As an investor seeking to continuously develop my skillset, I find it beneficial to shadow a professional investor with a thought process I respect. And by shadow, I just mean follow his work online, perform my own work, and compare conclusions. That's exactly how I chose to write about Northern Tier Energy LP, a company Vitaliy Katsenelson wrote about in November. As an active reader of Seeking Alpha, I noticed several articles have been written about the company since November, a significant amount of coverage for a $2.4B company by market capitalization. I have not read these articles prior to my analysis to avoid clouding my thoughts about the company. Understanding there is ample coverage, I will keep the investment thesis focused on what I consider the key points.
Instead of simply jumping on board a ship with someone I respect, I felt compelled to investigate more about NTI's refining business, noted to be strategically located in the PADD II Midwest region. Being located in the Midwest enables the company to benefit from low costs of raw materials (i.e. WTI crude oil or more specifically WCS (Western Canadian Select) or North Dakota Light (NDL)) when compared to its competitors in the PADD III Gulf Coast region that primarily use Brent or Louisiana Light Sweet. Such a strategic advantage improves gross margin, or what the industry refers to as crack spread (light products such as gasoline and distillates - crude oil). As the company states in its 10-K, NTI's "operating performance has benefited from the widening of the price relationship between the traditional crude oil pricing benchmark, NYMEX WTI, and the international waterborne crude oil pricing benchmark, Brent. We purchase crude oil which is priced based off NYMEX WTI. Refined products prices are set by global markets and are typically priced off Brent." Management references the NYMEX WTI because they purchase crude oil based on that futures index. As recent as 2009, WTI has at times exceeded Brent. Since August of 2010, however, Brent has been consistently higher, sometimes as much as almost $30/bbl.
As reflected in the chart below, the futures prices indicate a continued premium price for Brent vs. WTI. As a side note, the shape of the futures price curve is said to be in backwardation and that subject is discussed in more detail here.
The short fundamental explanation for the spread is that the significant influx of oil from western Canada and notably, the Bakken Shale in North Dakota has created excess supply of crude oil stored and priced in Cushing, OK. There is not enough refining capacity in the Midwest to gobble up the excess supply, and combined with a constrained network of pipelines, it cannot be delivered to the Gulf Coast refineries without significant added cost (and danger) of moving product by rail. In researching the spread dynamics, a friend tipped me off to RBN Energy (user/password required but the articles are free). A couple of specific articles I found useful were Reunited? Stronger WTI Moves Closer to Brent and Strangers in the Night - WTI and Brent Come Close Enough to Touch. Since the spread is an important driver of value, it's important to understand the history of it and get a sense of the future direction of the spread. As the chart below illustrates, the gross margin per barrel of throughput closely tracks the Brent vs. WTI spread with a correlation of about 0.6 albeit for an admittedly small sample of data. In assessing the company, I asked do I believe the futures price spreads and do I believe the gross margin vs. spread relationship will hold.
The more I read about the Brent vs. WTI spread, the more angst I have about whether or not the spread will continue, at least in the magnitude it has over the past few years (in 2012, the spread traded at an average of $17.50/bbl). The reversal of the Seaway and Magellan Longhorn pipelines in June 2012 and April 2013, respectively, have alleviated some of the stockpile of crude at Cushing, pushing WTI higher and narrowing the spread. Furthermore, significant additional pipeline capacity from the Keystone XL pipeline and Seaway pipeline expansion in 2014 is expected to allow for additional volume to reach the Gulf Cost. That would seem to further improve the ability to move crude from Cushing to the Gulf Coast absorbing even more of the Cushing stockpile.
On the other hand, the degree to which the entire spread is eliminated, is subject to debate as the Bakken crude quality "may be too light to meet the needs of the Gulf Coast refiners" according to RBN Energy. Even if the crude oil pipeline network was perfectly efficient, the spread may still exist since Bakken and Brent crude are not identical products. Demand for crude types varies based on the refineries' feedstock processing capabilities and preference influenced by refined product prices. Not to get lost is the fact that a zero or negative spread doesn't translate to no or negative margin, it just eliminates or flips the Midwest refiners' competitive advantage vs. its PADD III competitors. I do expect the relationship between the margin and spread to continue because the change in the spread directly impacts the revenue and cost of goods sold for the company. In other words, the correlation is logical. What will be interesting to observe is how much Brent oil the Gulf Coast refineries will use as more WTI and LLS-benchmarked oil is available for the Gulf Coast refineries.
Finally, a subject that has recently received more attention is the lobbying effort of producers to gradually lift export bans initiated during the Nixon administration via EPCA (Energy Policy and Conservation Act of 1975). Such measures would alleviate the over-supply of U.S. oil and likely raise prices or increase refinery cost. Valero for example is an active participant in the discussion. I believe any alleviation of the export ban would be very gradual over the course of many years and would not be lifted entirely as the BIS would likely continue to review individual export licenses.
What has primarily been discussed so far is the cost side of the revenue and cost equation. As noted, the output of plant or refined products is benchmarked to Brent crude oil prices. Demand for refined products - largely gasoline (48% of production for the FY12) and diesel and jet fuel (32% of production for the FY12) but also kerosene, asphalt, propane, propylene, and sulfur - has historically exceeded supply which is why the U.S. has been an importer of foreign crude oil. In recent years, demand for gasoline in the U.S. has flattened out due to stable driving habits in combination with more fuel efficient automobiles. As this Time article points out, "the average VMT by LDV-vehicle miles traveled by light-duty vehicles, a.k.a. cars-has been mostly flat for the past five years, and thanks to continually improving fuel efficiency in new cars, it looks like we'll keep gassing up less down the road." I think it's a trend to watch but in the meantime, refined products produced in the PADD II region of the U.S. remains insufficient to satiate Midwest demand as reflected in the below chart. While the chart shows that gas demand has consistently exceeded supply in PADD II, the net receipts have decreased for five consecutive years because PADD II refineries become more capable of meeting demand for refined products. The data is old and I have asked for updated information I was unable to find on the eia.gov website.
The retail side of the business operates 166 convenience stores under the Super-America brand and Super America supports an additional 70 franchised stores. Revenue is generated from gasoline, diesel, merchandise such as prepared foods and beverages, royalty income for the franchised stores, car washes, and Super Mom (baked goods). The focus in this article has been on the refining side of the business since that is the business I believe will most impact future profits and it comprised about 85% of gross margin in 2012.
Additionally, NTI owns a 17% interest in a 300-mile 455Mbpd crude oil pipeline from the Enbridge pipeline hub in Clearbrook, MN to the Saint Paul Park refinery.
Since NTI has only one published 10-K (the company was formed on 6/23/10 and had an IPO close date of 7/31/12), it's difficult to gauge the business' growth over the past several years. The refinery has processed 80.2MBpd, 81.2Mbpd, and 83.9Mbpd for 2010, 2011, and 2012, respectively so growth in productive capacity has been minimal since 2010. It's not an incredibly high growth industry as a whole.
To provide a sense of scale, there were 134 oil refineries in the U.S. as of 1/1/12 according to the EIA as referenced in NTI's 10-K. The 14 smallest had a refining capacity of 14,000 bpd or less while the 10 largest had a refining capacity of 327,000-560,500 bpd. In 1982, total capacity in the U.S. was 16.1MM bpd and as of 2012, it was 16.7MM bpd. That's not a lot of growth - in fact it's a CAGR of about 0.1%. High capital costs, historical excess capacity, and environment regulations have prevented meaningful growth in capacity.
Yet NTI has plans for growth and has already implemented some of those plans with an increase to 92.5Mbbls per stream day vs. the FY12 84.5Mbbls. NTI has spent about $46MM, $31MM, and plans expenditures of $55-$60MM in 2011, 2012, and 2013, respectively. The 2011 and 2012 capital expenditures primarily related to equipment maintenance and replacement, safety enhancements, and implementation of a new information and accounting system. Of the 2013 planned capital expenditures, $29MM was expected to be spent for the 10% capacity expansion while improving distillate recovery by 2%-3%. Management also noted that "a component of our growth strategy is to selectively consider accretive acquisitions within the refining industry and retail market."
Based on what I think are conservative revenue growth and margin projections, in which I heavily discounted the roughly $4 comparative advantage per barrel crack spread reported in the FY12 10-K ($4.77 in a company 8/13 presentation), I think a low $30s per unit price is reasonable. In Vitaliy's article he notes "NTI's earnings will likely be volatile going forward, but we can accept this volatility considering that we are paying six times its worst case earnings." With a lower bound $3/unit earnings projection, that means Vitaliy bought NTI at about $18/unit. It would have been nice to buy at that price although I think a favorable risk/return trade-off remains with about an eight times worst case earnings which equates to $24/unit. Price patience is required at the current market price. In the meantime, I will observe the relationship between WTI and Brent and how future improvements in logistics and government-imposed regulations impacts those prices.
Keep in mind NTI is a variable-payout MLP (master limited partnership) and has different tax impacts to unit-holders than to C-corporation shareholders. Here is some additional information from Fidelity for reference.