In "Mind the Differentials," we explained how surging oil production from unconventional fields such as the Bakken Shale in North Dakota and insufficient southbound pipeline capacity led to an oversupply of crude at the hub in Cushing, Okla., and other inland delivery points.
These localized gluts widened differentials between crude oil delivered to inland hubs and coastal varietals such as Louisiana Light Sweet (LLS) crude oil. In fact, rising U.S. oil production kept WTI, Bakken and other inland U.S. crude oils trading at a discount of $10.00 to $30.00 per barrel from the beginning of 2011 to early 2013.
The price of West Texas Intermediate (WTI) crude oil has climbed by about 15 percent in 2013, peaking at $107.23 per barrel on July 23. With the price of Brent crude oil treading water or down slightly this year, the recent rally in WTI has narrowed the price differentials between the U.S. benchmark and international oil prices dramatically. And in late July, the intraday price of WTI overtook Brent crude oil for the first time in more than three years.
We've called for the WTI-Brent spread to come in since late 2012, but the rapidity with which this narrowing has occurred and the outright disappearance of this price differential took U.S. by surprise.
The proximate cause for the rally in WTI prices relative to Brent, LLS and other seaborne crudes is the rapid decline in crude-oil inventories at Cushing, the official delivery point for WTI.
Although oil stockpiles at Cushing remain elevated by most historical measures, an above-average drawdown has reduced inventories below levels that prevailed a year ago.
The start-up of a number of pipelines that transport crude oil from Cushing and other inland hubs to the refinery complex on the Gulf Coast has helped to alleviate the Midcontinent bottleneck and close the spread between WTI and oil benchmarks that reflect global supply and demand conditions.
Source: Company Reports, Energy & Income Advisor
Two major pipeline projects will move oil volumes from Cushing to the Houston area: The reversal and expansion of Enbridge (ENB) and Enterprise Products Partners LP's (EPD) Seaway pipeline and the southern leg of TransCanada Corp.'s (TRP) Keystone XL pipeline, which, unlike the controversial cross-border extension between the U.S. and Canada, is slated to come onstream by year-end. Although the second phase of Seaway pipeline went into service at the beginning of this year, a bottleneck of storage and takeaway capacity in the Houston area meant that it took months for the pipeline to fill up.
The other pipelines in our table divert oil volumes that formerly flowed to Cushing. For example, Enbridge Energy Partners LP (EEP) and Enbridge Income Fund's (OTC:EBGUF) Bakken pipeline project transports crude oil from North Dakota to Canada, where these hydrocarbons can be refined or transmitted to other pipelines for shipment to the U.S. Midwest.
Royal Dutch Shell's (NYSE:RDS.A) (NYSE:RDS.B) Houma-to-Houston (Ho-Ho) pipeline will help to move crude-oil volumes from Houston to Louisiana's coastal refineries-an important release valve for the light-sweet crude oil produced in the Bakken Shale and Eagle Ford Shale. Whereas refineries in the Houston area operate at peak efficiency when they can run heavier feedstock, facilities on Louisiana's Gulf Coast are better equipped to process a lighter slate of crude oil.
With much of this pipeline capacity either already online or expected to commence operations by early 2014, Cushing's oil glut should continue to drain, putting a floor under WTI and ensuring that the spread between this U.S. benchmark and Brent crude oil remains relatively narrow.
In addition to the new pipeline capacity coming onstream in 2013 and 2014, producers in the Bakken Shale and other prolific plays that lack sufficient takeaway capacity have expanded their use of rail to transport crude oil to markets that offer the best price realizations.
The total number of petroleum carloads handled by U.S. railroads has jumped to between 13,000 and 14,000 carloads per week in 2013 from 5,000 to 6,000 per week in late 2010 and early 2011. Orders of tank cars have surged over the past year, as producers in the U.S. and Canada seek to boost their transportation flexibility using rail. (See A Moving Trend: Orders of Tank Cars Surge to Support U.S. Oil Boom.)
Source: Bloomberg, Association of American Railroads
With new pipeline capacity still lagging production growth, expect the number of railcar loads of crude oil to continue to increase over the next few years.
The early July restart of BP's (BP) refinery in Whiting, Ind., has also boosted the price of WTI. BP is building coking and hydrotreating units on the site that will allow the facility to increase the proportion of heavy-sour crude oil to 80 percent of its feedstock slate. This expansion and site upgrade will enable the facility to maximize profitability by running greater volumes of Western Canada Select (WCS) crude oil, a heavy-sour varietal that currently trades at about $84.00 per barrel-a discount of more than $20.00 per barrel to WTI. But until these upgrades come onstream, the Whiting refinery will run primarily light-sweet crude oil from Cushing.
Decline in Differentials is Temporary
The price differential between WTI and Brent crude oil should widen in the second half of 2013 but remain below the spreads that became the norm in recent years. In the short term, look for WTI to trade at a discount of $5.00 to $7.00 per barrel relative to Brent.
We expect the growing pains and regional price volatility associated with the shale oil and gas revolution to continue into 2014, as U.S. midstream and downstream capacity catches up with rising domestic oil production.
In the previous issue of Energy & Income Advisor, we explained why growing U.S. natural-gas output and ample spare productive capacity would keep a lid on the domestic price of this commodity over the next three to five years. Until the U.S. adds the capacity to export large volumes of liquefied natural gas, producers have no way to arbitrage the spread between cheap U.S. natural gas and higher prices for this commodity in European and Asian markets.
That's not the case with oil. Since the 1970s, the U.S. government has banned the export of oil, except in instances where companies obtain special licenses from the Dept of Commerce. On the other hand, licenses to export to neighboring Canada have the "presumption of approval"; however, the U.S. exports little crude oil to its neighbor to the north or elsewhere. In the first half of this year, for example, U.S. shipments of crude oil to international markets averaged 50,000 barrels per day-a fraction of the roughly 7.5 million barrels per day that the country produces.
Although the U.S. doesn't transport significant volumes of crude oil beyond its borders, the nation is the world's largest exporter of refined products such as diesel, jet fuel and gasoline. For this reason, domestic prices of liquid fuels tend to track global supply and demand conditions.
Source: Energy Information Administration
U.S. exports of diesel have accelerated in recent years and now represent about one-third of the refined products that the country sells in international markets.
Midcontinent refiners reaped the rewards over the past several years, purchasing discounted inland crude oils such as WTI and selling their output at elevated prices that tend to track Brent. (See Refiners: Profiting from America's Oil Boom.)
Rising U.S. production from the Bakken Shale and other unconventional plays has also displaced seaborne imports of light-sweet crude oil, with U.S. refiners preferring landlocked domestic varietals that trade at a discount and offer superior profit margins.
Source: Energy Information Administration, Energy & Income Advisor
Light-sweet crude oil has declined to between 10 percent and 12 percent of total U.S. imports (less than 1 million barrels per day) from between 20 and 30 percent (2.7 million barrels per day) as recently as summer 2007. In contrast, imports of heavy oil from Mexico, Venezuela and other countries have remained relatively resilient.
More important, as takeaway capacity via rail and pipelines expands, much of the nation's growing output of light-sweet crude oil will find its way to the Gulf Coast. Independent refiner Valero Energy Corp. (VLO) expects U.S. imports of light and intermediate crude oils into the Gulf Coast to shrink to almost zero by the end of 2013. In a presentation at the UBS Global Oil & Gas Conference, CEO Bill Klesse noted that these volumes had already declined to about 100,000 barrels per day in a normal month.
Source: Valero Energy Corp.
Once the refinery complex on the U.S. Gulf Coast receives its fill of light-sweet crude oil and can't accommodate additional volumes, the question becomes where excess barrels will flow. In the most likely scenario, regional price differentials emerge that primarily reflect transportation costs.
Source: Valero Energy Corp.
For example, Valero Energy estimates that the cost of delivering crude oil from Cushing to Houston via pipeline at about $4.00 per barrel, suggesting that these volumes would trade at a similar discount to light-sweet oil arriving in the Gulf Coast. A similar discount would apply to oil shipped from the hub in Midland, Texas, to Houston.
Other likely changes to U.S. crude-oil flows include an uptick in volumes from the Bakken Shale that are destined for refineries in California. As we detailed in the March 3, 2013, installment of Energy Investing Weekly, Profiting from California's New Oil Rush, the Golden State has limited capacity to import domestic crude or refined products via pipeline and traditionally has depended on seaborne imports. This situation explains why oil prices on the West Coast tend to be higher than in the Midwest or U.S. Gulf Coast.
Valero Energy estimates that it costs $9.00 per barrel to move crude oil via rail to the coast in Washington State where it can be barged south to California's coastal refineries for another $4.00 to $5.00 per barrel. [Targa Resources Partners LP (NGLS) is involved in one of these schemes.] Crude-oil volumes could also travel from Canada to California by rail at a cost of $13.00 to $16.00 per barrel.
Based on these estimates, crude oil produced in these regions would need to trade at an appropriate discount to be cost competitive. Meanwhile, oil prices on the East Coast should fetch a premium of $5.00 to $6.00 per barrel relative to the Gulf Coast-that's roughly the cost of barging oil between these two regions.
The Jones Act, which stipulates that oil transported between U.S. ports must be carried on U.S.-flagged vessels that are crewed primarily by Americans, could help to stimulate interest in seaborne exports of light-sweet volumes from the Gulf to eastern Canada; shipping these cargoes to our neighbor to the north entails about half the expense of barging them to the U.S. East Coast.
Bottom line: Although pipeline start-ups, increased demand from BP's refinery in Indiana and other short-term factors have reduced the WTI-Brent discount, we expect regional price differentials to open up once again in 2014.
In this scenario, WTI should trade at a discount of $5.00 to $10.00 per barrel to Brent crude oil over the long term, while production from the Bakken Shale could fetch up to $15.00 per barrel less than this international benchmark. Light Louisiana Sweet crude oil delivered to St. James, La., should also begin to trade at a slight discount to Brent as the Gulf Coast becomes saturated with light-sweet crude oil. However, with the exception of short-term supply disruptions, the extreme WTI-Brent spreads that prevailed in 2011 and 2012 are unlikely to reoccur.
Unlike the majority of participants in the energy sector, refiners don't benefit from rising oil prices. Refining is a manufacturing process that converts crude oil into usable products such as diesel, jet fuel and gasoline. Higher oil prices erode refiners' margins in the same way that rising steel costs are bad news for carmakers and rising corn costs squeeze cereal manufacturers' profitability.
The biggest beneficiaries of the wide crude oil price spreads over the past two years have been U.S. refiners with access to inexpensive crude oil from the Midcontinent.
You can gauge the refining industry's profitability by tracking the 3-2-1 crack spread, a metric that approximates the margin earned by refining three barrels of crude oil into two barrels of gasoline and one barrel of distillate (heating oil or diesel). Here's how you calculate the 3-2-1 crack spread:
- WTI crude oil stands at $104.70 per barrel; three barrels of crude oil would cost a refiner $314.10.
- Gasoline trades at $3.05 per gallon on the New York Mercantile Exchange. There are 42 gallons in a barrel, so gasoline is worth $128.10 per barrel and $256.20 for two barrels.
- Heating oil (the same basic product as diesel) trades for $3.01 per gallon, or $126.42 per barrel.
- To calculate profitability, we sum the value of the products produced ($256.20 + $126.42 = $382.62) and then subtract the cost of the crude oil used in the refining process ($382.62 - $314.10). This calculation yields $68.52 in profits. Divide this figure by three and you get a 3-2-1 crack spread of $22.84 per barrel.
The 3-2-1 crack spread has declined markedly since the beginning of 2012 because the prices of refined products, which tend to track Brent crude oil, haven't kept up with the rally in WTI.
Although the crack spread remains healthy relative to historical norms, the recent pullback has hurt U.S. refiners' profits and weighed on stock prices in the group. For example, shares of Valero Energy - the largest independent refiner in the U.S. - have tumbled by about 13 percent since the end of February. By comparison, the S&P 500 Energy Index gained about 7.6 percent over the same period.
This recent weakness has prompted some pundits to highlight shares of U.S. independent refiners as an attractive value play. We disagree with this strategy. It's too early to jump into this group because the market hasn't sufficiently dialed back earnings expectations to reflect the decline in oil-price differentials. If the WTI-Brent spread follows our forecast and remains tight through year-end, earnings estimates for the refiners will go even lower.
Meanwhile, U.S. refiners face another formidable challenge: the soaring cost of Renewable Identification Numbers (RIN), tracking certificates that ensure compliance with the ethanol-blending mandates in the Energy Independence and Security Act of 2007.
As we explained in the March 28, 2013, issue of Energy Investing Weekly, Food for Fuel, these requirements are no longer realistic and would require refiners to blend ethanol into gasoline at concentrations above 10 percent. Instead, many refiners are buying RINs on the secondary market to ensure compliance, propelling the price of these credits to a high of $1.43 per gallon from $0.07 per gallon at the beginning of 2013.
With ethanol-blending mandates set for another steep increase in 2014, RIN prices could climb even higher in 2014. In a conference call to discuss second-quarter results, Valero Energy's management team indicated that the company spent $128 million on RINs in the quarter-more than double its outlay in the three months ended June 30, 2012. The firm also hiked its estimate for the full-year RIN-related expenses to between $600 and $800 million. During the question and answer session following the call, several analysts peppered Valero with questions about the cost of RINs:
Analyst: I'm sure there will probably be a long list of these, but I wanted to start with RINs and one of the struggles I'm going through is are blenders passing through the cost of RINs into the retail prices? Does it vary by region? What are the major considerations with regard to whether or not these RINs costs are getting passed through to the retail level?
COO Joseph W. Gorder: Jeff, this is Joe. That's a great question. We are trying to figure the same thing out ourselves. I would tell you we look at it on a regular basis and it's very difficult to quantify whether or not we are seeing the effect of the RINs in the cracks. We think we might be, but we are not 100 percent sure.
I do know that if you look at our customers, there are some out there that are able to capture this and there are some that aren't and everybody is interested in somehow capturing this and the real question for U.S. going forward is how much of this actually gets passed through into the marketplace and how much doesn't?
Because it's a legitimate expense for us, as we've mentioned $600 million to $800 million, it's a big hit and we'd like to be recapturing it. We're just not sure whether we are or not.
Simply put, Valero Energy and other refiners have been able to pass along some of their RIN-related expenses to consumers, but the company is still eating a portion of the costs.
Over the past few months we've downgraded several of the refiners in our coverage universe to hold or sell. We are expecting crude-oil differentials to widen in 2014, a development that could catalyze a rotation back into the refining industry; however, you'll need to be more selective when investing in the space this time around.
Disclosure: I am long EPD, NGLS. I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it (other than from Seeking Alpha). I have no business relationship with any company whose stock is mentioned in this article.