Unlike the majority of the 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 car manufacturers and rising corn costs squeeze cereal manufacturers' profitability.
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 to calculate the 3-2-1 crack spread.
- West Texas Intermediate ((WTI)) crude oil stands at $89.51 per barrel; three barrels of crude oil would cost a refiner $268.53.
- Gasoline trades at $2.73 per gallon on the New York Mercantile Exchange. There are 42 gallons in a barrel, so gasoline is worth $114.66 per barrel and $229.32 for two barrels.
- Heating oil (the same basic product as diesel) trades for $3.04 per gallon, or $127.68 per barrel.
- To calculate profitability, we sum the value of the products produced ($229.32 + $127.68 = $357) and then subtract the cost of the crude oil used in the refining process ($357 - $268.53). This calculation yields $88.47 in profits. Dividing this figure by three yields a 3-2-1 crack spread of $29.49 per barrel.
Over the past two decades, the 3-2-1 crack spread averaged about $9 per barrel. In the current environment, well-positioned refiners are enjoying their best profit margins in some time.
The last time refiners enjoyed comparable levels of profitability occurred from the end of 2004 to the end of 2007. During this Golden Age of Refining, shares of Valero Energy Corp (NYSE: VLO) - the largest independent refiner in the US - generated a total return of 209 percent, handily outperforming the 119 percent gain posted by the S&P 500 Energy Index.
The elevated 3-2-1 crack spread has prompted some analysts to suggest that the refining industry has entered a second Golden Age. However, investors must understand the differences between the current environment and the 2004-07 bull market for refiners.
In the first Golden Age, a combination of rising demand for refined products and a shortage of US refining capacity drove up margins in North America. No new refineries have been built in the US since 1976, while operators closed some facilities because profit margins remained weak throughout much of the 1990s and early 2000s. This situation reversed as surging demand growth for refined products in China and other emerging markets outstripped the growth in global capacity. Expanding an existing refinery or building a new facility requires significant amounts of time and up-front investment; several years passed before the industry could roll out sufficient new capacity.
Rising demand isn't behind the latest up-cycle in the North American refining industry. Sluggish economic growth and the elevated price of petroleum products have conspired to weaken domestic consumption. US oil demand declined to less than 19 million barrels per day in 2011 from almost 21 million barrels per day in 2005.
Today, global refining capacity matches end-market demand reasonably well, though the industry endured a rough patch when demand plummeted during the last global economic crisis.
Widening differentials between inland oil prices in the US and global oil benchmarks have driven the refining industry's second Golden Age. In short, the most recent up-cycle isn't a global phenomenon but applies primarily to a handful of advantaged regions in the North American market.
The 3-2-1 crack spread assumes that a refiner purchases WTI crude oil as feedstock and sells gasoline and heating oil. As we explained in Mind the Differentials, rapid production growth in the Bakken Shale and other unconventional oil fields has overwhelmed takeaway capacity at the hub in Cushing, Okla., the delivery point for WTI.
Refiners with facilities in the Midwest can purchase WTI at favorable prices and sell their output at prices that reflect global supply and demand conditions. On the other hand, refineries on the West Coast or the Gulf Coast lack sufficient access to WTI, forcing them to run Brent or Light Louisiana Sweet crude oil-higher-priced, waterborne varietals that constrain profitability relative to their inland peers.
In 2011 more than 16.5 million barrels of refined products - equivalent to almost one-fifth of global demand - traded across international borders.
Because gasoline and distillates are globally traded commodities, the prices of these products usually track Brent crude oil, a key international benchmark.
That's great news for inland refiners in North American that can purchase WTI crude oil at a local discount and sell gasoline and diesel fuel at prices that reflect global supply and demand conditions.
Regional refining margins historically have moved in lockstep throughout the world. However, the profit margins enjoyed by downstream operators in North America have soared because of the widening price spread between inland crude oils such as WTI and Western Canada Select (WCS) and other international benchmarks.
With oil production from prolific US shale plays and Canada's oil sands likely to grow, we expect North American basis differentials to remain favorable for inland refiners for at least the next two to three years. These feedstock advantages have also started to filter down to the Gulf Coast refining complex as new pipeline capacity transports more WTI and WCS south from Cushing.
The first phase of Enbridge's (ENB) and Enterprise Product Partners LP's (NYSE: EPD) Seaway Pipeline reversal and expansion came onstream last May, adding 150,000 barrels per day of capacity to move oil from Cushing to Houston. The second stage of the project, due to start up before year-end, will add another 250,000 barrels per day of takeaway capacity, while the third phase would expand the pipeline by another 450,000 barrels of oil per day.
In addition, TransCanada Corp's (TSX: TRP, NYSE: TRP) Keystone Gulf Coast Pipeline is slated to come onstream in 2013 and would augment Cushing's takeaway capacity by 700,000 barrels of oil per day.
Nevertheless, these advantages haven't extended to every region in North America. For example, refinery margins on the West Coast, or Petroleum Administration for Defense District V (PADD V), have languished relative to facilities on the Gulf Coast or in the Midcontinent region.
One of the most popular gauges of refinery profitability in PADD V is the 5-3-2 crack spread, calculated by refining five barrels of Alaskan North Slope crude oil into three barrels of gasoline and two barrels of distillate. In this equation, diesel and gasoline prices reflect the cost of these products for delivery to Los Angeles harbor.
Although the 5-3-2 crack spread has spiked occasionally in the past few years, this measure of profitability has lagged the 3-2-1 crack spread primarily because Alaskan North Slope crude oil fetches Brent-like prices. California-based refineries also lack access to discounted crudes from Canada and the Midcontinent region because of insufficient pipeline capacity connecting these areas to the West Coast.
Regulatory challenges have also disadvantaged refiners that operate in the state. California's Assembly Bill 32 (AB32), which passed in 2006, requires the state to progressively institute caps on carbon dioxide emissions that will reduce these releases to 427 million metric tons per annum. Firms that emit less than their established cap levels can sell pollution credits to companies that fall short of their goals.
Valero Energy has been among the most outspoken critics of the wording and implementation of AB32. Consider the following exchange between CEO William Klesse and an analyst during a conference call to discuss the company's third-quarter results:
Analyst: In California you've been very consistent over the years with your views of the regulatory regime. When you make your strategic assessment on your positions out there, is it the compliance cost for the new standards in 2013 or 2015 that represents the greatest concern or is it something more broad? And either way, is there an order of magnitude that you can give us as it relates to cost structure that would be likely related to the new regulations in California?
William Klesse: It's an excellent question. Actually this AB32, so the cap and trade program that's starting now and the low carbon fuels that tend to restrict which types of crude you can run, these programs are all starting. So the basic issue on low profitability on the West Coast has actually been crude sourcing. So do people have an advantaged crude source? And second, we still have over 10% unemployment in California, and California is more than two-thirds of the PADD. So when you start to look at this, demand is down and there's too much refining capacity….when everybody is back and running, we all tend to run down to cash cost.
Klesse highlights two major concerns in California. First, AB32 and similar regulations restrict refiners from processing certain crude oils that result in higher levels of carbon dioxide emissions. By limiting the slate of feedstock, these laws limit refiners' ability to take advantage of basis differentials and the lower cost of heavy crude oils.
The second headwind isn't necessarily unique to the West Coast: a weak economy and falling demand. However, Kleese's comments indicate that the supply-demand balance for refiners in PADD V is more unfavorable than in other regions. When refining outages occur, margins spike. But when California's refineries run at full capacity, the resulting oversupply depresses profit margins to the point that they barely cover cash costs.
Accordingly, Valero Energy plans to focus capital spending outside PADD V and upgrade its Midcontinent and Gulf Coast plants to enable them to process a wider variety of crude oils. These enhancements will give Valero Energy's facilities the flexibility to select the cheapest feedstock.
North American refiners that can take advantage of discounted crude oils to earn higher margins will outperform in coming years. The best refiners share two basic characteristics: Operations in regions that enjoy ready access to discounted crude oils and complex facilities that can process WCS and other heavy-sour grades.
Shares of well-positioned North American refiners such as Valero Energy and Marathon Petroleum Corp (NYSE: MPC) have rallied sharply in recent months. Neither stock looks expensive on a forward-earnings basis, but these names are likely due for a short-term pullback after such a big run-up.
A handful of developments could hasten this buying opportunity.
The completion of the second phase of the Seaway pipeline expansion will alleviate some of the supply glut at Cushing, providing a bit of support to the price of WTI. Meanwhile, planned and unplanned production outages in the North Sea have boosted the price of Brent crude oil in recent months; the gradual return of these supplies could exert downward pressure on this oil benchmark in the near term.
Moreover, negotiations to avoid the impending barrage of automatic federal tax hikes and spending cuts - the so-called fiscal cliff - will also roil the stock market in coming weeks. Investors should regard any pullback in the stock price of Valero Energy Corp or Marathon Petroleum Corp between now and year-end as a buying opportunity. We will track both stocks in our Coverage Universe.
Not surprisingly, the boom in refining margins has also resulted in the initial public offerings (IPO) of several master limited partnerships seeking to take advantage of the sector's bullish outlook and investors' insatiable demand for securities that offer above-average yields.
Alon USA Partners LP (NYSE: ALDW) debuted on the New York Stock Exchange on Nov. 20, 2012. The MLP had planned an IPO of 16 million units at a price of $19 to $21 each, but ultimately downsized the issue to 10 million units at a price of $16 each, likely because of a lack of demand. Nevertheless, the stock has rallied to almost $24 per unit - well above the high end of the MLP's original price range.
This downstream operator's primary asset is a single refinery in western Texas that boasts a nameplate capacity of 70,000 barrels per day and a Nelson Complexity Index rating of 10.2, indicating that the facility can handle a broad slate of heavy-sour crude oils.
In 2011 the company took full advantage of these capabilities. More than 80 percent of the feedstock Alon USA Partners processed was West Texas Sour ((WTS)) crude oil, a light crude oil that's high in sulfur content and currently trades at less than $72 per barrel-a significant discount to WTI and an almost $40 discount to Brent. The official delivery point for WTS, Midland, Texas, is only a few miles down the road from Big Spring refinery.
Oil produced in West Texas historically has found its way to Cushing, but oversupply at that hub makes the WTI delivery point a less-than-ideal destination. Moreover, the Permian Basin in West Texas has experienced a boom in drilling and oil production, as producers use horizontal drilling and hydraulic fracturing to exploit new reserves. There isn't enough takeaway capacity in the area to handle this growing output, oversupplying the local market and depressing prices even further.
Although these constraints pose a challenge for producers in this market, the Big Spring refinery should enjoy below-average feedstock costs for the foreseeable future. New pipeline capacity is on the way, but output continues to rise unabated; this bottleneck will take some time to resolve.
Meanwhile, in the first nine months of 2012, Big Spring earned a profit margin of about $22.88 per barrel of crude oil processed and ran at a capacity utilization rate of 97.3 percent. By comparison, the facility operated at a utilization rate of 90.8 percent and generated a profit margin of $20.89 per barrel in 2011. The year prior to this, profitability was a mere $7.64 per barrel, and the utilization rate came in at 68.2 percent.
This wide variation in profit margins per barrel and utilization rates illustrates the inherent cyclicality of the refining business.
These statistics also reflect arguably the most important point about Alon USA Partners: This nontraditional MLP doesn't aim to pay a minimum quarterly distribution and gradually boost these disbursements over time. Alon USA Partners' prospectus makes this clear: The MLP will disburse 100 percent of available cash each quarter to unitholders and will hold little cash in reserve beyond requirements for basic maintenance. The partnership agreement also lacks the subordinated-unit structure that many MLPs use to protect the quarterly distribution from temporary shortfalls in cash flow.
In short, investors should expect the payout to vary with trends in refining margins.
Alon USA Partners could offer an impressive distribution yield in a strong market for refiners. In the prospectus, the MLP estimates its distributions for the year ended Sept. 30, 2013, at $5.20 per common unit. At the MLP's offering price of $16 per unit, this payout equates to a yield of 32.5 percent. Based on the current quote and assuming the MLP delivers on this forecast, the units now yield 21.7 percent.
However, investors shouldn't put too much stock in this forward estimate. Most partnerships lowball their forecast quarterly distributions in order to surprise to the upside. Alon US Partners, on the other hand, has assumed that the Big Spring refinery will run at close to full capacity and that the favorable price differentials for WTS feedstock will continue in 2013. Given the volatility of commodity prices and refining margins, these factors can change quickly.
Investors should also consider the potential downside during periods when refining margins are less sanguine. In 2010 the MLP generated earnings before interest, taxation, depreciation and amortization of $31.574 million-enough to support an annual distribution of about $0.42 per unit.
In terms of future upside potential, the MLP could also benefit from drop-down transactions from its sponsor, Alon USA Energy (NYSE: ALJ), which owns other downstream assets that would be suitable in this structure. With an 84 percent equity stake in the MLP and ownership of its general partner, the parent has ample incentive to pursue strategies that enable Alon USA Partners to grow its distributable cash flow. At the same time, the general partner's take doesn't include incentive distribution rights, a feature that frees up more cash for distribution to investors.
Alon USA Partners represents a solid play on strong refining margins, but investors should regard the stock as a short-term trading vehicle, not a long-term investment like many of our favorite MLPs. We rate Alon USA Partners a buy under $22 per unit for investors who understand the risks associated with this nontraditional MLP.