Today’s low oil-price environment certainly has constituted a sizable headwind for much of the energy value chain, especially for E&P companies. For much of the downstream sector, however, times are relatively good. Despite this polarity, both are still searching for balance.

Balancing the two ends of the energy value chain falls to midstream operators, which are adding new pipe, terminals and storage in response to new sources—and types—of crude supply.

In most cases, refiners keep a close eye on future global crude production trends. These trends in crude production, in turn, greatly impact future investment decisions to ensure that availability of compatible grades will match the design basis for new refineries. Historically, this has worked out well for refiners, but not always, according to John Mayes, director of special studies for Dallas-based consultancy Turner, Mason & Co.

Throughout the 1990s and into the first half of the last decade, the growth of heavy Canadian production was the dominant factor driving new refining projects in North America, especially on the U.S. Gulf Coast. As a result, these projects often included units to process heavy, high-sulfur feedstocks, such as delayed cokers. The largest of these were completed in the last 10 years.

Causing crude’s collapse

By 2009 and 2010, however, the shale oil, or light tight oil (LTO), boom gave refiners both opportunities and operating challenges, even as they were starting up facilities to process those incremental heavy grades. By all accounts, this surge in U.S. LTO helped create the mid-2014 oil price collapse.

As a result, many refiners situated in the Midcontinent and U.S. Gulf Coast have reversed this trend and are now increasing capacity to process very light crude grades, according to Mayes.

“All of a sudden there has been an abrupt U-turn, and the focus is completely away from heavy and on the processing of the super-light and condensate grades. That’s likely to be the dominant feature for at least the near future,” Mayes told Midstream Business.

“[Refiners] recognize they weren’t real attentive on the shale grades and missed some opportunities there, so they don’t want to repeat that scenario for the next cycle, whenever it may be,” he said.

According to Turner Mason, global crude production is forecast to grow by 10.2 million barrels per day (MMbbl/d) from 2015 to 2025. More than 75% of this increase is expected to come from the Middle East and North America, with smaller contributions coming from South America, the Former Soviet Union and Africa, while output is projected to decrease in Europe and Asia-Pacific.

Additionally, oil output during the next decade is forecast to become increasingly oriented toward the very light and the very heavy. In 2015, the largest concentration of production was in the light and medium grades (63% of the total). Output of condensates, super-light and heavy comprised the remaining 37%.

Within the 10.2 MMbbl/d of incremental crude production forecast by 2025, light and medium grades are expected to comprise less than 45% of the total, while very light and very heavy grades will represent more than 55%, according to Mayes. This decline of medium-gravity crudes is so significant that in the incremental production, output of both super-light and heavy grades are anticipated to exceed medium output, Mayes noted, which will present refiners with new challenges in the coming decade.

Watching production

“Refiners need to be aware of the crude production side of the business to anticipate these shifts in order to maximize opportunities as early as possible,” Mayes said.

During the next six years, however, Mayes noted that global refineries will be adding capacity to process medium crude far in excess of expected production increases. Conversely, refining capacity increases for light and heavy crudes are expected to lag during Turner Mason’s forecast crude production increases.

It’s still unclear as to what the absolute price of oil would be to stimulate drilling activity. When activity resumes, Mayes noted that refiners need to be ready to adapt to the light/heavy crude grade wave.

“If [oil drilling] recovers quickly, then [refiners] need to be more adapted to the light crudes vs. the more expected kind of increases that are going to come out of Canada,” he said.

So how will the refining industry balance light and heavy crude grades going forward? It appears that the anticipated light/heavy oil imbalance will create a multitude of challenges and opportunities for North American refiners, especially those that have high Nelson Complexity Index (NCI) scores like Valero Energy Corp., CVR Energy Inc. and HollyFrontier Corp. The NCI is a measure of a refinery’s ability to convert heavy, high-sulfur crudes into petroleum products—in addition to simple distillation.

In a discussion paper during a session at the American Fuel & Petrochemical Manufacturers Annual Meeting last year in San Francisco, Blake Eskew, vice president, downstream consulting for IHS, highlighted how LTO production growth will strain refinery balances on the light end of the barrel, with the biggest strain on the heavy end coming from a growth in Canadian oil sands production.

“Even if PADD 3 [Gulf Coast] coker inputs were to increase to 90% utilization and then creep upward at 1% annually, less than half of the additional residue could be accommodated. Displacement of offshore medium and heavy crude supplies, and potentially coker capacity additions, will need to continue for the increase in oil sand volumes to be processed,” Eskew observed in the paper.

With an impending crude grade imbalance, refiners are currently weighing technology investment decisions for reconfiguring their assets to properly handle increased volumes of light/heavy grades that are poised to soon flood the market.

‘Opportunity crudes’

Afolabi Ogunnaike, senior analyst, refining and oil markets for Wood Mackenzie, observed that the majority of U.S. refining investments in the next three years will come within basic crude distillation units (CDUs). This runs in contrast to the focus on desulfurization and hydrocracking investments to process heavy crudes between 2010 and 2014.

In fact, he predicted some project cancellations are possible within cracking investments as the industry shifts its focus to CDU investments to process new LTO and condensate supplies. As a result, an emphasis on CDUs for handling “opportunity crudes,” he said, is the best approach forward for refiners.

Mayes agreed with Ogunnaike’s assessment.

“[CDUs] are where you get the most bang for your buck,” he said. “The hydrocracking was really a reflection of the emphasis on diesel prices.”

Two years ago the majority of U.S. refinery investments were focused on increasing capacity to process light crude or condensate. Projects in the 600,000-bbl/d range were proposed. Some of these projects have already started up, such as Valero Energy Corp.’s topping units at its Houston and Corpus Christi, Texas, refineries as well as Kinder Morgan’s condensate splitters in the Houston area.

However, there have been significant changes since some of these projects were first proposed. First, U.S. oil supply is now declining. Second, U.S. crude differentials have narrowed. Finally, the U.S. oil export policy has changed.

“Some of the proposed condensate splitter projects may not go forward, particularly the facilities not associated with refineries and without long-term offtake agreements,” Ogunnaike told Midstream Business.

Pipelines’ role

Wood Mackenzie recently calculated that U.S. refiners earned about $32 billion from processing discounted U.S. West Texas Intermediate (WTI) and Western Canadian Select (WCS) crude oil in 2013. To be clear, Ogunnaike emphasized that the figure is not a profit; rather, it denotes additional value the refineries earned because WTI and WCS crudes were heavily discounted compared to their international benchmarks.

But as the midstream improved North America’s pipeline infrastructure, the firm has seen discounts narrow.

During much of 2016, however, WTI only averaged about 50 cents/bbl less than Brent, while WCS averaged $4/bbl less than heavy Maya crudes. World crude prices rose as 2016 ended following announcements by OPEC and Russia that they would curtail crude production. Oil prices jumped accordingly, and the WTI-Brent price spread increased by more than 100%. This year, Ogunnaike forecasts U.S. refiners will derive about a $6 billion value from processing discounted crude.

“We expect U.S. refineries will continue to be among the top-performing refineries in the world. The narrowing differentials are eroding some of the additional value they were able to capture, but they still outperform refineries in other regions,” Ogunnaike said.

While U.S. refiners are, by nature, opportunistic buyers of crude oil—living and dying on margin—they must adapt to a new world of growing light and heavy North American crudes. However, finding the right type of crude at the right price can sometimes present new sets of challenges and opportunities.

Rail vs. imports

The sudden oil supply shock from the shale gale took midstream operators by surprise. In the Midwest, where a substantial portion of the growth was occurring, there was not sufficient infrastructure to move this growing excess supply out of the region. Pipeline companies, not sure initially how much production would come on and unsure as to how long production would last, were slow to respond.

Consequently, oil producers—particularly in the Bakken Shale—were offering large discounts to encourage midstream intermediaries to move oil to refineries on the U.S. East Coast. Railroads and rights-of-way were in place, and moving oil by rail, while more expensive than transporting by pipeline, was the only short-term option.

Crude-by-rail (CBR) shipments surged between 2012 and 2014, peaking at 928,000 bbl/d in October 2014, according to U.S. Energy Information Administration (EIA) data. Most of the rail shipments during that span occurred from the Bakken to East Coast refineries.

However, this trend changed dramatically in late 2014 and became painfully obvious in 2015 when the large overhang in global oil supplies caused a dramatic collapse in price and a narrowing in the relative WTI and Brent price spreads, rendering CBR from the Bakken crude to the Northeast uneconomic. Doing so would fetch between $10/bbl to $11/bbl of added transportation costs on top of the absolute value of the input.

Out of Africa

As a result, interest in purchasing Atlantic Basin crudes, such as those from West Africa (WAF) or the North Sea, increased—particularly by East Coast refiners such as PBF Energy Inc.; Monroe Energy LLC, an affiliate of Delta Air Lines Inc.; and Philadelphia Energy Solutions (PES). This is directly linked to the narrowing WTI and global Brent benchmark price spread which, when viewed on a delivered and quality-adjusted basis, made sourcing WAF crudes more economically attractive.

PBF Energy, which owns refineries in Paulsboro, N.J., and Delaware City, Del., reported a 57% decline in 2015 in crude unloaded at its two Delaware City rail terminals, one designed for LTO and the other to handle heavy Canadian crude. It received about 53,400 bbl/d in 2015 compared to 125,600 bbl/d in 2014, according to the company’s subsidiary, PBF Logistics LP.

U.S. imports of Nigerian crude at one point jumped to 559,000 bbl/d in early 2016, setting a weekly record dating back to mid-2013, according to the EIA. Nigeria was the fourth-largest supplier of foreign crude to the U.S. at the time, displacing Mexico and also competing with Iraq and Colombia, the EIA noted.

Meanwhile, Philadelphia waterborne crude imports increased 19% in 2015 as rail car deliveries of Canadian and Bakken oil to local refineries declined 15%. This trend is likely to continue if WTI trades at near-parity with Brent, according to Lawrence Goldstein, director of special projects for the Energy Policy Research Foundation.

“As long as these relative values favor imported crudes priced at Brent-linked prices, the trend will continue, especially when Jones Act restrictions and prohibitive Bakken rail delivery costs are factored in,” Goldstein told Midstream Business.

Transporting costs

The Jones Act, which requires U.S.-flagged and U.S.-crewed vessels to transport U.S. crude between U.S. ports, raises costs—between $10/bbl or $11/bbl—for U.S. refiners transporting domestic crude by sea (i.e., from the Gulf Coast to the East Coast).

“The Jones Act has outlived its usefulness,” Goldstein said. “Faced with having to absorb the Jones Act cost of shipping, the East Coast refiner is looking now to buy African crudes which, two years ago, we basically displaced almost completely. Nigerian crude had almost disappeared, and now we’re seeing a second wind.”

Due to this cost penalty for sea deliveries, rail can be competitive when the all-in delivered cost is at parity or below delivered foreign cargoes. Today the WTI-Brent differential prevents domestic crude reaching (delivered) parity whether delivered by rail or by sea, hence the increase of imported barrels. But that could be changing in the wake of the announcements by OPEC and Russia.

“If there’s demand for Bakken oil that’s keeping the price up, then it isn’t going to be economic, and it isn’t going to compete [with imported barrels],” Sandy Fielden, director of research, commodities and energy, at Morningstar, told Midstream Business.

Fielden noted that proposed and in-development pipelines could further pull barrels off U.S. railroads even if WTI becomes discounted enough again to compete with Brent and other foreign crudes.

For example, Energy Transfer’s 450,000-bbl/d Dakota Access Pipeline, anticipated to come online sometime in 2017, will connect the Bakken and Three Forks production areas in North Dakota to the Patoka, Ill., pipeline hub, which will be able to access multiple markets, including Midwest and East Coast refineries, as well as the Gulf Coast via the Nederland, Texas, crude oil terminal facility of Sunoco Logistics Partners.

Market observers suggest that, once this pipeline comes online, Bakken oil will have even more pipeline capacity than it has oil to supply to Northeast refiners. The question now seems to be will Dakota Access go onstream? Continuing, and often violent, protests against the project led the U.S. Army Corps of Engineers to withhold a necessary easement under North Dakota’s Lake Oahe as 2017 began while it considers alternate routes. A final decision will go to the new Trump administration, which is likely to be more supportive than the regulatory appointees of former President Obama.

“Crude-by-rail to the East Coast looks even more tenuous going forward,” Ogunnaike said. “The pipeline infrastructure has really improved dramatically, and that’s what’s driving narrow differentials, less so from crude exports.”

In addition, the new administration may approve TransCanads’s Keystone XL Pipeline project, vetoed by former President Obama. Keystone XL, designed to move heavy Canadian crude into the U.S., could further change the feedstock dynamics for U.S. refiners and their midstream suppliers.

Bryan Sims can be reached at bsims@hartenergy.com or 713-260-6460.

SIDEBAR: West Coast Refiner Sourcing Dynamics Better, Not Great

Crude-by-rail (CBR) shipments from PADD 2 (U.S. Midwest, mostly Bakken Shale) to California have all been dried up, mainly due to a stringent regulatory environment that has impeded rail terminal approvals for buildout, according to Sandy Fielden, director of research, commodities and energy, at Morningstar Inc..

At their height in December 2013, CBR shipments into California reached 36,000 barrels per day (bbl/d)—just 2% of the state’s 1.9 MMbbl/d refining capacity. They have since dropped significantly, Fielden explained.

“Not much has really ever got to California by rail, and it doesn’t look like much is going to unless some of these rail terminals that have been planned actually get built. Unless they’re built, you’re not going to get much more crude shipped to California regardless of economics,” Fielden told Midstream Business.

“If Permian production recovers, there might be an opportunity to pipe that out to the West Coast if the price is right, but it’s a big endeavor,” Fielden added. “It’s not something anybody is going to get the money to do right now, not until things are looking a lot more comfortable in the price.”

While California produces its own oil, it receives a lot more of its share via out-of-state imports, primarily Alaskan North Slope (ANS) crude, even as ANS production is declining. The state also imports large volumes of oil from Colombia, Mexico and South America. All these dynamics are occurring as significant amounts of Pacific Northwest crude are being exported to Asia.

“That’s a trend that we expected to have developed more quickly than it has,” Lawrence Goldstein, director of special projects for the Energy Policy Research Foundation, told Midstream Business.

Meanwhile, Pacific Northwest CBR economics continue to be resilient, according to Fielden.

Bakken crude from North Dakota competes at Washington refineries with ANS crude shipped down by tanker from Valdez, Alaska. In 2012, ANS prices were more than $20/bbl higher than Bakken crude—easily covering rail costs at more than $10/bbl. In 2016, the ANS premium to Bakken has averaged well below the $10/bbl freight cost, making CBR shipments uneconomic.

There are five refineries in the U.S. Northwest, all located in Washington state with a total operating capacity of around 647,000 bbl/d. Since there is no pipeline network to deliver U.S. inland crude to the Northwest, the only traditional source of supply aside from ANS has been from imports (mostly from Asia) or limited supplies of Canadian crude via the 300,000-bbl/d Kinder Morgan Trans Mountain Express Pipeline from Edmonton, Alberta, to British Columbia. Canada’s government approved an expansion of Trans Mountain to move 890,000 bbl/d in late 2016 with first service scheduled for 2019. However, heated opposition to the project could delay start up.

Nevertheless, in a similar way to what is occurring at U.S. East Coast refinery destinations, CBR volumes of inland oil being shipped to Northwest refineries have remained resilient in the face of poor economics, according to Fielden.

“We don’t know for sure, but this resilience is likely due to refiners having made term take-or-pay commitments to rail load and unload terminals and to leasing rail tank cars,” Fielden said. “These contracts mean that they have to pay variable transportation costs even if they don’t ship crude. They, therefore, continue to do so even though the economics are questionable at best.”

Tesoro Logistics LP continues to make sizeable CBR shipments westward to supply the 120,000-bbl/d refinery its parent, Tesoro Corp., operates in Anacortes, Wash.

“Tesoro’s Anacortes refinery has historically relied on a steady mix of Alaskan and Canadian crude oil supplemented by imported barrels from all over the world,” Phillip M. Anderson, Tesoro Logistics president, told Midstream Business. “The Bakken barrel works really well with the configuration of that refinery and produces a better slate of products than ANS. A large portion of the refinery diet is now made up of Bakken, and it gives them some additional flexibility to fill out the remaining slate that still consists of a lot of Canadian and ANS crude.” —Bryan Sims