bentek_exportslastdemandstanding_april2015

Exports: Last Demand Standing April 1, 2015

Page 1

Key Takeaways

Inventory builds are implying the US is

oversupplied by 800 Mb/d

Traditional sources of demand in years past

(displacing imports, higher refinery runs) have

largely run their course

The massive oversupply situation at current

production levels provides a sobering narrative on

the prospects for further growth in US production

Unrestricted exports of crude provide the last

significant source of demand

Premise

The US crude oil market has finally hit the proverbial wall that Bentek Energy has long predicted

would arise as a result of persistent supply growth. Traditional demand sources are struggling to

absorb this growing supply, made evident by crude inventories that are surging higher at

unprecedented rates. Domestic production, however, remains captive in the US due to

antiquated policies that limit the exports of domestically-produced crude. Growing US supply

has led to depressed prices, signaling to the market that the US is surpassing demand needs at

todays production level of 9.4 MMb/d. Exports to the globe, therefore, are the last significant

demand source for US crude. Unchanged, the current US crude export policy signals the end of

growth in North Americas shale crude revolution.

Market Alert Exports: Last Demand Standing

April 2015


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The Wall: How We Got Here

The US refining complex has absorbed incremental US production by sourcing domestic crude over

waterborne imports and operating at higher utilization rates than previous years. However, demand

markets have reached the point at which they can no longer absorb this growing production and

domestic storage is filling to record levels.

US production grows

After peaking at roughly 10 MMb/d in 1970, and averaging around 9 MMb/d in the 1970s and early

1980s, US production declined by about 2% year-over-year for the next two decades, spurring

worries of peak oil. With the proliferation of hydraulic fracturing and horizontal drilling, however,

worries of peak oil were shelved, and exploitable crude reserves in the US grew exponentially. In

2008, US production averaged just 5 MMb/d. Since then, production has grown substantially,

averaging 8.7 MMb/d in 2014. In 2014 alone, production grew by 17% over 2013 volumes, flooding

the market with an incremental 1.3 MMb/d.

In the wake of collapsing crude prices during the second half of 2014, US producers have

announced substantial cuts to planned capital expenditures and drilling programs, but few intend to

cut production. In fact, many producers still intend to grow production year-over-year, citing falling

service and drilling costs, with reductions ranging from 10% to 50%, and falling tax rates linked to

crude prices. Producers also intend to target their most productive acreage where they have realized

considerable efficiencies, resulting in reduced drilling times and high initial production (IP) rates.

Additionally, contractual obligations and hedging programs will allow some producers to meet near

term production targets despite the low price environment.

US supply displaces comparable waterborne imports

A large portion of US production has historically been light-sweet crude, a low-density, low-sulfur

grade considered to be of high quality because it typically requires less complex infrastructure and is

easier to refine than high-density, high-sulfur grades. As US light-sweet crude production declined

through the end of the century, US refineries anticipated any future supply would be of a heavier,

sourer quality and adjusted much of its infrastructure accordingly by installing complex units capable

of refining more viscous crudes into refined products. Domestic refineries also became increasingly

reliant on waterborne imports. Waterborne crude imports into the US (imports from countries other

than Canada), averaged 8.2 MMb/d in 2008, of which 1.9 MMb/d was of light-sweet quality similar to

that produced in the US today, and 6.3 MMb/d of which was heavier and sourer than the majority of

US production. In 2014, however, total US waterborne imports averaged just 4.45 MMb/d, of which

only 198 Mb/d was of light-sweet quality.


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The remaining 4.45 MMb/d of imports is too heavy and sour for US refineries to easily displace with

domestic production. Refineries configured to refine heavier, sourer crude will likely continue to find

it economic to source feedstock from the foreign sources where heavy, sour crude supply is

abundant, as configuration modifications are capital-intensive and time-consuming. In order to

incentivize substantial investment in reconfiguration once again, refiners would have to expect the

economics of running light-sweet crude not only to exceed those of running heavier crudes, but also

to exceed them by enough to justify further capital deployment.

With only 160 Mb/d of light-sweet imports remaining as of December 2014, US production has

displaced nearly all comparable waterborne imports.

US refineries increase utilization rates

In addition to sourcing domestic crude over waterborne imports, refineries in the US are operating at

higher utilization rates in an attempt to absorb incremental production. Since 2010, refinery utilization

has grown from an average of 86.3% to 90.4% in 2014. Required maintenances throughout the year

hinder the ability of refineries to maintain consistently higher utilization rates. In addition, several

refinery expansion projects and new builds increased total US refining capacity by 286 Mb/d from

2010 to 2014. As such, US refineries have, in total, processed 1.12 MMb/d more crude in 2014

versus 2010.

Source: EIA

-5000

-4000

-3000

-2000

-1000

0

1000

2000

3000

4000

5000

2011 2012 2013 2014

Mb

/d

Incremental Supply/Demand versus 2010

Production Refinery Runs Heavy Intermediate

Light Sour Light Sweet Exports Adjustment


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Looking forward, a risk to maintaining high refinery utilization rates exists due to the changing

landscape of the refineries that still operate in the US. Though total US refining capacity has grown,

since 1985, sixty refineries have been decommissioned in the US. That has changed the refining

landscape to rely on high utilization rates on the operations of fewer refineries. Therefore, the total

utilization rate can be significantly affected by an accident, unplanned maintenance, or a labor

dispute at any remaining refinery.

Storage inventories nearing tank tops

Crude barrels that cannot be absorbed into the US refining market, or displace waterborne imports,

must accumulate in US storage complexes. Typically, crude inventories draw down at the end of the

year when refineries maximize utilization. However, this trend reversed at the end of last year. In

December 2014, refineries were operating at 94% utilization, yet crude inventories continued to grow

throughout the end of the year and into 2015.

300

320

340

360

380

400

420

440

460

480

500

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

MM

bb

ls

US Crude Stocks (excl. SPR)

5 Year Min-Max Range Avg. 2010-2014 2013 2014 2015

Source: EIA


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After eleven weeks of aggressive stock builds at an average of 7.7 MMbbls per week to begin 2015,

commercial stocks reached 467 MMbbls as of March 20th, the highest recorded inventory since

1930, exceeding the five-year March average by over 100 MMbbls. If builds persist at this

aggressive rate, total US inventories (which includes line fill, lease tanks, and oil in transit from

Alaska) will exceed 500 MMbbls as soon as the last week of April. Though inventories typically build

when refineries enter into maintenance season in the first quarter, the five-year average injection

rate has been only 2.1 MMbbls per week through the third week of March, far below the

aforementioned 2015 average injection rate. The discrepancy between the historical average

injection rate, and the injection rate thus far in 2015, implies that the domestic market is oversupplied

by around 800 Mb/d ((7.6 MM - 2.1 MM)/7 days per week = 800 Mb/d).

Source: EIA

Overall, persistent storage builds clearly indicate that, though refineries have absorbed much more

supply, the US refinery market is approaching the limits of its ability to absorb incremental, domestic

production.

Exports, the only remaining outlet for US production

In the wake of the Arab oil embargo of the 1970s, and consequent fears of supply shortages, the US

government imposed restrictions on the ability of producers to export domestically-produced crude.

Until only recently, the US has relied heavily upon foreign oil in order to fuel the economy. Global

supply disruptions and political conflicts have often sent global prices sky-rocketing, leading the

(2,000)

0

2,000

4,000

6,000

8,000

10,000

12,000

M b

bls

Weekly Inventory Builds

5 Year Average 2015


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American public to largely dismiss the idea of crude exports. Additionally, the fact that the US still

imports foreign oil begs the question as to why domestic crude should be exported.

As mentioned, nearly all waterborne imports into the US are of a heavier, sourer quality than US

production. Due to the refinery configuration in the US, as well as feed slate preferences, the

demand for heavy-sour crude is expected to either remain relatively stable going forward, or even

grow as refiners take incremental heavies for blending with lighter grades. Additionally, raw crude oil

has little value until it is refined into consumer products, such as gasoline, diesel, and jet fuel. US

refineries are legally able to export those products, and the US has actually become a net exporter

of refined products, with total net exports having averaged 1.9 MMb/d in 2014. By contrast, the US

was a net importer of refined products as recently as 2010, to the tune of around 270 Mb/d.

However, the general publics lack of understanding regarding the chemical composition of crude oil

and the downstream economics of the commodity hinders the paradigm shift in American sentiment

required to lift export restrictions.

As refineries reach their capacity to absorb incremental US crude production, and storage levels are

approaching working capacity, the next several months will demonstrate the damaging short-term

and long-term effects sustained export restrictions will have on domestic crude prices, the US oil

exploration and production (E&P) industry, and the US economy as a whole.

Summer 2015

Spring refinery maintenance season is typically completed by the end of April, and refineries once

again ramp up utilization in anticipation of summer demand for gasoline and other refined products.

The higher utilization by refineries leads them to source supply from storage, drawing down

inventories that were built up during maintenance. Stocks fall, on average, about 1.15 MMbbls per

week throughout the summer (May-August), but at currently elevated inventory levels, stocks must

draw at much faster rates this year in order to return inventories to more manageable levels before

the end of summer, when refineries begin fall maintenance.

Since 2010, stock levels have drawn down to around 360 MMbbls by the last week of August;

however, since 2010 capacity has been added in the form of both tank and pipeline infrastructure

expansions. For this reason, Bentek will use 400 MMbbls as a reasonable level for stocks to draw

down to by the end of August. While this would still imply a persistently oversupplied environment, a

draw down to this level would provide some breathing room for the export discussion to continue.

With this predicament in mind, the following section lays out an aggressive demand scenario for the

summer of 2015 to paint a picture of the magnitude of adjustments the market needs to make in

order to return storage levels to relative normalcy before the fall refinery maintenance season

begins. Production levels will be held constant at todays production rate to stress the severity of the

current situation.


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Further import displacement

As mentioned, US production has already displaced nearly all crude imports of comparable quality.

Light-sweet waterborne imports into the US averaged just 230 Mb/d last summer. Theoretically, US

refiners can consume an additional 230 Mb/d of domestic crude this summer and forego all light-

sweet waterborne imports. However, these remaining imports of light-sweet crude were

predominantly supplied to East and West Coast refineries, which have essentially no pipeline

connectivity to domestic supply. Therefore, the WTI-Brent differential will have to remain wide to

incentivize refineries on the East and West Coast to absorb rail and/or barge transportation costs

from US production areas rather than import foreign barrels.

As US production began aggressively displacing waterborne imports of light-sweet crude, imports of

light-sour and intermediate grade crudes remained relatively stable through the end of 2013. During

2014, however, imports of these grades fell by 47%. Though light-sweet US barrels are not direct

replacements for these grades, the decrease in the imports of these mid-range barrels during 2014,

coupled with increasing imports of heavy-sour grades, signifies US refiners were blending heavy and

light barrels in an effort to displace mid-range waterborne imports. It is important to note, however,

that blending a heavy barrel with a light one does not necessarily produce the same refined product

mix that refining a true intermediate barrel does. An economic blend depends largely upon the

appetite of each individual refinery and, therefore, it is unlikely that US production can entirely

displace light-sour and intermediate imports.

Summing up, some waterborne heavy-sour grades will be displaced by incremental production from

Canada entering the US, domestic production will displace all light-sweet imports, and, to an extent,

further blending of heavy and light grades will displace mid-range waterborne grades. For the

purposes of this analysis, we will assume that total waterborne imports can fall to just 3.8 MMb/d this

summer, a 715 Mb/d decrease from last summer.

Refineries run even harder, allowed exports double

Refineries operated at a 90.9% and 92.2% utilization rate in the summers of 2013 and 2014,

respectively, suggesting an increase of 1.3%. We will suppose in our aggressive demand scenario

that refineries are able to increase utilization at the same rate into 2015, operating at 93.5%

utilization throughout this summer. Additionally, two new refineries configured to consume US light-

sweet crude, Dakota Prairies 20 Mb/d refinery in North Dakota and Kinder Morgans 100 Mb/d

condensate splitter in Houston, will add another 112 Mb/d of incremental demand, assuming this

additional capacity will operate at a 93.5% utilization as well. All told, this scenario analysis will

assume refineries will generate 245 Mb/d of incremental demand.


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Allowable crude exports under current regulations, though relatively small, could see substantial

increases summer-over-summer. Exceptions to US crude export restrictions include crude exported

to Canada, production from Alaskas Cook Inlet, and stabilized condensate (ultra-light crude lightly

refined at a condensate stabilizer). US crude exports averaged 370 Mb/d last summer. In this

aggressive demand scenario, we suppose that exports will double over last summers levels to 740

Mb/d.

Assuming the US can, in fact, displace 715 Mb/d of waterborne imports, US refineries can absorb an

incremental 245 Mb/d, and allowable exports can double summer-over-summer, stocks would draw

by approximately 497 Mb/d, or 3.5 MMbbls per week, throughout the summer. US inventories would

end the summer with 442 MMbbls in storage, still 84 MMbbls above the average August inventory

levels.

ProductionWaterborne

Imports

Canadian

Imports

Storage

WithdrawalAdjustment

Refinery

RunsExports

2013 7,366 5,406 2,460 252 326 15,743 107 -40

2014 8,673 4,516 2,811 284 271 16,188 370 -2

2015 9,400 3,800 3,100 497 375 16,432 740 0

Source: EIA, Bentek

* All values are in Mb/d

** The 'Adjustment' value is an EIA fill number used to balance the reported crude oil supply and demand numbers

*** An 'Adjustment' value of 375 Mb/d was used as a representation of what the implied adjustment has been in 2015

May - August

Supply DemandBalance

The End of the US Energy Renaissance?

In this aggressive demand scenario, US inventories are only expected to draw down to 442 MMbbls

by August 2015, 84 MMbbls above the five-year average. For inventories to reach 400 MMbbls,

stocks would have to fall by 830 Mb/d, or 5.8 MMbbls per week. Therefore, in order to reach

normal storage levels by the end of August, the US would have to export over 1.08 MMb/d, an

additional 335 Mb/d beyond that of the aggressive demand scenario laid out above.

US producers have already indicated they intend to export self-classified stabilized condensate

without formal approval from the Bureau of Industry and Security (BIS) and Eastern Canadian

refineries intend to continue to source increased volumes of US light-sweet crude. An additional 370

Mb/d of exports year-over-year, though aggressive, is not unreasonable under current export

restrictions. To meet the 1.08 MMb/d of required exports to balance the market, however, the US

government must formally change their policy to allow raw crude oil exports.


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If export policy remains unchanged, barring significantly higher refinery runs and/or feedstock

switching, the challenges of which have been discussed in some detail already, the alternative is that

production would have to drop to 9.07 MMb/d for inventories to draw down to normal levels by the

end of August. That is an over 300 Mb/d drop from current production levels. To realize that kind of

drop in production would require drilling to slow down well beyond what it already has, and

potentially shut in existing production if the market needs to see that kind of response occur by this

summer.

Exports a needed option, but not a panacea

Taking a look at the global picture, while the general consensus is that the global market will be

nearly balanced by the latter half of 2015, several factors could rapidly change this picture. One

such factor that the market has been cautiously following is whether a deal is struck between the US

and Iran over Irans nuclear program. If a deal does happen this summer, the restrictions that are

currently limiting Irans ability to export crude to international counterparties will be lifted, and a

potential 1.0 MMb/d of incremental crude will flood the global markets. Another country where the

landscape could rapidly change is Libya. Internal fighting in the country has caused large volatility in

the amount of production that is available for export. If the parts of the country where production and

shipping take place were to stabilize, incremental production could rapidly return to the market as

well. The recent events surrounding the conflict between Saudi Arabia and rebel groups in Yemen

are a stark reminder of the immediate impact this kind of turmoil can have on oil prices.

These factors, among other uncertainties and potential global supply risks, will ultimately decide

whether Brent prices come under pressure, or can begin to appreciate once more. A global supply

shock is likely to widen the spread between Brent and WTI. While a wide differential between WTI

and Brent exists, theoretically, arbitrage would open for US exports of crude to international refining

centers. However, if global supply is able to ramp up at more aggressive rates than is currently

expected, US exports would be fighting for space in an already oversupplied global market. In this

situation, Brent prices would come under additional pressure, and the WTI/Brent spread would likely

narrow. In a narrow WTI/Brent spread environment, US production will struggle to compete into

international refining centers, even if exports were not restricted.

A sobering outlook

Without unrestricted exports, the US E&P industry will suffer. To balance the market, US producers

will have to reduce costs further, resulting in additional capital fleeing the energy market, and a loss

of wages and employment in the industry. The cost reduction will trickle down through the supply

chain to other industries that rely on E&P for a portion of their profits, including, but not limited to,

service companies, steel tube and pipe manufacturers, trucking companies, and local businesses

patronized by oil field workers. The oil and gas industry was hailed as the driver of economic and job


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growth in the US in the wake of the Great Recession of 2009. Any slowdown in this sector is

therefore concerning as it has played a significant role in the economic recovery to date.

Benteks production projection models indicate that, absent a lack of demand, US production could

continue to soar in the years ahead. However, incremental domestic demand for US production

growth is waning and the market is largely signaling the end to the boom in US production without a

new source of demand. Unrestricted crude exports on the back of US policy change are the most

immediate solution to finding that demand. While there is no guarantee that the global market would

be able to absorb incremental production growth from the US, the optionality of exports would

provide the much-needed relief valve to provide an outlet for future US crude production growth.

CONTRIBUTORS & ACKNOWLEDGEMENTS

Tony Starkey, Manager, Energy Analysis [email protected]

Jenna Delaney, Energy Analyst [email protected]

Nicole Leonard, Project Consultant [email protected]

David Xu, Energy Analyst [email protected]

For more information online:

www.bentekenergy.com
mailto:[email protected]:[email protected]:[email protected]:[email protected]://www.bentekenergy.com/

bentek_exportslastdemandstanding_april2015

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