For traders, investors and virtually anyone else trying to plan upstream operations in the midcontinent, the most important story for 2011 was the steep discount that crude prices held at Cushing to benchmarks in the U.S. Gulf Coast and the rest of the world. Millions of dollars are at stake for producers from North and West Texas, through the Midcontinent, to North Dakota and Canada. Those producers generally price their crude against a Midcontinent benchmark.
The price crunch for crude at Cushing stems from a fundamental logjam that will not disappear anytime soon. Additional oil production from Canada, the Midcontinent and the Rockies, has pushed more supply into Cushing. Insufficient pipeline capacity exists to pull crude directly to the refining hub on the U.S. Gulf coast. The price of Midcontinent crude has slipped relative to other markets because producers can't get oil to the Gulf coast and other markets.
For years, West Texas Intermediate (WTI) crude frequently held a modest premium to Brent crude—a North Sea crude with similar characteristics. Conventional wisdom held that this small premium was needed to draw shipments from the North Sea to the U.S. Gulf coast for shipment via pipeline into the Midwest. This explanation made sense as long as there were no transportation bottlenecks which impeded the physical flow of crude into the Midcontinent, where WTI is settled.
But the sharp decline in crude prices at Cushing, and one which has held for more than a year, shows that prices are affected by a diversity of factors and that the fundamentals have shifted. For 2011, the average discrepancy between crude in the U.S. Gulf Coast—as measured by Louisiana Light Sweet crude spot prices—and crude at spot prices at Cushing was $17.22 per barrel (bbl.) The steepest discrepancy was about $29.75 per bbl. in late September.
An analysis from Credit Suisse Group AG shows that the discount for WTI to Brent averaged $19.27 over the course of 2011. The widest spread occurred in October, when the spread opened to more than $25 per bbl. At this differential, Midcontinent producers have strong market incentives to sell oil into the Gulf coast market—if only adequate transportation to that market were possible. The midstream infrastructure has not kept pace with the growing production.
Andy Lipow, President of Lipow Oil Associates LLC, says the discrepancy in prices between crude and other benchmarks will narrow over time as midstream companies put additional pipeline infrastructure to the Gulf coast in place.
"It's going to narrow over the next couple of years, but it will trade like an accordion depending on when the logistics come in service," he says. Lipow and other analysts believe the discrepancy in price will hold as long as crude oil is shipped from the Midcontinent to the gulf refining centers.
Mickey Thompson, crude oil committee chairman at the Oklahoma Independent Petroleum Association, says the discount for crude at Cushing affects large and small producers alike. At the current discount levels, even small producers feel a loss of revenue.
"For anybody, even a little producer, you're talking about $120,000 per year, and it could have been double that just three months ago when the differential was twice what it is today," he says. In addition, the discount for sweet crude in the Midcontinent costs the Oklahoma state treasury "tens of millions of dollars" in foregone revenue.
Mike McDonald, a past chairman of the Oklahoma Independent Petroleum Association, says the issue was a huge concern for Midcontinent producers when the discount for Midcontinent crude was $20 or more below Gulf coast values. The discount for crude has fallen to around $10 per bbl. after the announcement of the reversal of Seaway Pipeline, but it "will not go away anytime soon." For every $10 per bbl. discount to Gulf coast crude values, Oklahoma producers collectively lose about $428 million per year, he says. The discount affects every Midcontinent producer and is the central topic of discussion in many boardrooms.
Thompson has broached the problem to the industry for three years and has discussed the problem with "anyone who would listen" since January of 2009, when the price differential widened to $8 per bbl. At the time, companies opposed the development of the Keystone XL pipeline, which they thought would exacerbate the discount. At the time, Thompson says independent producers were unsure if they could access the Keystone XL and, if they could, at what rates?
Many Midcontinent producers notice the discount that Midcontinent sweet crude has from Brent and other sweet crudes, but don't complain too loudly about it as long as they are receiving $80 to $90 per bbl.
"There is some apathy among producers, and I'm talking about my friends. There would be a sense of urgency if crude were $30 or $40 per bbl.," he admits.
Contango and backwardation
Meanwhile, producers are unsure when the market for sweet crude will return to its historical relationship with U.S. Gulf Coast values. "We don't have any study that would suggest what might happen, or when something might happen. It's market driven and the market flips from contango to backwardation. And, suddenly, there's not as much reason to have lots of oil in storage at Cushing," he says.
Market producers are accustomed to fluctuations in commodity prices, although some of the recent price patterns have made veterans of the industry scratch their heads. Many Oklahoma fields produce the best crude in the country near the largest hub in the U.S. "We used to get paid a premium for that. Now our sweet bbl. and our handy location are a disadvantage. How does that work? Does that sound like a free market?" he asks.
The unexpected movements in the market have caught a lot of small producers in the region at a disadvantage. "I don't know if the market is chasing the speculators or the speculators are chasing the market, but as producers, we are just caught on the horns of that free market dilemma," he says.
In addition to the discount for sweet crude in the Midcontinent, the region's producers are also facing a serious challenge from Canadian tar sands, which have displaced some of the production from the region.
"Our customers have responded to global conditions, presumably the availability of Canadian tar sands, by retooling their refineries," he says. "Long-term, the problem is not storage at Cushing. The real problem is who buys our crude oil," he says.
Production out of the Rockies and the Bakken is discounted even further, he says. Prices from that region are anywhere from $5 to $10 per bbl. below Cushing's prices. The Rockies have less refining capacity, thus forcing crude from the region through the nation's overloaded pipeline system.
Midcontinent refiners began converting their units to take on more sour crudes from Canada some 20 years ago as production from the Midcontinent started to wane and refiners were worried about a shortfall.
"In the U.S., at the time, production was declining," McDonald says. "They were concerned about the supply for their refineries. No one thought at the time about getting oil from shale."
As a result, Midcontinent refiners developed their plants to take larger quantities of sour crude from Canada, and Midcontinent producers found some of their production displaced. The Canadian tar sands crudes from Canada are anywhere from $5 per bbl. to $10 per bbl. less than Midcontinent crudes. "A lot of these refineries have changed their mix so that they can run more sour crude from Canada," McDonald says.
For years, the front month contract on the New York Mercantile Exchange (Nymex), which settled with WTI in Cushing, was the proxy for world oil prices and the main instrument used for hedging, forecasting and planning in the U.S. The success of the contract made WTI on the Nymex as the world's most active commodity exchange with a physical settlement. "WTI has been the favorite instrument through which long-term investors have gained exposure to the price of oil," according to Credit Suisse.
With Midcontinent crude trading at a steep discount to other benchmarks, some producers considered using a separate benchmark for crude, arguing it was not a good reflection of world oil markets.
But Lipow and other analysts believe it is an adequate benchmark for crude in the Midcontinent, even if it has a discount to the Gulf coast and other world benchmarks. A good benchmark must have sufficient volume, liquidity and transparency to draw enough people to trade off it, he says.
"You want to have a liquid contract with price discovery. You want price transparency where people can see the price and how it is determined. And you want something that can receive physical deliveries against and take physical deliveries from," he says.
The issues surrounding the transportation of crude out of Cushing appear to be temporary, as the midstream sector rushes to look for short- and long-term solutions, Lipow says. Short-term solutions include rail transport and barges that pull crude out of the Midcontinent. Longer term solutions include pipeline infrastructure and storage facilities to develop the pipeline network out of Cushing.
Further, Lipow points out that the other major benchmark, the Intercontinental Exchange's (ICE) Brent futures, has problems of its own. Brent's production is around 200,000 bbl. per day—and in some months as low as 150,000 bbl. per day. The majority of it is shipped on tankers.
A second crude benchmark closely tied to ICE's Brent futures is dated Brent. This is a contract for a delivery of one of four crudes (Brent, Forties, Oseberg and Ekofisk), sometimes traded in cargo volumes delivered between the coming 10 and 25 days. The contract is occasionally illiquid and therefore hard to assess with complete transparency, Lipow says. "They each have their pros and cons," he says of the different benchmarks.
For years, many market traders have discussed the possibility of establishing a futures contract with a physical settlement in the U.S. Gulf coast, a major refining center. The new contract, many believed, would be a better benchmark for crude because it was close to a refining center that used the product and would have a closer correlation to seaborne crude benchmarks like Brent.
Rather than use ICE's Brent or dated Brent, some Midcontinent traders have urged the establishment of a futures contract for WTI with a settlement in the U.S. Gulf coast. But Dr. Craig Pirrong, director of the Global Energy Management Institute at the Bauer College of Business, says the establishment of a new futures contract is easier says than done.
For one, the capacity for storage capacity in the U.S. Gulf coast is a fraction of that seen in Cushing. In addition, getting market participants to start using an illiquid contract is a difficult task.
"It doesn't take a lot of cash to start a new contract, but it's really hard to get people to use it," he says.
Dr. Pirrong also dismissed criticism that WTI at Cushing is an improper benchmark only because it trades at a discount to other benchmarks. The benchmark represents very well what it purports to represent—crude values in the midcontinent. It was never intended to be a marker for seaborne values, he says. In addition, the discount for crude in Cushing, he says, has its winners and losers.
"It's a problem for some and a boon for others," he says. Midcontinent refiners are the primary beneficiaries of the discounted crude because they can buy feedstock at much cheaper prices than they would if its movements tracked other benchmarks more closely, Dr. Pirrong says. The issue factored into ConocoPhillips' reluctantance to sell its interest in the Seaway Pipeline. Its 199,000 bbl. per day refinery in Ponca City, Oklahoma was a primary beneficiary of the discounted crude. "That refinery was a legal license to print money," he says.
A Hart Energy study shows that refiners with access to discounted Midcontinent crudes in 2011 saw some of the highest refining margins ever experienced in North America, above $37 per bbl. in some cases.
Lipow also disagreed with the other periodic complaint about the benchmark at Cushing, namely that its settlement location is not really a major consumption center. While true, Cushing is connected with more than 24 inbound and outbound crude oil pipelines that connect Cushing to other areas of the country. The complaints about Cushing have not stopped the market's use of the contract. Lipow also disagreed with criticism that WTI at Cushing has "lost touch" with the broader world market for oil.
"The changes in the relationships between Brent and WTI are the results of world supply and demand issues affecting the current limited pipeline logistics," he says.
In Europe, Brent is used as a benchmark for light sweet crude, which was affected by the absence of Libyan oil on world oil markets during the Libyan civil revolution. "Those factors affect the physical supply and demand of oil overseas," he says.
A few short-term solutions to the bottleneck have already been announced. In November 2011, Enbridge Inc. and Enterprise Products Partners announced plans to reverse the direction of crude moving on their co-owned Seaway pipeline. The proposed reversal is scheduled to initially transport up to 150,000 bbl. per day of crude from Cushing to the Gulf Coast, sometime before second-quarter 2012. Additionally, it will increase the capacity to 400,000 bbl. per day by 2013. The discount for crude at Cushing plunged to around $10 per bbl. as soon as the announcement was made.
But not all analysts agree that the immediate reversal of the Seaway Pipeline will eliminate the current discount of WTI to Brent. A recent report from the U.S. Energy Information Administration (EIA) states that the long-term growing output in crude from Canada and the Midcontinent will force traders to deal with an infrastructure bottleneck for years.
"With crude oil production increases from Canada, the Bakken and other shale formations in the coming years expected to continue, the market will still be dependent on rail as the marginal mode of transportation, meaning some discount will be required to account for the costs of moving inland U.S. crudes to the Gulf Coast," the EIA reported.
Ultimately, the discrepancy in crude prices in Cushing and elsewhere will be resolved as the midstream infrastructure catches up and crude can flow freely wherever demand for it is the strongest.
Dr. Pirrong says the reversal of the Seaway Pipeline by itself does not provide enough capacity to move all of the additional crude coming from Bakken and Canada, although it will alleviate some of the additional demand for capacity. As a result, the price discrepancy will (and has) narrowed as a result of the announced reversal and its additional capacity out of Cushing.
But a long-term solution will require additional capacity beyond the previously announced Seaway Pipeline and Dr. Pirrong says there are enough projects in the works to resolve the demand. "Over the next couple of years, the problem will sort itself out," he says.
The construction of the Keystone XL pipeline will help bring additional capacity to bear if it is completed in its entirety, Dr. Pirrong says. The last leg, which stretches from Cushing to the U.S. Gulf Coast must be constructed if it is to provide part of the solution. Without it, the discount for crude in Cushing may actually steepen as additional crude comes into Cushing without the capacity to move it further south, he says. "It's part of an ultimate solution," he says.
No easy answers
There are no easy, short-term solutions to the discount for sweet crude in the midcontinent. Ultimately, the country needs to develop its pipeline network so that crude can flow out of Cushing to the Gulf coast as easily as it flows into the hub, McDonald says. Reversal of the Seaway Pipeline is part of the solution.
"If we can get Keystone XL approved by the government, that would help," he says.
In the past, traders used at least two justifications for the steep discount for crude at Cushing. The first was that pipeline capacity leading to the Gulf coast was full, and that they were unable to move it efficiently. In some cases, producers used trucks and rail to move crude out of the region because pipelines were full and the premium for crude on the Gulf coast was as much as $25 per bbl. Anything which was left behind either went into storage or was consumed at a discount by Midcontinent refiners, he says.
In addition, traders say the market's steep contango for most of 2011 justified buying crude and pushing it into storage at Cushing. They could sell it later at a premium and lock in a profit. When Enbridge announced that it would reverse the Seaway Pipeline, the contango in the market disappeared abruptly and there was no longer an incentive to buy it for storage, he says.
As a result, traders ceased buying crude for storage, leaving the amount in tanks at historic lows for this time of year, he says. Since then, the amount of crude in storage has slipped. "Now we no longer have that justification (for the steep discount of midcontinent crude values)," McDonald says.
Many midstream companies have invested heavily in the region in an effort to pull more crude out of the Bakken and to transport it to Cushing and beyond. Enbridge Inc. announced it held a second open season earlier this year to give shippers an additional opportunity to subscribe for additional capacity within the Gulf Coast Access project. This pipeline will move crude from the Enbridge terminal in Flanagan Illinois to Cushing and then to the Gulf Coast.
The Gulf Coast Access project involves the construction of an additional line from Flanagan south to Cushing, Oklahoma, following Enbridge's existing Spearhead Pipeline right-of-way. The new line is expected to be in service by mid-2014 at an estimated cost of $1.9 billion. Based on the results of its first open season, Enbridge will construct a minimum 30-inch pipeline from Flanagan terminal, near Chicago, to Cushing that, fully powered, would have capacity of 600,000 bbl. per day of heavy crude.
Depending upon the results of the open season that began January 4, Enbridge may increase this new pipeline to a 36-inch line that would have capacity up to 800,000 bbl. per day. Capacity, and details around size and scope of the project, will be determined by shipper demand and the results of the open season. Because this new pipeline will be generally adjacent to the existing Enbridge Spearhead System, Enbridge can optimize its existing mainline system, routes, station sites and infrastructure.
The company held a second open season on this segment of its Gulf Coast Access project at the request of shippers. The January open season will offer another opportunity for shippers to subscribe for additional capacity, over and above capacity secured in the first open season. Enbridge secured sufficient capacity to proceed with the Gulf Coast Access project. The results of this second open season will determine whether it will upsize our original proposal.
In addition to the reversal of Seaway and its Gulf Coast Access project, Enbridge and its affiliates have also announced a series of investments to enhance transport of crude out of the Bakken.
Enbridge will invest $145 million to enhance the capability of its North Dakota crude oil system by expanding capacity into the Berthold terminal by 80,000 bbl. per day. The Berthold Rail Project includes the construction of a double loop unit-train facility, crude oil tankage and other terminal facilities adjacent to its existing facilities near Berthold North Dakota. The project will have the ability to stage three unit trains at Berthold at any given time. After an initial 10,000 bbl. per day Phase 1 start up in July 2012, the rest of the rail export capacity will be in service by 2013. Enbridge currently has the capacity to export 25,000 bbl. per day north to the international border and 210,000 bbl. per day into Clearbrook, Minnesota, from Berthold.
In addition, Enbridge will accommodate growing production from the Bakken and Three Forks formations in Montana, North Dakota and southeast Saskatchewan through the Bakken Expansion Program. The project is expected to add 145,000 bbl. per day capacity by early 2013. Of that, 25,000 bbl. per day is available now. Enbridge Energy Partners will spend an estimated $90 million as part of the Bakken Access Program to expand its gathering system and construct additional storage tanks and truck access facilities at multiple locations in North Dakota.
Meanwhile, as analysts and traders are discussing long-term solutions to the bottleneck in infrastructure, Midcontinent producers are trying to get creative about an interim solution.
Thompson called for a type of independent cooperative marketing effort to find new buyers for Midcontinent sweet crude. Traditionally, independent producers contract with a marketer who picks up the production and moves it to a terminal, paying a small discount to the benchmark at Cushing for their service. But, as local refiners and marketers buy additional supplies of Canadian crude, the region's producers are starting to think about alternative ways of doing business.
"We need to start thinking about selling our crude oil to whoever will buy it," Thompson says. "We may need to sell our crude oil offshore." But many Midcontinent producers are reluctant to break away and begin selling crude to an unknown entity. They are especially skittish of unknown buyers after the financial implosion of SemCrude Corp. cost many small producers millions in lost revenue. Since then, producers have a strong preference for established refiners and marketers whom they know personally and trust.
"My friends and colleagues look at me and say, 'You have to be kidding me. You want us to sign our crude oil to whom? Some co-op?'" he says. But Thompson counters that many wheat and cotton farmers have sold their products successfully through cooperatives for years. "It has helped keep small ranchers and farmers afloat," he says.
Yet, the widening discount has forced many midcontinent producers to think creatively about how to find alternative markets. When the discount for Midcontinent crude widened to more than $20 per bbl., some producers looked at moving crude from the Midcontinent via trucks and rail.
"We looked at that long and hard," he says. Trucking crude from Oklahoma City to the U.S. Gulf coast refining center costs between $11 and $12 per bbl., he says. Beyond the cost of trucking crude, Thompson says he saw a shortage of trucks and skilled drivers. Rail is less expensive, and some producers use this option to move their product. "Right now, trucking is not really viable," he says.
Thompson agrees that the reversal of the Seaway Pipeline could reduce the discount for Midcontinent crude, depending on the transportation rates approved by the Federal Energy Regulatory Commission (FERC), but stressed the reversal was not a panacea and might not benefit Midcontinent producers when it begins operations. Thompson and other Midcontinent producers worry that the FERC will allow the operator to establish market rates for the transportation of crude from the region, which would mean a significant increase in transportation rates.
If that happens, Thompson says the discount for Oklahoma crude may fall, but Midcontinent producers would not necessarily benefit from it. Most of the benefit would go to the pipeline companies if they are allowed to establish market rates.
"Our fear is that we won't capture any of the reduced differential that we thought we would reclaim when that pipeline goes into operation. The owners of the pipeline may decide that they want to capture that differential," he says. "If that happens, trucking and rail and barging could come back into play."
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