Gasoline futures are also trading higher at $1.75 per gallon or $73.50 per barrel.

To complete the crack spread transaction, the refiner buys back the crack spread by first repurchasing the Gasoline futures he sold in January, and he also sells back the Crude Oil futures. The refiner locks in a $3.70 per barrel profit on this crack spread futures trade.

The refiner has successfully locked in a crack spread of $17.20. The futures gain of $3.70 is added to the cash market cracking margin of $13.50.

Had the refiner been un-hedged, his cracking margin would have been limited to the $13.50 gain he had in the cash market. Instead, combined with the futures gain, his final net cracking margin with the hedge is $17.20 — the favorable margin he originally sought in January.

If you have any questions send a message or contact me

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Peter Knight Advisor

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NYMEX Light Sweet Crude Delivery Location: Cushing Oklahoma

Cushing, Oklahoma is the delivery location for the NYMEX benchmark Light Sweet Crude Oil futures contract.

Light Sweet Crude Oil futures contract specifies delivery of a common stream of light sweet crude U.S. oil grades, which are referred to as WTI or Domestic Sweet crude oil.

The Cushing physical delivery mechanism is a network of nearly two dozen pipelines and 15 storage terminals, several with major pipeline manifolds. Cushing is called The Pipeline Crossroads of the World.

Storage Capacity

This vibrant hub has 90 million barrels of storage capacity where commercial companies are active participants in the market. The storage capacity has grown dramatically over the past few years and now accounts for 13% of total U.S. oil storage.

Crude oil inventory levels reached a record high of 69 million barrels in storage in early 2017.

Transporting Oil

Cushing’s inbound and outbound pipeline capacity is well over 6.5 million barrels daily.

It is interconnected to multiple pipelines, each capable of transporting hundreds of thousands of barrels of oil daily.

Significant investments in infrastructure, along with increased U.S.  oil production, and the repeal of the oil export ban have strengthened the role of WTI as the leading global benchmark.

As U.S. oil production continues to increase, Cushing will play an even greater role in the global petroleum landscape.

If you have any questions send a message or contact me

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Peter Knight Advisor

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As the delivery point for Henry Hub Natural Gas futures, the Henry Hub, located in Erath, Louisiana, is a nexus of several natural gas interconnections.

Here you will find interstate and intrastate pipelines, as well as other related infrastructure. Because of this level of interconnection, Henry Hub offers natural gas shippers and marketers ready access to pipelines serving markets across the entire United States.

The commercial relevance of Henry Hub is the result of its strategic location and logistical infrastructure.

When local markets across the United States price their natural gas, they tend to do so based off a differential to Henry Hub. This differential accounts for regional market conditions, transportation costs and available transmission capacity between locations.

A Closer Look at Henry Hub

Henry Hub is owned and operated by Sabine Pipe Line LLC and its affiliates. They are a full-service header system which offers various receipt and delivery capability, hub management services and an extensive interconnection to one of the most important U.S. pipeline structures.

Through its transportation program, Sabine provides transportation services for both the Henry Hub and Sabine’s mainline. This allows a shipper to transfer gas from one pipeline to another.

The Sabine Pipeline

The Sabine Pipeline is a bidirectional mainline pipeline that stretches from Port Arthur, Texas, to the Henry Hub. It is an interstate pipeline that is certified as an open-access gas transporter, and it is directly connected to four industrial consumers and one producer.

Henry Hub is interconnected to eight pipelines and three intrastate pipelines. These pipelines are part of the highly integrated U.S. transmission grid.

Location

When we look at regional production, we begin to see the importance of this location.

Monthly average natural gas production in Texas has been approximately 637,021 million cubic feet monthly since January 2014. This represents 27% of U.S. marketed production, making Texas the state with the highest natural gas production.

Louisiana produced a monthly average of 155,481 million cubic feet monthly from January 2014 through November 2016. This represents 7% of U.S. marketed production.

Storage Facilities

Henry Hub also has a direct connection to storage facilities, including Jefferson Island, Acadian and Sorrento.

These facilities are salt-dome caverns characterized by high deliverability and high cycling rate, which allow for several withdrawal and injection cycles each year.

As you can see Henry hub is situated in the Southwest region of the United States, which has one of the most developed and extensive pipeline networks in the country.

This allows natural gas to be moved from supply basins and exported to major consumption markets.

Given the physical and logistical attributes of Henry Hub, it is easy to see why this location has become the pricing benchmark for the natural gas market.

If you have any questions send a message or contact me

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Peter Knight Advisor

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Managing Natural Gas Risk

Calendar spread risk management is one of the key issues in trading natural gas in North America.

Seasons

Natural gas prices show clear seasonality broken into two main seasons: winter, or withdrawal season, and summer, injection season. Winter in the United States generally ranges from November to March; summer is from April to October. During the summer season, gas demand decreases while production continues, resulting in excess natural gas that can be stored. During the winter season, gas consumption peaks as a result of increased heating demand from residential end-users, the industrial sector and utilities. As a result of unpredictable winter demand, winter natural gas futures generally trade at a premium to the summer futures.

Two examples of natural gas calendar spreads could be a summer-winter spread using the averages of the summer and winter months and a March-April spread, when winter demand slows and moves into the summer injection season. Natural gas storage facilities offer physical optionality to balance supply and demand in the gas market. Natural gas providers have the option to inject excessive gas production into underground storage facilities.

Example One

A gas marketer has entered into a contract to sell to a gas utility firm 50,000 MMBtu for December delivery at Henry Hub, Louisiana for a fixed price $3.319 per MMBtu. This marketer decides to hedge his physical volume risk so he buys 50,000 MMBtu from a producer for June delivery at Henry Hub for a fixed price of $3.095 per MMBtu. Essentially, this marketer has bought the June and December calendar spread for $0.224 per MMBtu with long June Natural Gas and short December Natural Gas at Henry Hub.

One approach to balance his price risk is to use a storage facility as a way to move forward his June long position. The marketer injects 50,000 MMBtu gas into the underground storage in June and withdrawals it in December for the sale position with overall storage cost of $0.12 per MMBtu and overall financing cost of $0.10 per MMBtu. As a result, this marketer makes $0.004 per MMBtu after the storage and financing costs.

Example Two

Another alternative approach would be using financial instruments to hedge the calendar spread risk. The marketer sells 50,000 MMBtu or five Henry Hub June futures contracts and buys 50,000 MMBtu or five Henry Hub December futures contracts. With June futures priced at $3.105 and December futures priced at $3.305, this marketer effectively sold the June-December calendar spread for $0.2. Overall this marketer is able to unwind his positions and make $0.224-$0.2=$0.024 profit with financial instruments.

Summary

Calendar spread risk management is a key issue for some participants in the Natural Gas market. We have just demonstrated one way futures could be utilized to manage that risk.

If you have any questions send a message or contact me

Regards,
Peter Knight Advisor

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Natural gas production in the United States has been rising steadily since 2011. Over 90% of the increase in domestic natural gas production has happened in the seven most prolific shale formation regions, with the largest increases coming from Marcellus. While the states within those shale regions produce the highest volumes of natural gas, there is a broad area of production across the majority of the United States.

Gas storage levels also plays a key role when looking at supply side. Natural gas in storage provides a valuable cushion to meet peak demand. During periods of lower demand, surplus can be injected into storage facilities. The natural gas storage infrastructure can be utilized to accommodate sudden rises or falls in demand, up to a certain point.

Overall, natural gas supply is characterized as being quite responsive to a relatively wide range of prices. However, restrictions of the existing infrastructure impact additional flows, rendering the supply curve very inelastic even when prices are high. On the demand side, overall economic growth, weather and competing fuel prices affect gas demand. Here is a general breakdown of the demand of natural gas across the some of the main sectors.

Demand of Natural Gas

When it comes to electrical power generation, natural gas power burn has been increasing due to low gas prices relative to coal. The second largest sector is within industrial usage. Natural gas is used as raw material to produce fertilizer, chemicals, and hydrogen.

Residential and commercial sector utilize gas as a fuel for heating or cooling purposes. Natural gas suppliers are usually insulated from short-term fluctuations through existing tariffs. The transportation sector accounts for a small amount of natural gas used as vehicle fuel from liquefied natural gas or LNG.

Over the last few years, the United States has seen the development of new LNG exporting terminals, mostly in the gulf coast region. The demand for natural gas for LNG export to international markets is expected to rise significantly.

Natural Gas and Weather

Gas demand has a high price-sensitivity to changes in weather. Weather pattern changes are the primary contributor to gas price volatility. Gas prices also show a clear seasonal pattern with higher prices in fall and winter months in response to higher demand for heating. And lower prices the spring and summer months as demand drops.

Summary

When traders look at the supply and demand for natural gas in the United States, there are a variety of variables that impact the product, distribution, and use of this product throughout the year.

If you have any questions send a message or contact me

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Peter Knight Advisor

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Managing Risk in the Energy Market

Like other commodities with wholesale markets, the electricity wholesale market is where electricity is frequently bought and then resold before it ever reaches the end customer. Wholesale participants in this market may not always own resources that generate power and they may not always directly serve the end users.

Three major types of participants engaging in the resale markets include:

Electricity utility companies

Independent power producers

And Electricity marketers

In addition to directly buying or selling in the spot market, companies can also engage in bilateral transactions through negotiation, using a brokerage platform, or through a futures exchange. The transaction could be either a standardized contract like futures or they could be customized, like complex contracts known as structured transactions. In between the wholesale market and the end-customer are the Load Serving Entities (LSE). An LSE can either procure electricity in the wholesale market or they may own their own electricity generation resources.

Options Hedging Example

Assume it is March and the nuclear plant economist has a positive short-term outlook for PJM regional electricity spot price during peak hours for the month of May. The nuclear plant operation costs are $20 dollars per MWh.

Plant’s Goal:

Maximize profit

Eliminate downside risk to fund operations at $20 per MWh

How could the economist take advantage of the potential for a short-term price increase and protect their downside price risk to ensure they have enough funds to maintain continuous operations? 

The economist has two options:

Negotiate a private deal (costly, time consuming,)

Hedge using options on futures (more flexibility, lower costs)

Assume the May average forward price for PJM Western Hub is around $35 dollars per megawatt hour. Given its 1000 MWh capacity and 80% utilization rate in peak hours, this plant needs to sell around 800 MWh for each peak hour during the month of May.

How many contracts would be need to hedge the 800 MWh?

CME Group PJM Western Hub Real-Time Peak Calendar-Month 50 MWh Options Contract (ticker symbol PMA)

800 MWh / 50 MWh = 16 contracts (per day)

16 contracts * 20 days = 320 total contracts

The most straightforward approach for this plant to manage its position, is to sell their generation on the spot market while also going long a May PMA Out-of-the-Money Put, with a $21 strike price.

Strategy:

Sell output at spot physical market

Long OTM Put option at strike $21 per MWh for all peak hours in May

Assuming the current May average forward price for PJM Western Hub is around $35 per MWh, the out-of-the-money put option might only cost $0.3 per MWh to execute.

	Scenario 1 Payoff	Scenario 2 Payoff
Spot Market in May	$40 per MWh	$17 per MWh
320 PMA Put Option @ $21 strike per MWh	$0.3 per MWh Put Premium Paid (Option expired worthless)	$0.3 per MWh Put Premium Paid $21-$17=$4 per MWh profit (Option was in-the-money)
Net Revenue	$40 – $0.3=$39.70 per MWh	$17+$4 – $0.3= $20.7 per MWh

 

Futures Hedging Example

Assume it is January, and a utility has a contract to serve their clients in the PJM Western Hub region, for 100 MWh for all the peak hours in the month of June.

How could the utility hedge their price risk in June?

The Utility has three options to hedge their risk:

PJM Spot Market

Bilateral customized transaction

Exchange traded futures

Spot Market

The utility has the option to wait until June to buy electricity from the day-ahead, or real-time, Spot market, which is operated and cleared through the ISO. If they do this, they will be exposed to the price risk between January and June.

Bilateral Agreement

They also have the option to negotiate a bilateral contract with other firms in the wholesale market. But it usually takes time and counterparty risk assessment to be able to execute a customized transaction. Depending on the negotiation, the price this company could get might not be competitive as it is not a market price.

Exchange-Traded Futures

The utility decides to use standardized electricity futures from a futures exchange to hedge its price risk, as it offers the necessary liquidity to meet their needs while eliminating the counterparty risk.

To hedge their risk, the utility uses the PJM Western Hub Peak Calendar-Month Real-Time LMP Futures (L1) provided by CME Group.

Assume there are 20 days of peak days in the month of June, and the futures contract (L1) has a size of 80 MWh. For 100 MW for all the peak hours, this LSE is obligated to 100 MW * 16 peak hours * 20 days = 32,000 MWh. To hedge its price exposure, it buys 400 contracts of L1 June futures at the price of $30 per MWh.

When June comes, the utility buys electricity from the real-time spot market to serve its customers for 100 MW per hour during peak hours.

By the end of June, we might assume the average price of all the peak hours in PJM Western Hub is $40 MWh. Since they bought 400 contracts of L1 June Futures, the profit from the financial futures position will offset the cost from buying in the spot market.

In the end, this utility only pays $30 MWh to serve its customers while the spot market is at $40 MWh. By hedging their price risk using electricity futures, they saved $10 MWh, which equates to $320,000 overall.

If you have any questions send a message or contact me

Regards,
Peter Knight Advisor

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Recent bullish price action in the crude oil markets has many traders revisiting the spread between North Sea Brent and West Texas Intermediate (WTI) crude oil. Join CME Group’s Dave Lerman as he analyzes the current state of the two crude benchmarks, including:

How have massive U.S. production changes influenced the Brent-WTI spread?

What impact will tensions in Syria and the Middle East have?

How have U.S. crude exports of WTI impacted this important price differential?

If you have any questions send a message or contact me

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Peter Knight Advisor

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Join Dave Lerman in this special Trader’s Edge installment covering the energy renaissance in the U.S.

On September 12 the Energy Information Administration (EIA) announced that based on currently available estimates of worldwide crude production, the United States recently became the largest producer of crude oil in the world.

Given that a significant amount of oil produced in the U.S. is of the WTI grade (light sweet crude), the ramifications to the producers, users and traders of WTI are significant. See how this could affect WTI trading, including the following points:

As WTI becomes an even greater benchmark, hedgers and speculators are going to pay increasing attention to WTI futures and options across all time zones

U.S. production will no doubt effect the supply and demand equation from crude in an important way, and thus effect its price in the short-, intermediate- and long-term

Spreading WTI versus Brent and other crude products will take on more significance going forward

If you have any questions send a message or contact me

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Peter Knight Advisor

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In this episode of Trader’s Edge, our education experts will look at how low volatility has impacted options trading strategies, particularly around Crude Oil and Natural Gas products.

Two of the most liquid options products in the world, Crude Oil and Natural Gas now show open interest in the millions.

Despite constant headline news about energy price swings, implied volatility remains well below average. See how trading Crude Oil and Natural Gas options could benefit your trading strategy.

f you have any questions send a message or contact me

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Peter Knight Advisor

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The market is always showing early warning signs as to which direction it is heading into. The forward curve or term structure of the markets is one of those signals that offer a considerable amount of information as to the market sentiment and the potential direction of the market.

The term forward curve refers to a series of consecutive month’s prices for future delivery of an asset – like WTI or any of the main energy products traded on NYMEX. The NYMEX futures market (as well as the cleared over the counter markets) trade many months well into the future for the main oil commodities – WTI, Brent, HO, RBOB and Nat Gas.

Let’s start by discussing what the forward curve is and is not. The forward curve is not a price prediction model. The forward curve, or all of the forward months, trade all day long in dynamic patterns. A price along the forward curve does not necessarily mean that will be the price of oil when the market gets to that point in time. Rather it represents what both buyers and sellers agree (via a transaction) that the forward price of oil is that instant in time and subject to change in the next instant.

Thus the term structure or forward curve of the market is in essence a model showing how future months are valued relative to the nearby or spot contract month given all of the available market information at any instant in time. From an activity viewpoint, the majority of the activity, and thus liquidity, tends to be in the front to the forward curve with the far back months mostly following.

The shape of the forward curve is important to energy market participants. The forward curve or term structure of the forward market is looking at prices from many different maturities as they extend into the future. The curve trades in three different structures depending on market conditions. The least common configuration is a flat forward curve or when all prices going forward basically are mostly equal to each other. This represents a market that has no conviction with buyers and sellers indifferent as to the direction of the market. Rarely does the energy market trade in a flat formation.

I will use the following NYMEX HO forward curve (based on settlement prices for 6/6/14) to point out the two dominant structures that the forward curve generally trades in -backwardation and contango.

Source: NYMEX ULSD Data on 6/6/2014

The front part of the HO forward curve (July, 14 to Jan, 15) shows the curve structure in a contango – sometimes called a carry formation. A contango formation occurs when prices are higher in succeeding delivery months than the nearby or spot months. Generally a contango forms when the market is over-supplied (and/or demand is low). The market does not need all of the oil being produced (in the above case, HO) and the oil over and above what is needed generally winds up in inventory. Thus during periods of contango inventories generally build.

The back end of the above curve is in a backwardation (Jan, 15 through Dec, 15). A backwardation is a structure that suggests the market is undersupplied and/or demand is outstripping supply. In the above example it is the time of the year when demand for heating oil rises as a result of the winter weather or a period when normal supply flows cannot keep up with demand. It is during a period of backwardation in the market that inventories are normally depleted as an additional source of supply to meet demand.

The following forward curve of the NYMEX Nat Gas contract shows a similar pattern to the above HO curve.

Source: NYMEX Natural Gas Data on 6/6/2014

The front end of the curve moves into a mild contango starting with the Oct, 14 contract and into a backwardation during the heart of the winter heating season beginning with the Jan, 15 contract.  Both the HO and Nat Gas contracts move into contango and backwardation on a seasonal basis. Both commodities are over produced during the summer season while demand outstrips demand during the winter heating season. The degree of contango and backwardation are very fundamentally driven. If supply strongly outstrips demand the contango will get very wide and vice versa during periods of demand strongly outstripping supply – like during periods of much colder than normal winter weather (similar to the winter of 2013/14 in the US).

The WTI forward curve is less seasonal and primarily dependent on both US domestic and international crude oil supply and demand balances. The WTI forward curve based on 6/6/14 settlement prices is shown below.

Source: NYMEX WTI Data on 6/6/2014

This particular curve is in a backwardation throughout its entire forward period suggesting that demand is outstripping supply. Even though this is the forward curve for a US based crude oil that in early June of 2014 is oversupplied the crude oil market is internationally based. Events around the world insofar as supply and demand, impact WTI as well as the Brent marker crude oil. The world of oil in 2014 is still being impacted by various geopolitical events in several oil producing countries (i.e. Libya, Iran, and Iraq) that has resulted in a reduction in crude oil exports from these countries offsetting the surplus of crude oil that has formed into the US and thus the term structure in a backwardation.

Some of the key takeaways from the forward curves are as follows:

• The shape of the forward curve is primarily driven by fundamentals.
• The fundamentals or the relationship between supply and demand at any point in time will push the term structure into a contango or backwardation.
• When a market is in a backwardation demand is generally outstripping supply and thus prices in the front end of the market will generally be supported and have limited downside until the market moves back in balance.
• On the other end, when a market is in contango supply is outstripping demand and thus prices in the front end of the market will generally be sold into  and have a downside bias until the market moves back in balance.
• The fundamentals that drive the shape of the forward curve can be driven by seasonal conditions i.e. winter heating season or by other reasons that impact the supply and demand. Some of these reasons are:
  • Geopolitical risk to supply in producing countries.
  • Weather related impact to supply i.e. natural disasters like hurricanes.
  • Normal operating impact to supply like refinery and producing maintenance schedules.
  • Unscheduled downturns in the refining sector resulting in under producing various refined products.
  • Economic growth that results in a growth spurt for energy products.
  • Above or below normal weather related demand for heating fuels like HO and Nat Gas.

The above is an overview of the term structure of several of the key energy commodities traded on the NYMEX futures market.

If you have any questions send a message or contact me

Regards,
Peter Knight Advisor

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