FUELSNews 360º - Q3 2017 by FUELSNews

M A R K E T

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I N F O R M A T I O N

Table of Contents FUELSNews 360° Quarterly Report Q3 2017 FUELSNews 360°, published four times annually by Mansfield Energy Corp, analyzes and summarizes the prior quarter’s activity in the oil, natural gas, and refined products industries. The purpose of this report is to provide industry market data, trends, and reporting both domestically and globally as well as provide insight into upcoming challenges facing the energy supply chain.

Executive Summary

Overview 6

July 2017 through September 2017

Economy & Demand

Fundamentals

24 26

Inventories

Exports

Production and Refining Capacity

PADD 1A, 1B & 1C Northeast, Central Atlantic & Lower Atlantic

2017 Hurricane Impacts on U.S. Fuel Supplies

National Truck Driver Appreciation Week

Perfect Storm of Panic Buying

Natural Gas Procurement in the Age of Choice

By Nikki Booth

Part Two By Tom Krizmanich

PADD 2, Midwest

Nate Kovacevich

PADD 3, Gulf Coast Nate Kovacevich

Wending the Way to Oil Market Balance

By Nancy Yamaguchi, Ph.D.

PADD 4 & 5, Northern Plains, West Coast, AK & HI

Amy Nguyen

Martin Trotter

By Dan Kemeny

Chris Carter

Natural Gas

By Alan Apthorp & Madi Burton

Regional Views

Renewable Fuels

Sara Bonario

Viewpoints 26

Alternative Fuels 22

FUELSNews 360˚ Supply Team

Canada

Nate Kovacevich

Due to extreme fuel supply conditions resulting from hurricane activity, this quarter's edition of FN360° was published later than usual. We apologize for the delay.

Q3 2017 Executive Summary The third quarter of 2017 was a tumultuous one for markets,

At the regional level, refineries throughout the country opted to put

characterized by an uptick in both geopolitical activity and weather

off repair work, staying open to capitalize on higher prices during

events. Prices trended higher as OPEC cuts tilted markets towards

the post-Harvey recovery. Repairs cannot be put off forever, so

supply tightness and declining inventories, especially in the U.S.

expect to see above-average refinery maintenance activity in Q4 and into 2018 which could impact regional fuel prices.

On the supply side, the OPEC/Non-OPEC deal continued to drive markets higher, though the deal, at times, struggled to contain

In the Northeast, the battle continues raging between Chicago-area

Libyan and Nigerian production. American production continued to

refineries pushing fuel eastward and refineries along the East Coast.

dazzle markets with its growth, despite a temporary slowdown

Crude economics make fuel from Chicago cheaper, putting East

during Hurricane Harvey.

Coast refining operations at risk. Chris Carter gives an update on the

Around the world, political struggles rose to the top of the headlines

on-going struggle on page 16.

impacting crude oil prices. East Asia, South America, and the Middle

Looking to Q4 2017 and early 2018, expect prices to remain

East all experienced their share of instability, and a new and un-

elevated, with crude oil in the $40s unlikely to return soon. Supply

tested U.S. president created added layers of risk for markets. Those

tightness will likely continue at least through March 2018 when the

trends will continue to play out over the coming three to six months

OPEC/Non-OPEC cuts expire; beyond then, only time will tell.

and represent one of the largest risks for fuel price.

Although U.S. crude will continue to keep a lid on WTI crude prices,

Despite international uncertainty and rumors of conflict, oil demand was strong throughout Q3 in the U.S. and worldwide, driven by

the floor has also been set, keeping prices in the $50-$60 range for the next quarter.

strong economic growth. In the U.S., economic factors are the

This quarter, Tom Krizmanich continues his three-part series on

strongest they’ve been in years, leading many to expect an interest

natural gas procurement. This quarter’s article details the key

rate increase before the end of the year. Looking to the future,

considerations to make when choosing a natural gas supplier, as

economic strength should continue to propel oil demand higher.

well as what service offerings to consider when buying gas. Make

At the fuel products level, no factor in Q3 was more disruptive than Hurricanes Harvey and Irma, which devastated refineries along the Gulf Coast and caused both domestic and international fuel

sure to read FUELSNews 360° next quarter to examine the synergies between fuel and gas buying, and how both types of buyers can learn from each other.

disruptions. Along with limited fuel supplies, fuel transportation was

We hope you enjoy this quarter’s issue of FUELSNews 360°. Please

hampered, including the slowdown of the Colonial Pipeline and

feel free to email us at fuelsnews@mansfieldoil.com with feedback,

freight shortages throughout the Southeast. More details on the

questions, or to request additional copies.

impacts of the storms are included on page 26.

Overview July 2017 through September 2017 WTI Crude Oil Futures

Source: New York Mercantile Exchange (NYMEX)

Fuel prices climbed throughout the third quarter of the year, though with plenty of peaks and valleys. WTI crude oil prices ranged from a low of $44.23 near the beginning of the quarter to peaks over $52 as September closed the quarter. The quarter began on a low note, with a Russian statement squashing hopes of deepening OPEC cuts. Not long before, the OPEC/Non-OPEC group had agreed to extend production cuts until March 2018, which markets responded to by sending prices significantly lower. Rumors had been building that cuts may be deepened, leading to market disappointment when the rumors did not come to fruition. Russia continued the sentiment, saying they did not see a need for production cuts since supplies were already beginning to tighten. Soon after Russia’s statement, OPEC reported the organization’s production increased by 300 kbpd, sending compliance down to 78%. Nigeria and Libya propelled output higher, unbound by the production limits other members subscribed to. The two countries would later be required to establish production caps of 1.8 MMbpd (Nigeria) and 1.25 MMbpd (Libya), which were more symbolic than substantive, since their production is still much lower than the set limits. Of course, just weeks later, Nigeria was forced to declare force majeure on some oil fields, demonstrating why the country sought an exemption when the OPEC deal was signed. Inventories played a major role throughout the beginning of Q3, with markets looking for signs that supply conditions were tightening. As reports came out of improved demand outlooks and deep supply cuts, markets felt confident that prices should rise, leading prices to generally trend higher throughout the quarter, with some peaks and valleys. 6

Geopolitical tensions were endemic throughout the quarter, driven largely by uncertainty surrounding President Trump’s response to events. When the President tweeted that the U.S. was “locked and loaded” to respond to North Korea, markets plummeted, expecting escalating tensions in East Asia to destroy oil demand while not impacting production. On the flip side, threats of sanctions against Venezuela caused prices to move higher. Venezuela provides a significant amount of crude oil to the U.S. Gulf Coast for refining, so sanctions would have forced Gulf Coast refineries to find alternative supply sources. Amid all of the geopolitical tensions, Ecuador added a new twist to the international supply picture – the small country announced their intention to exit the OPEC deal. The country, badly drained of resources, simply could not sustain the output caps. Although the country’s oil production is a blip compared to overall OPEC output, the symbolic importance was questioned by markets. If Ecuador could exit the deal, who would follow? It turns out, none would follow Ecuador. Soon after the announcement, OPEC compliance was shown to be 94%, and markets were reassured that cuts would last. As the quarter continued, OPEC began to once again start talking up the market, this time rumoring that deeper cuts or an extension were possible in 2018. An overview of Q3 would not be complete without a thorough review of Hurricanes Harvey and Irma, which we provide on page 26. Harvey wrought intense flooding and wind damage in Texas and Louisiana, taking 20% of the U.S.’s entire fueling infrastructure offline. Because it hit refineries harder than it hit oil fields, Harvey caused gasoline and diesel prices to surge, while crude prices fell.

Overview Since Hurricane Harvey, crude prices have normalized and even risen higher. Overall, Q3 saw crude prices rise back to the top of their 2017 range of $45-52 range, ending the quarter on September 29 at $51.67. The average price during the quarter was $48.20, just five cents higher than previous quarter and $3.26 higher than during Q3 2016.

Quarterly WTI Crude Prices

Like crude prices, diesel prices have seen steady gains since Hurricane Harvey. While gasoline saw an acute run-up in price followed by an intense slump, diesel prices have been playing the slow-and-steady game, moving from the $1.50-$1.60 range all the way to around $1.80. NYMEX diesel prices averaged $1.65, $.14 higher than Q2 diesel prices and 24 cents higher than the same period in 2016. Gasoline got a strong boost from Hurricane Harvey, but fell back down very quickly after the storm. Gasoline prices averaged $1.63 in Q3 2017, up a mere 5 cents from Q2 2017 and up $.23 from 2016 levels. â&#x20AC;˘

Source: Energy Information Administration (EIA)

Port of Houston

Quarterly Gasoline Prices

Quarterly Diesel Prices

Source: Energy Information Administration (EIA)

ÂŠ 2017 Mansfield Energy Corp

Source: Energy Information Administration (EIA)

Overview

Summary, Third Quarter, 2017

$1.6065 $1.8117

$51.67

22405

Source: New York Mercantile Exchange (NYMEX), Dow Jones Industrial Average

ÂŠ 2017 Mansfield Energy Corp

IIIII II

Economy & Demand

IIII II I

IIIII II

The Federal Reserve put off an interest rate increase during Q3, though markets expect at least one more increase before the end of the year. Should the Fed come through on increasing rates once more, the dollar will rise, putting downward pressure on fuel prices. The dollar could certainly use assistance from a rate hike. The US Dollar Index continued its fall throughout early Q3; the US Dollar Index fell 13% between November, 2016 when President Trump was elected, and early September,2017. Since then, however, markets have picked up, gaining 3.8% back.

IIII II I

Generally, the US Dollar and crude markets are negatively correlated; when one falls, the other rises. A weaker Dollar makes it cheaper for other countries to buy oil, increasing demand and pushing up prices. Despite the increase in the Dollar in late September, however, crude markets also rose, indicating that there was enough pressure for higher prices to overcome headwinds from the Dollar.

U.S. GDP Growth

The U.S. economy has been growing at a strong clip, with Q2 economic growth pegged at 3.1% annualized, and Q3 growth estimated to have been 3.0%. That’s a strong pickup from the 1.4% annualized growth announced in Q1, and it has helped drive strong fuel demand throughout the quarter. GDP was propelled by consumer spending and business investments, while lower housing investments put a damper on growth.

Source U.S. Department of Commerce

Unemployment continues to edge its way lower, reaching 4.2% in September and averaging 4.3% for the month. In conjunction with the reduced unemployment rates, September data showed a loss of 33,000 jobs in the U.S. economy, the first time jobs have fallen in seven years. September’s data marks the lowest unemployment numbers in over a decade, though the numbers may have been slightly skewed by the hurricane. Some expect to see hiring rise in coming months, strengthened by demand following Hurricane Harvey.

U.S. Unemployment Rate

Globally, that trend is playing out as well. Most major economies expect steady growth in the short-term, though medium- to long-term growth is less clear. The OECD forecasts global growth to be 3.5% in 2017 and 3.7% in 2018. That forecast represents a forecast for Europe that was stronger than last quarter, while growth in India was reduced by half a percent. Globally, business investments and consumer spending are creating momentum behind growth, though continued efforts will be needed to extend that growth into late 2018 and beyond.

Source: Bureau of Labor Statistics

Economy & Demand World trade volume picked up somewhat during Q3, gaining 1.2% in August according to the CPB Netherlands Bureau for Economic Policy Analysis. The increase followed a slight 0.1% reduction of volumes in July. Gains for August were led by China and India, while North America and Australia had slightly negative growth during that time. Global trade is a particularly important factor for crude markets since imports and exports require transportation across much farther distances, increasing the energy needed to move goods. â&#x20AC;˘

U.S. Fuel Demand

Fuel Demand

Global oil demand is set to accelerate as we end 2017, propelled by strong economic growth around the world. In Q3, fuel demand grew by 1.2 MMbpd yearover-year, a slower rate than Q2, which was 2.2 MMbpd growth. Still, growth has been strong, and the International Energy Agency (IEA) expects 2017 oil demand growth to be roughly 1.6 MMbpd. In the U.S., fuel demand has averaged 19.9 MMbpd, though that rate has increased throughout the year. According to the EIA, demand will rise even higher in 2018, propelled by strong growth in products besides conventional gasoline and diesel (products such as propane and biofuels).

Source: Energy Information Administration (EIA)

ÂŠ 2017 Mansfield Energy Corp

Economy & Demand Diesel demand in Q3 was higher than seasonal averages, reaching 800 kbpd over five-year averages in early August. Diesel demand is closely correlated with economic growth – economic activity leads to more goods being shipped, increasing rail and truck diesel consumption. Harvey caused a slight uptick in demand before sending demand far lower, a mixture of seasonal trends and demand destruction during Harvey. Since the storm, demand has struck back. Going into Q4, demand is expected to remain high, receiving a boost from chilly winter weather driving heating oil demand and busy agricultural harvests. Strong diesel demand will keep diesel prices elevated throughout the winter.

U.S. Diesel Demand vs. 5-Yr Range

Source: Energy Information Administration (EIA)

Gasoline has trended along the upper edge of historic seasonal averages. This summer saw a heavy driving seasons amid low retail gasoline prices. Gasoline demand is highly responsive to retail prices – when prices are high, drivers seek out ride-sharing options or cut down on road trips to conserve costs. As the summer turned to fall, demand began falling off as usual, though it’s remained at the top of 2012-2016 historic levels. Gasoline demand has been over 9 million barrels per day for most of the year. •

U.S. Gasoline Demand vs. 5-Yr Range

Source: Energy Information Administration (EIA)

Fundamentals

Inventories

Crude Inventories 5-Yr Range

Inventories in Q3 were strong drivers of fuel prices, with good reason. After trending even higher than 2016â&#x20AC;&#x2122;s historically high inventory levels, crude stocks finally dipped below 2016 levels in July, continuing the trend downwards through August before briefly popping up again thanks to Hurricane Harvey shutting in refineries and ports, trapping crude oil in storage. Inventories began the quarter at 495 million barrels (MMbbls), just 5 million barrels above 2016 levels but a staggering 130 MMbbls above 2012-2015 averages. Crude inventories bottomed out on August 25 at 459 MMbbls, an impressive 36 MMbbl draw in just 8 weeks (-7.2% change, an average of 4.5 MMbbls drawn each week). The declines did not last, however, and stocks added 15 MMbbls in just three weeks after Hurricane Harvey. Since then, the trend has been back downwards, driven by strong U.S. crude exports.

Source: Energy Information Administration (EIA)

Gasoline Inventories 5-Yr Range

While Harvey drove crude inventories higher, gasoline stocks fared differently. For most of the year, gasoline has remained about 25 million barrels above the 2012-2015 average; in September, they fell below 2015 levels, reaching their lowest level in years. Without refineries online to add gasoline to fueling transport systems, suppliers were forced to rely on gasoline in storage, causing prices to skyrocket during and immediately following Hurricane Harvey. Gasoline inventories began the quarter at 236 MMbbls, falling as low as 216 MMbbls (a 20 MMbbl drop, of 8.5%) in late September. Inventories did add over 2 MMbbls back in the last weeks of September, as refineries came back online and gasoline demand fell off due to demand destruction.

Source: Energy Information Administration (EIA)

ÂŠ 2017 Mansfield Energy Corp

Fundamentals

Diesel Inventories 5-Yr Range

Diesel had its own unique path following Harvey. Unlike gasoline stocks, diesel stocks continued their draws unabated, with five straight weeks of draws to end the quarter. Diesel inventories began the quarter at 137 MMbbls, and ended the quarter at a low-point of 117 MMbbls, which like gasoline, was a 20 MMbbl draw, but was double the size of gasoline’s draws on a percentage basis (14.6% vs. 8.5%). One fascinating trend in Q3 2017 was that diesel inventories actually ended lower than they began. Diesel inventories typically rise throughout the year before seeing steep losses in the autumn and winter. Autumn demand is driven by agricultural demand, and is particularly acute in the Midwest. Heating oil, used to heat homes in northern states, experiences strong demand during the winter, causing diesel stocks to continue falling. This year, inventories are already lower heading into the fall; markets are expecting more steep draws for the next several months, which could put inventories directly in line with historical levels. •

Exports

Source: Energy Information Administration (EIA)

U.S. Weekly Crude Exports

In Q3, U.S. exports exploded, driven by rising Brent-WTI spreads. WTI crude oil is made in America, while Brent crude is considered the international price of crude oil. The difference between those two oil indexes drives imports and exports for the U.S. In 2014/15, the spread reached as high as $13/barrels; however, producers could not capitalize on higher international prices because of a ban on exports. Until December 2015, crude exports could only travel to Canada. Even after the ban was lifted in December 2015, exports remained weak for years, as export infrastructure took time to be created – pipelines aren’t built overnight. Since January 2017, exports have been increasing, rising above 1 million barrels per day on several occasions. Exports remained suppressed, however, by narrow Brent-WTI spreads. When exporting internationally, barges cost roughly $4 per barrel of crude, meaning that Brent-WTI spreads must increase beyond $4/bbl to incentivize strong exports.

Source: Energy Information Administration (EIA)

That opportunity came following Hurricane Harvey, when U.S. crude prices fell amid declining refinery run rates. Brent prices soared during that period, boosted by strong demand for refined products in the U.S. Brent-WTI spreads surpassed $5, and kept soaring as high as $7. The spread ended the quarter at $6, accompanying a record high level of exports – just shy of 2 million barrels per day. • 13

Fundamentals

Production

U.S. Crude Production

Crude oil production in the U.S. has risen to be just shy of record production levels set in June 2015, just before the bottom fell out of the market and prices collapsed. The highest weekly reading of U.S. crude production was 9,610 thousand barrels per day (kbpd); the last posted level in September 2017 was just 49 kbpd shy of that record level. U.S. producers are known internationally as swing producers, ramping up production when prices go up and shutting off the tap when prices fall. In Q3, crude prices averaged $48, slightly below the $50 level normally cited as necessary to justify production. However, prices in late September surpassed $50, leading to the high production levels seen as the month closed. •

Source: Energy Information Administration (EIA)

Refining Capacity

Refining capacity was significantly impacted in Q3 by Hurricane Harvey. For most of the summer, both refining utilization and overall capacity trended flat, with no major changes in refining infrastructure. Refining capacity decreased modestly in July as a few refineries went offline temporarily, but the overall trend in refining utilization was upwards.

MANSFIELD ENERGY

Of course, Hurricane Harvey stopped that in its tracks. Refinery utilization fell from almost 97% down to 80% in one week, bottoming out at 77.7% utilization during the peak of the outage. The outage had global implications – the reduced availability of fuel in the U.S. incentivized supplies from other countries to be sent to the U.S., driving up the prices of fuel slightly in other nations as well. Since oil is a global commodity, losing over 3 million barrels per day of refining capabilities, no matter where it occurs, will cause shockwaves throughout the world. •

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Refining Trends

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PADD 1

Regional Views Chris Carter,

Supply Manager

See his bio, page 36 East Coast PADD1A,1B & 1C Chris’ Predictions

Northeast, Central Atlantic & Lower Atlantic

“Refiners will likely continue

pushing additional product as refining margins increase and refineries come back online after the Q3 hurricanes. “

Expect to see an oversupplied PADD 1 market in both ULSD and Gas in the next quarter. Refiners will likely continue pushing additional product as refining margins increase and refineries come back online after the Q3 hurricanes. Florida markets will remain well supplied moving into their high driving season. •

The Fight Continues in Pittsburgh between Midwest and East Coast Refiners

Gasoline buyers in the Pittsburgh market continue to benefit from the ongoing price war between Midwest and East Coast refiners. In Mid-September, Philadelphia Energy Solutions (PES) began posting rack prices in Pittsburgh for the first time in several years. Traditionally, all deals with PES were done on a contract term; however, PES wanted to provide additional visibility into the wholesale market. During the past quarter, East Coast refiners posted wholesale prices up to 2.8 cents per gallon lower than Midwest refiners. Buckeye still plans on allowing Midwest barrels to flow from Pittsburgh to Altoona in 2018. East Coast refiners continue to voice their opposition to the reversal, stating that such actions would be detrimental to their business. •

Harvey and Irma Wreak Havoc on East Coast

The Southeast experienced heavy supply disruptions during Hurricanes Harvey and Irma, and with that came wide unbranded gasoline inversions. An unbranded gasoline inversion occurs when the average price of branded gasoline (gasoline marked for resale by a branded retailer such as an ExxonMobil, Shell, or Valero) falls below the cost of unbranded gasoline (sold to most bulk consumers).

Average Regular E10

The East Coast saw the spread between Gross Contract Average (GCA) and Net Contract Unbranded Low (NCUL) temporarily slide the week after Hurricane Harvey hit Texas. When that occurs, the lowest available supply for unbranded buyers (i.e. anyone other than retail gas stations) costs more than the average gallon of branded fuel. The situation in the Southeast grew particularly challenging during Hurricane Irma when supply that had already been stretched thin by Hurricane Harvey was forced to be re-routed to Florida. Throughout Florida and the Southeast, branded fuel sold for more than 10 cents below unbranded low. •

Source: Oil Price Information Service (OPIS)

Regional Views

Florida Gasoline Price Inversion

Florida and terminals fed by the Colonial Pipeline were most affected by the hurricanes. Several terminals reported runouts of unbranded supply in North Carolina following the storm. Florida experienced extremely tight supply leading up to Irma, but recovered quickly since vessels had prepared before the storm and the Jones Act had been waived for oil products in order to aid in market recovery. •

Source: Oil Price Information Service (OPIS)

Additional Changes to 7.8lb Requirements

Shelby County, located in the Memphis area, has followed the trend of other Southeast markets that will no longer be required to use 7.8lb gasoline next summer. The State of Tennessee also received a waiver for Nashville to drop the gasoline requirement earlier this year. There is speculation that the eleven Louisiana parishes that require 7.8 near New Orleans will be receiving a waiver before next summer, as well. The changing standards means better supply economics and reliability of supply for counties receiving the waiver. Only a few areas in the south require the boutique 7.8lb gasoline blend, making it difficult to secure supply when outages occur as product cannot be trucked in from surrounding areas. •

Colonial Plans to Decommission Line 25

Colonial Pipeline Gulf Coast Status Map

In August, Colonial announced that it will decommission Line 25 from Richmond into Montvale, VA in September 2018 due to a concern about the integrity of the stub line. Roanoke is also supplied via Planation Pipeline; however, it is unclear if it will be able to support the additional volume. In October, the stub line for Plantation pipeline was allocated for the first time in several years. Other than Roanoke and Montvale, the nearest terminals are Richmond and Greenville. For consumers currently supplied by Line 25, expect freight rates to increase due to the change, driving gasoline prices a few cents higher per gallon Colonial's Diesel Pipeline (Line 2) was reported down for less than 24 hours and began pumping at slower rates east of Hebert Station. It wasn’t until September 4th that Colonial restarted Line 2 between Houston and Lake Charles, with Line 1 (gasoline) following on September 5th. 17

Source: Colonial Pipeline Company

One of the main challenges suppliers faced along Colonial this quarter was the delay between cycles delivering into terminal cities. On a normal schedule, Colonial runs on a five day cycle; however, during Harvey, cycles ranged eleven to thirteen days between terminal locations. This resulted in several terminal cities running out of both gas and diesel. Gasoline was already facing challenges prehurricane as suppliers were running on tank bottoms in preparation for winter spec gasoline, deepening the effects of these delayed delivery cycles for gas. • © 2017 Mansfield Energy Corp

PADD 2 Midwest

“ With capacity normalizing and margins elevated, refiners should be more than incentivized to produce as much as possible to end the year. “

Regional Views

Nate Kovacevich, Sr. Supply Manager See his bio, page 36

Nate’s PADD 2 Predications

I’m expecting PADD 2 diesel and gasoline prices to head lower in the 4th quarter to follow the seasonal tendency after a normal spike in demand through the harvest. This year’s drop might be a little bigger than usual as NYMEX prices surged through most of September due to Hurricanes Harvey and Irma. With capacity normalizing and margins elevated, refiners should be more than incentivized to produce as much as possible to end the year. We’ve already heard of a couple Midwest refiners who have pushed their maintenance schedule from October to next year to take advantage of the refining economics as well as to help get more gasoline and diesel into the marketplace. This combination of increased refining capacity and a downtick in demand in November and December should lead to lower prices across the board. •

Tesoro and Western Refining are Now Andeavor

Tesoro Corporation announced its much anticipated completion of the $6.4 billion acquisition of Western Refining, Inc. The new combined entity will now officially be called Andeavor, with a total refining capacity of 1.1 million barrels per day (or 6% of the nation’s crude processing capacity). Andeavor will now be operating ten refineries in eight states, including Minnesota and North Dakota. The company will have a major presence in the northern-tier market that includes MN, IA, WI, SD, and most notably ND. Last year, Tesoro purchased the Dickenson, ND refinery from Calumet to go along with its refinery in Mandan, ND. Now, if crude oil prices were to ever head decidedly higher, Andeavor has some spectacular assets to take advantage of further development in the Bakken region. •

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Exxon Delays Refinery Work at Joliet until October, Holly Defers Overhaul until Q1 2018

ExxonMobil has pushed back an overhaul of its lone 240,000 bpd crude unit at the Joliet, IL refinery from early September to early October in response to supply shortages brought about by Hurricane Harvey. The crude unit was offline for 3 weeks. ExxonMobil said, “We are delaying scheduled maintenance at other ExxonMobil refineries so they can continue making gasoline and diesel to relieve the supply situation and also to free up people and equipment to help with the restart of affected Texas facilities.” In other Midwest refinery news, Holly Frontier has deferred an overhaul to its 85,000 bpd crude unit at its West Plant in Tulsa, OK, until February. The planned shutdown was expected to be large, with the turnaround expected to last as long as 8 weeks. The delayed turnarounds should help to relieve upward price pressure in both the Chicago and Group 3 markets during a time when the demand for diesel jumps. September and October is the strongest demand timeframe and typically coincides with some form of refinery maintenance, hence, we tend to see prices in the Midwest move higher during the fall timeframe. ExxonMobil’s move to delay its maintenance should help the supply situation in the Chicago region in lieu of Citgo’s Lemont refinery going down in early September for planned maintenance. •

PADD 3 Gulf Coast

Regional Views

Nate Kovacevich, Sr. Supply Manager See his bio, page 36

Nate’s PADD 3 Predications

“ The path towards recovery will continue into Q4, which should help normalize a number of Texas markets. “

Gulf Coast refineries ended the month of September in a much better place than the previous month; however, there are still several refineries that are producing at reduced levels. The path towards recovery will continue into Q4, which should help normalize a number of Texas markets. As I write, we still have a couple of markets that remain tight in West Texas, but conditions have improved dramatically, helped by those who have railed product into those markets. As pipeline infrastructure gets back to normal, we should see West Texas do the same. By the end of Q4, prices should be down sharply from post-Hurricane levels. •

San Antonio and Dallas Markets Impacted by FHR and ExxonMobil Refinery News

Flint Hills Resources shut its largest 170,000 bpd crude unit at its 300,000 bpd Corpus Christi, TX refinery for planned maintenance at the end of September, just weeks after coming back online following Hurricane Harvey. The outage lasted approximately four weeks. The timing of this turnaround was not ideal, considering the State of Texas is still recovering from the impact of Hurricane Harvey. The shutdown added further supply tightness to San Antonio, Waco, and the Dallas FTW area. To counteract this news, ExxonMobil announced on September 25th that its Baytown, Texas refinery, which feeds both Dallas and San Antonio, was operating at normal capacity. The Baytown Refinery, which produces 560,000 bpd and the nation’s 2nd largest refinery, had been shut for several weeks due to flooding caused by Harvey. Pre-Harvey refinery utilization was at 96.1% operability before dropping significantly to reach only 77.7% operability post-Harvey. Refinery utilization began its road to recovery during the weeks following the storms with operability reaching 83.2% only one week after the hurricane. •

Retail Gasoline Prices Remain Elevated in the Gulf Coast Nearly a Month after Harvey

In late August, both gasoline and diesel prices jumped sharply at the pump as Hurricane Harvey’s path hit the Corpus Christi refinery network, Houston complex, and Port Arthur/Beaumont areas causing nearly 75% of Gulf Coast refining to shut down in response. While gasoline prices have started to maneuver south, diesel prices remain elevated. • 19

PADD 4

Northern Plains

“ Harvey created a ripple effect, since supply that would usually go to Colorado was diverted to other regions to aid in the hurricane relief. “

PADD 5

West Coast, AK, & HI

Regional Views

Amy Nguyen,

Supply Optimization Supervisor See her bio, page 36

Colorado

The aftermath of catastrophic Hurricane Harvey affected more than just Texas’ oil markets. The refinery shut-downs resulting from Harvey caused gas prices to go up throughout the U.S. This included Colorado, where the average price of gasoline increased by over twenty cents. Even though Colorado receives most of its gas from refineries in Colorado and Wyoming, it was still affected by the Texas refineries. Harvey created a ripple effect, since supply that would usually go to Colorado was diverted to other regions to aid in the hurricane relief. Prices should slowly decrease as refineries in Texas come back up and product going to Colorado is no longer diverted into other regions. •

California

In September, California lawmakers approved a $1.5 billion plan for spending revenue from the Cap-and-Trade program. The Cap-and-Trade program, which began in 2013, imposes “caps” on greenhouse gas emissions and requires companies to acquire permits for each ton of carbon they release into the atmosphere. The bulk of the $1.5 billion will be divided among several different programs to replace gas and diesel burning vehicles with cleaner models.

The objective of the program is to reduce oil and pollution from transportation and make it easier for people in California to purchase an electric vehicle or trade in their car for a more fuel efficient option. This could potentially shift more demand towards electric vehicles and renewable diesel. Already in San Francisco and Oakland, city vehicles have begun using renewable diesel to eliminate climate warming emissions. Even one of the trains that runs between Oakland and Auburn now runs entirely on renewable diesel. In addition to approving the $1.5 billion spend, California also plans to increase taxes on both gas and diesel in November. The base excise tax on gasoline increases by 12 cents per gallon, while excise tax for diesel will increase by 20 cents per gallon. The purpose of the tax, however, is not to deter consumers from filling up at the pump, but rather to pay for the repairs of the state’s roads, highways, and bridges. California has gone twenty-three years without a gas tax increase and has a backlog of $130 billion in road repair and replacement projects. As we draw closer to the fall and winter, expect demand to go down but prices to rise due to the taxes. •

Pacific Northwest

Flocks of people invaded the Pacific Northwest in August to view the total solar eclipse. The eclipse was notable for being the first time in 99 years that the path crossed the entire continental United States. The path started in Oregon and millions flocked to the state to see the rare spectacle. The mass influx of people led to congested roads and highways, causing massive traffic jams. With the large increase in vehicles on the road, gas stations feared gas shortages and stockpiled extra fuel to keep up with the anticipated demand. In response, gas prices rose within the region. The price increase was actually opposite of the downward national trend during that time span. The few states that saw their averages rise were generally in the Pacific Northwest. Oregon’s average gas price went up 12 cpg while Idaho and Washington went up by 8 cpg and 5 cpg respectively. As the hordes of tourists have now left the area, prices have declined and consumption has returned to normal. • 20

Canada

Regional Views

Nate Kovacevich, Sr. Supply Manager See his bio, page 36

Enbridge Looking to Replace Line 3 Pipeline Segment into Minnesota

Calgary based Enbridge is seeking approval to replace Line 3, which was built in the 1960’s and runs from Hardisty, Alberta, through Minnesota on its way to Enbridge’s terminal in Superior, Wisconsin. The pipeline’s original capacity was 760,000 barrels per day, but due to its aging infrastructure, costs of maintaining that capacity have grown in recent years. Construction has already begun in Canada and Wisconsin, with an overall budget of $7.5 billion. The replacement will have higher crude capacity and will run along a new route in some areas in northern Minnesota. The new line will better protect the environment and allow Canadian oil companies to push more crude into northern U.S. refineries that continue to gobble up the cheaper land-locked product. •

Irving Oil Shuts Catcracker, FCC Unit Down until Early November

Irving Oil refinery was forced to shut down its 25,000-bpd catcracker at the 300,000-bpd St. John, New Brunswick, Canada refinery in early September due to an unplanned issue. The unit went down prior to a planned overhaul on Sept 11th. The FCC unit is seen resuming in early November. Local retail gasoline prices had jumped as Irving Oil had joined the arbitrage play of sending gasoline into Florida and Mexico following Hurricane Harvey. Trade sources said the refinery had sold significant volumes to export into areas impacted by the hurricanes. The unplanned refinery issue and subsequent planned shutdown could mean continued tightness and a prolonged period of higher prices in the area. •

Alternative Fuels

Renewable Fuels

Sara Bonario, Supply Director See her bio, page 36

Bipartisan Legislation Introduced to Extend & Phase-out Biodiesel Tax Credit

On July 17, Representatives Diane Black (R-TN) and Ron Kind (D-WI) introduced bipartisan legislation that would extend the biodiesel blenders’ tax credit, ultimately phasing it out over five years. The Biodiesel, Renewable Diesel, and Alternative Fuels Extension Act of 2017 (H.R. 3264) would reinstate the tax credit for all biodiesel blenders at $1 per gallon in 2017 and 2018, falling to $0.75 per gallon in 2019 and $0.50 per gallon in 2020 and 2021, and finally phasing out to zero in 2022.

reinstate this vital credit and provide five years of tax certainty, allowing businesses to plan for the eventual phase-out of the credit. The bill would keep the credit at the blender level, circumventing an effort by certain lawmakers to change the credit to a producer’s credit. Transforming the credit into a producer’s credit would have essentially created a tax on imported biodiesel and raised costs for consumers.

For over ten years, the blenders’ credit has incentivized the blending and sale of biodiesel. However, the credit’s expiration at the end of 2016 made it difficult for retailers to sell biodiesel in a cost-competitive manner relative to unblended diesel, impacting market participants’ ability to properly plan and make business decisions. H.R. 3264 would

Brad Puryear, Mansfield Energy’s General Counsel, states, “The blenders’ credit encourages fuel marketers to expand usage of biodiesel, which contributes to American energy independence, promotes cleaner energy, and supports the mission of the Renewable Fuel Standard. The blenders’ credit also results in a more competitive price of diesel fuel at the pump for all consumers. The phase-out is fiscally prudent and provides businesses with clear direction and time to adapt to changes.” •

Alternative Fuels

EPA Proposes Renewable Volume Obligations for 2018

In early July, the Environmental Protection Agency (EPA) proposed Renewable Volume Obligations (RVOs) for 2018 under the Renewable Fuel Standard (RFS). RVOs are the amount of renewable fuels required under the RFS to be blended into the nation’s fuel supply every year. The EPA also proposed RVOs for Biomass-based diesel (BBD) for 2019. EPA is again proposing to use its waiver authority to lower the volumes below their statutory levels and is setting forth volume requirements for cellulosic biofuel, advanced biofuel, and total renewable fuel that are lower than the 2017 requirements. On July 28, in Americans for Clean Energy v. EPA, a federal court struck a blow against the EPA by ruling the agency had misused its waiver authority in lowering certain fuel blending requirements under the RFS Program. The courts declared the 2016 RVOs were lowered improperly. The EPA had lowered the volumes based on a waiver authority that lets the agency adjust for an “inadequate domestic supply” of biofuels available for blending. The EPA, however, had determined inadequate domestic supply by using both supply and demand-side factors. The Court found that the demand-side factors were not relevant in determining domestic supply, stating that the EPA may not “consider the volume of renewable fuel that is available to ultimate consumers or the demand-side constraints that affect the consumption of renewable fuel by consumers.”

Volume Used to Determine the Proposed Percentage Standards 2015

2016

2017

2018

2019

Cellulosic biodiesel

MM gals

123

230

311

238

n/a

Biomass-based diesel

Bn gals

1.73

1.9

2.0.

2.1

Advanced biofuel

Bn gals

2.88

3.61

4.28

4.24

n/a

16.93

18.11

19.28

19.24

n/a

Total renewable fuels: Bn gals

Biofuel producers are supporting the court’s decision, as they have long argued that RVOs have been set too low. Certain oil industry stakeholders, however, remain concerned that RVOs are still too high. The EPA has said it is still reviewing the decision, which has created substantial uncertainty regarding the potential consequences for affected markets. Comments on the 2018 proposed RVOs were due August 31st. •

Proposed Percentage Standards 2015

2016

2017

2018

Cellulosic biodiesel

MM gals

0.069%

0.128%

0.173%

0.131%

Biomass-based diesel

Bn gals

1.490%

1.59%

1.67%

1.74%

Advanced biofuel

Bn gals

1.620%

2.01%

2.38%

2.34%

Total renewable fuels: Bn gals

9.520%

10.10%.

10.70%. 10.62%

Alternative Fuels

Natural Gas

Martin Trotter, Pricing & Structuring Analyst See his bio, page 36

Cash Prices

Natural gas cash prices opened Q3 at just $2.95/dt, nearly 15 cents lower than the opening prices of Q2. Prices bottomed out at $2.75/dt in early August before ballooning to nearly $3.15 during the third week in September due to heat and hurricane activity which drove volatility in the cash market. Cash prices continued a downward spiral to close the quarter only 3 cents above the Q3 opening mark. •

Forward Prices

Calendar year 2018 prices averaged around $3.00/dt during Q3, settling primarily between the $2.95 to $3.05 marks. After beginning the quarter low and finding a bottom around $2.90 to close July, prices peaked in late September amid hurricane conditions in the Gulf Coast and Florida regions, peaking around $3.08. Cal ’19 followed a similar trend, but failed to see midAugust gains similar to Cal ’18, as illustrated by the 12-cent operating band, nearly 6 cents tighter than its front year counterpart. The outer most years performed within an 11 cent band for the second quarter in a row, failing to break the $2.80 threshold. The beginning of the quarter saw Cal’ 21 trading flat with ’19 and ahead of ’20 before retreating at the close of summer cooling demand season. •

NG Forward Calendar Year Strip Prices

Source: New York Mercantile Exchange (NYMEX)

Alternative Fuels

Natural Gas Fundamentals

Natural Gas SUPPLY:

Appalachia Processing Key in Bolstering Production

After shale gas burst onto the scene in the Appalachian corridor, processing capacity from Kentucky to Pennsylvania has rushed to keep up. Due to vast midstream infrastructure investment to provide interstate pipes and processing facilities, capacity in the region is now 10 Bcf/day, up 800% between 2010 and 2016. The additional processing plants separate dry natural gas from plant liquids such as ethane, propane, and butane – all products are marketed separately from natural gas. Production gains followed suit, and natural gas production increased to 22 Bcf/day by May 2017, with an additional 2.5 Bcf/day increase expected over the next two years. The efficiencies of the newer processing plants are paying dividends, as midstream companies now have the ability to extract additional saleable amounts of finished product, and alter processing methods in response to economic market demands. The increased processing of NGPLs has also driven additional fractionation – a further processing of NGPLs – in the region. •

Natural Gas and NPL Production and Processing Capacity in Appalachian Region

Source: U.S. Energy Information Administration, (EIA) Natural Gas Monthly, Form EIA-757, and company public filings and press releases

DEMAND: An onslaught of hurricanes stifled demand as consecutive storms battered the Southeast throughout August and September. Harvey muted demand across Houston and South Texas, dropping about .7 bcf/day. In addition to cooler weather and power outages, intense flooding forced the closure of businesses requiring natural gas, including the typically weather-agnostic industrial sector. Collectively, East Texas and Louisiana saw a .8 bcf/day decrease due to demand disruption. Additionally, exports to Mexico fell dramatically. Nearly all the disruptions, which caused exports to fall to a three-month low, were concentrated in South Texas, with Permian and West Texas remaining relatively steady. Just days later, Irma rocked the power grid in Florida and six million utility customers lost power. Natural gas demand in the state fell nearly 40%, from 4.43 Bcf/day to 2.74 Bcf/day, and reduced demand for several weeks. •

Florida Hourly Electricity Demand, September 2015-2017

Hurricanes Reduce Nat Gas Demand

Gigawatts (previous years aligned by week number & day of week to 2017 data)

Source: U.S. Energy Information Administration (EIA), Energy Infrastructure with Real-Time Storm Information

Source: U.S. Energy Information Administration, (EIA) U.S. Electric System Operating Data

Viewpoints By Alan Apthorp, Market Intelligence Analyst, and Madi Burton, Market Intelligence Analyst

2017 Hurricane Impacts on U.S. Fuel Supplies

See their bios, page 36

Source: Energy Information Administration (EIA), Energy News Today and Oil Price Information Service (OPIS)

Leading into the 2017 hurricane season, models predicted a heavierthan-average storm season of 14-19 named storms, 11 of which were hurricanes. Even with the forewarning, no one could have predicted the devastation that occurred as a result of Hurricanes Harvey, Irma, and Maria in Q3. Cumulatively, the storms were responsible for more than 260 deaths and racked up $300 billion in damages. Beyond the loss of life and economic destruction, the storms also had an unprecedented impact on energy infrastructure in the U.S., causing shockwaves worldwide in refined product markets.

Hurricane Harvey

Hurricane Harvey began as a tropical wave, upgraded to a tropical storm on August 17, 2017. The storm travelled over the Yucatan Peninsula in Mexico as a tropical storm, and as it swirled towards the Gulf Coast many thought the worst-case scenario would be a Category 1 hurricane. Just days after these predictions, on August 24, Harvey rapidly intensified, gaining strength from warm waters in the Gulf of Mexico and reaching Category 3 status. Harvey was an extremely slow-moving system, which is why the storm was able to intensify over such a short period. The storm travelled at just 26

3-4 miles per hour, giving it ample time to grow. By August 25, the storm grew to a Category 4 storm, officially a major hurricane, before striking Rockport, Texas. The storm bounced off land out to sea, then reapproached as a tropical storm. The storm would travel out into the Gulf of Mexico one more time, strengthening slightly before making its third and final landfall in Louisiana on August 29. Harvey sat over Texas for days, dropping record levels of water. Rainfall in certain areas of Texas reached 60 inches, the most ever recorded in the continental U.S. Flooding and strong winds left significant damage. Houston, together with the rest of the Texas coastline, is home to numerous refineries. Over half of the refining capacity in the U.S. is in the Gulf Coast. When Hurricane Harvey lingered in the area, it took about 40% of the Gulf Coast refining capacity offline, equivalent to 20% of U.S. refining capacity. Outages eventually led to complications for the Colonial Pipeline, which connects refiners in the Gulf to consumers throughout the Southeast, all the way up to Lindon, New Jersey. Without supply coming from the south, the pipeline did not have enough physical product running through it to maintain scheduled flow rates, so supplies became scarce

ÂŠ 2017 Mansfield Energy Corp

Viewpoints throughout the Southeast. The pipeline was completely shut down west of Louisiana; where it remained online, supply replenishments that typically came every five days stretched to ten or more days. In conjunction with limited supplies, panic buying (which Nikki Booth discusses on page 29) caused demand to spike, further exacerbating supply. Supply situations became so tight that deliveries were being scheduled from as far north as Pennsylvania to provide fuel to the Carolinas and Georgia. The situation was extremely tight, but manageable…at least until Hurricane Irma rolled in. The situation became so dire in the U.S. that gasoline prices gained nearly 50 cents, surging to over $2.00/gal at the NYMEX level before returning to its pre-storm levels. Regulators lifted hours of service and trucking regulations, making it easier for truck drivers to drive longer to make their deliveries. Compared with other hurricanes that have made landfall in the United States since 2000, Hurricane Harvey’s impact on U.S. Gulf Coast spot gasoline prices was par with the impact from Hurricanes Katrina and Rita. In August 2005, gasoline spot prices rose nearly 30% within one trading day after the landfall of Hurricane Katrina in Louisiana. The gasoline spot price remained elevated for a second trading day before rapidly declining soon after. In September 2005, prices rose by almost 30% within three trading days after the landfall of Hurricane Rita before similarly declining. In contrast, gasoline spot prices remained stable or fell in the days after Hurricane Sandy, which hit the U.S. East Coast, and Hurricane Ike made landfall. Hurricane Harvey’s impact on gasoline prices was more gradual than the impact following Hurricanes Katrina and Rita because refineries in Houston, Texas, and Port Arthur, Texas, began going offline in the days after the hurricane’s landfall near Corpus Christi. As a result, gasoline prices rose steadily for four trading days before starting to decline.

Mansfield, noted, “For Harvey we were shipping fuel from Florida to Texas, then after Irma we were shipping from Texas to Florida.” Fuel supplies and delivery truck availability, both stretched thin by Harvey, had to be rerouted to Florida, extending supply concerns throughout the Southeast. For weeks, getting a delivery of fuel on the East Coast, as far north as Virginia, required extensive logistical coordination. Unlike Texas, which was intimately linked to most of the country’s refined product infrastructure, Florida is relatively isolated from the rest of the U.S. Nearly all of its fuel – 97% – comes from barge deliveries from other markets. Florida’s ports quickly came back online after the storm with little damage, allowing resupply to begin quickly. Although all of Florida’s fuel terminals were temporarily offline for the storm, they came back online very quickly after Irma passed. Contrast this with Texas, which affected most of the U.S. supply chain.

Harvey also drove WTI-Brent spreads to 2-year highs. The storm had a significant effect on refineries, but did not take much crude production offline. For that reason, more crude was put into inventory in the U.S. than normal, pushing the American oil index, West Texas Intermediate crude, lower.

Hurricane Irma

Hurricane Irma, which hit the U.S. as a Category 4 storm in southern Florida, came right as markets were beginning to recover from Harvey. After the destruction from Harvey, Florida residents paid close attention to Irma’s development. As the storm powered over the Caribbean islands as a Category 5 storm, many left the state. While Harvey moved slowly and dumped rain in Texas, Irma moved quickly, bringing quick, destructive winds. Fuel markets were well prepared for Irma, delivering above-average volumes of fuel via barge. The constraint in Florida was not supply, but rather transportation, demonstrating the importance of having both reliable supply and means of getting that supply. Panic buying led to above average demand, which meant more trucks going to local terminals, creating lines. Longer lines caused extended delivery times and delays, which created more panic buying – a vicious circle. Either Harvey or Irma, in isolation, would have been manageable on its own. However, as Andy Milton, Senior Vice President of Supply at 27

Radar imagery of Hurricane Maria from Puerto Rico, shortly before it stopped transmitting data.

Hurricane Maria

Hurricane Maria, known for causing severe devastation in Puerto Rico, led to an exports disruption while it was in the Gulf, ultimately hitting the coast of North Carolina September 26. While Hurricane Maria did not have as significant impact on fueling infrastructure, the disruption continued the volatility in fueling statistics. Exports were severely hampered during September as ports were opened and closed. •

Viewpoints

National Truck Driver Appreciation Week

By Dan Kemeny, Sr. Logistics Analyst

The appreciation for drivers shouldn’t end at the conclusion of the week. As Red Classic President Ron Drogan states, “Everyday should be truck driver appreciation day.” In a statement directed to drivers, Dan Firth expressed, “Know that you have the respect and admiration of the entire tank truck community this week and every week throughout the year.”

During Driver Appreciation Week, countless numbers of drivers descended on Texas and Florida to help support the increased fuel and freight demand caused by hurricanes Harvey and Irma. Harvey alone is estimated to have affected 10% of US Trucking, through impacts on productivity, increased demand and congestion. The sentiments expressed online associated with the week of honoring drivers were almost a foretelling of those efforts. In a YouTube video posted by Overdrive Magazine thanking drivers, two particular segments are applicable. The first states, “Thank you for spending weeks away from your family to supply our needs,” while the next says, “Thank you for hauling vital goods into disaster zones.”

September 10-16th marked National Truck Driver Appreciation Week for 2017. While many annual celebrations and observances are merely one day, an entire week to celebrate the life blood of the transportation industry seems fitting considering the dependency the industry places on drivers. Leaders from across the industry echoed these sentiments leading up to and throughout the week:

In another inspirational video titled “Imagine,” the creator dives deep into this subject, with drivers moving “into the crisis instead of away. Delivering lifesaving supplies…and when the unimaginable happens, we pick up the pieces and carry them home. Then we turn our trucks around, to rebuild, to raise us up to a future only we can carry.” National Truck Driver Appreciation week is an opportunity for the industry as a whole to bring attention to professional drivers. Each day, these 3.5 million men and women are tasked with safely delivering 70% of all freight tonnage in the US. They are truly tasked with keeping America’s economy running, even in the face of disaster. Borrowing from the question used to conclude the Imagine video, “Have you thanked a trucker today?” •

• NTTC President Dan Firth -“The tank truck industry plays a critical role in the North American economy and our segment’s performance is largely due to the professionalism of our drivers. Our industry has many important stakeholders, but none are as mission-critical as our drivers. Without the contributions of this essential group, our industry and the overall economy would come to a screeching halt.” • Kevin Burch, co-chair of Trucking Moves America Forward, Chairman of the American Trucking Associations and President of Jet Express “We celebrate them all year, but this week provides an important opportunity to say thank you to our country’s professional truck drivers.” • Chris Spear, ATA President and CEO – “This week was created to commemorate and support the industry professionals who work daily to deliver America’s goods.” The ATA began celebrating National Truck Driver Appreciation Week in 1988 to honor the men and women who work hard to deliver goods both safely and on time each and every day. Examples of how different entities showed their appreciation this year range from safety awards, cash, gifts, vacation days, meals, windshield washing, health checks or even a simple cup of coffee. Trucking Moves America Forward (TMAF) is thanking drivers by putting up billboards of drivers with their families throughout the country with a message of #ThankATrucker. 28

Dan Kemeny Senior LTL Logistics Manager Dan Kemeny leads Mansfield’s LTL department in Denver. His responsibilities include overseeing the logistics and billing for all of Mansfield’s fleet fueling and tank wagon deliveries. Prior to his current role, he spent time handling Mansfield’s FTL and DEF transportation and regional operations.

Viewpoints By Nikki Booth, Carrier Relations Manager

Perfect Storm of Panic Buying

History has shown that natural disasters can occur at any time with devastating effects. Recent destruction from both Hurricane Harvey in Texas and Louisiana and Hurricane Irma in Florida caused widespread outages in the Southeast. Not only was fuel supply disrupted, but the entire supply chain across the U.S. felt the impact. Panic buying lay at the heart of the disruption, and was immediately felt in the fuel industry.

customer were subsequently delayed, slowing business operations across a spectrum of industries. On top of that, if a customer was panic buying and ordered fuel when their tank was still full, that fuel truck had to be diverted elsewhere, causing yet more delivery delays for those in need.

Panic buying is the action of buying large quantities of a particular product or commodity due to sudden fears of a forthcoming shortage or price increase. The public's panic buying of goods (i.e. water, bread, milk) is a result of fear of an upcoming supply scarcity. As Hurricane Harvey approached the U.S., consumers remembering the Colonial Pipeline shortage from 2016 panicked and began “stocking-up.” For example, I ventured to my local grocery store outside of Atlanta to get some soda the weekend Harvey hit Houston, and the store was completely out of bottled water – 800 miles away from the eye of the storm! From that moment, I knew there would be significant demand from consumers in the fuel business. That’s exactly what happened. Consumers began topping off the gas tanks in their cars and companies throughout the country began topping off their bulk tanks. Transportation companies critical to the distribution of goods in the U.S. began panic buying, often resulting in over ordering. Though their intentions were good, the impact of panic buying ultimately harmed the U.S. transportation network by driving up fuel prices and limiting supplies. Managing the logistics surrounding a product with immense supply constraints and higher than average demand (quadruple normal demand, in this case) becomes extremely challenging. Panic buying during Hurricanes Harvey and Irma created a perfect storm in U.S. logistics. Many terminals and refineries in Houston ceased operations to prevent damage as Harvey passed. These closures (about a fifth of U.S. production overall) triggered a short-term fuel shortage in the U.S. across the southeast, from Texas to the Carolinas. The shortage forced fuel carriers to wait in longer lines at the terminals (often waiting several hours) after driving hours in some cases to find a terminal with product available. Extended wait times meant drivers, who normally deliver 4-5 loads per shift, were only able to make 1-2 deliveries in the same timeframe, severely weakening carrier capacity. Deliveries to the 29

Panic buying during a supply shortage magnifies the repercussions of limited product availability, bringing the entire U.S. supply chain to a crawl. Weeks later, the aftermath of both hurricanes was still being felt in the Southeast. FEMA has the National Disaster Recovery Framework in place to guide effective recovery support to disaster impacted areas in the U.S. Still, if individuals and companies have not established their own continuity plan to prepare for natural disasters, panic buying will continue, exacerbating shortages when they arise. •

Nikki A. Booth Carrier Relations Manager Nikki manages the strategic direction of Mansfield’s full truck load network across the U.S. and Canada. Her team works closely with fuel transport companies to handle freight procurement, address logistical concerns, and identify cost-saving solutions. Nikki has been with Mansfield since 2007 and has over 14 years of experience in supply chain management, with 11 years focused on energy transportation and logistics.

Viewpoints By Tom Krizmanich, Director, Business Development, Mansfield Power & Gas

Natural Gas Procurement in the Age of Choice

Last quarter, we looked at the history of the natural gas market, from the time natural gas was first made useful all the way to the current regulatory system we use today. This quarter, we’ll look at how natural gas procurement works and important factors to weigh when choosing a supplier.

Making the Switch

Your first step is to verify you are eligible for natural gas supply through a third-party supplier. Some utilities may only offer this service to larger commercial or industrial accounts, while certain states allow third-party supply down to the residential level. Natural gas procurement involves checking the natural gas prices you currently pay against those of another retail supplier or default service through your utility. Unlike fuel and other products you buy, you likely already have natural gas delivery established for your location, which makes the basic process relatively simple. The utility that owns the pipelines delivering natural gas to your consumption points does not change, meaning that switching providers is not a logistical concern. The local utility will continue to provide distribution services, make repairs to its delivery system, and respond to emergencies. Because utilities hold a monopoly on gas distribution, they are heavily regulated by local, state, and federal governments. 30

How to Choose a Supplier

Since delivery of the natural gas is not a concern – you have no choice which utility services your locations – suppliers differentiate themselves through many different services, payment plans, and programs. These make up the decision criterion you must use when choosing a gas supplier. Supply decisions are based on price, services, and incentives. Many utilities participating in a customer choice program offer a default commodity rate for natural gas provided by the utility; however, this rate often changes monthly and may not be the most competitive offer. Any customer, regardless of size, needs to understand the factors that could affect the decision to purchase third-party natural gas supply. These factors include potential savings, the terms of service, and the pricing options, including month-to-month variable rates or fixed rates for longer terms.

Viewpoints Choosing a supplier is a decision based on numerous factors:

Specialty

Does the supplier specialize in your segment? Some suppliers focus on residential customers, while others choose to specialize in servicing commercial and industrial customers. Having a supplier that understands your unique needs is important, especially for industries with high natural gas demand, such as manufacturing.

Billing

Does the supplier offer consolidated billing for all locations? Each invoice processed has a cost – validation, payment, and reporting all take time and resources. Consolidating invoices to a single statement can save you time and effort.

Data Reporting

How easy does the supplier make it to track costs and consumption? Finding ways to reduce energy costs is crucial to companies, and the only way to get there is by understanding how much energy you use. In today’s data-driven world, most supply teams don’t have a choice – they have to prove cost savings with their new supplier.

Another crucial consideration is the pricing structure you’ll use. If you prefer budget certainty, a fixed price option is ideal – you’ll pay one rate for the entire term of the deal (usually one to three years, though some contracts extend longer). These plans often come with volume requirements, so monthly payments tend to be very stable. Other consumers fear prices falling during the term of the deal, and opt instead for a market index rate. This price could track NYMEX Henry Hub contracts, the nationally traded natural gas contract, or could be based on a local pricing index. National deals are more transparent and easily tracked, while local indexes more closely align with local supply dynamics, making them slightly less risky for suppliers and therefore cheaper.

Choosing Your Supply

Even after you’ve chosen your supplier, you need to decide which type of supply you need, and how it will be priced. Suppliers offer a wide variety of supply and pricing options, to meet the plethora of diverse customer needs. One important consideration is whether your company will buy firm or interruptible supply. Firm supply, as its name suggests, is guaranteed supply, always available when you need it. Firm supply comes with fixed pipeline capacity, so absent a force majeure situation like a pipeline outage, your supply is certain. Firm supply comes with a price, however, and if you’re on a variable price plan this strategy could cost you significantly in the winter. Firm supply is the standard option for most consumers.

Some customers choose to blend fixed and variable prices. These blends can take different forms. In some instances, a fixed volume is locked at a fixed price, and any remaining consumption is charged at an index rate. Others choose to blend at a fixed ratio, with half of their volume billed at a fixed rate and half billed on index, meaning they always pay halfway between the market and their fixed price, for better or worse. Still more opt for a cap or a collar, allowing for some variability in prices until the market hits a certain price threshold, above which prices are fixed. Whatever your price risk preferences, there’s a pricing strategy available for you. •

Some purchasers choose interruptible supply, which is the first type of supply to get cutoff during cold weather when customers have high gas demand. Interruptible supply is cheaper than firm service, and can be a good option for companies with their own gas storage options or back-up generators. 31

Thomas Krizmanich Director Business Development Power and Natural Gas Tom Krizmanich is responsible for the development and management of Mansfield’s power and gas product offerings. He is dedicated to creating customized solutions to reduce the cost of natural gas and power to customers, and provides additional support to the daily operations pertaining to the sales and marketing functions for the retail power and natural gas team.

Viewpoints By Nancy Yamaguchi, Ph.D., Contributing Editor

Wending the Way to Oil Market Balance Global Supply-Demand Balance Proves Elusive

At this point in time last year, many forecasters were giving up on the idea of seeing $50/b crude in the fourth quarter of 2016. It was widely thought that the global crude market would achieve a better supplydemand balance by the end of 2016, but the year brought many changes, both on the supply side and on the demand side. Now, a year later, the market discussion is an echo of what it was before: The oil market will achieve a better supply-demand balance by the 4th Quarter, and crude prices will be at $50/b. This time, however, the fundamentals appear to be more solid, and a closer balance appears to be approaching. In 2016, it took extraordinary events to spark an oil price rally, and it took very little to quench it. This year, patience may be paying off. There are many moving pieces in the balance equation. Yet two key regions continue to dominate the supply-demand story: OPEC and the United States. The goal of OPEC’s price war was to drive out the higher cost producers, exemplified by U.S. producers in shale plays. Many U.S. producers were forced to exit the field. But the ones remaining achieved amazing gains in drilling efficiency, so that each time OPEC actions created a price rally, it seemed that U.S. producers gained. This briefing traces the market developments leading to the delayed, but now approaching, balance.

OPEC’s Efforts to Fix the Global Oil Imbalance Ending the Oil Price War

The oil price war shut in a large percentage of the U.S. shale industry which had been expanding rapidly. The number of active oil and gas rigs in the United States had soared to over 1900 by late 2014. After Saudi Arabia boosted production and prices fell, the U.S. active rig count began to fall, dropping below 1000 in April 2015. Figure 1 displays the U.S. active rig count, as published by Baker Hughes. Drilling rigs continued to exit the field, until the rig count hit bottom at 404 in May 2016. As the figure shows, however, the rig count has been increasing since then, and it stood at 944 as of the second week of September 2017. This was slightly off-peak because of Hurricane Harvey. U.S. crude production hit a peak of 9627 kbpd in April 2015. It fell to 8567 kbpd in September 2016. The OPEC production cuts strengthened prices, as planned, but U.S. producers capitalized on this. The latest data shows that U.S. production surpassed 9500 kbpd just before Hurricane Harvey hit. The U.S. Energy Information Administration (EIA) forecasts that U.S. crude production will average 9250 kbpd in 2017, and that it will rise to 9840 kbpd in 2018 — a new production record.

Viewpoints

Rig Count & Weekly Rig Change

possible now to assess how the production cut agreement fared during the first six months of 2017, which was the original period of the agreement, and how production stood in the first part of the third quarter. The starting baseline for the eleven OPEC participants was 30,254 kbpd. Iran negotiated an increase of 90 kbpd as a condition of its participation. The others agreed to the cuts listed. Saudi Arabia’s pledged cut was the largest at 486 kbpd. Iraq followed with 210 kbpd, and the UAE pledged the third-largest cut at 139 kbpd. The total planned cut was 1256 kbpd in January 2017.

Source: Baker Hughes

According to OPEC, January production for the eleven participants was 29,890 kbpd. This was 364 kbpd below what had been pledged. At the country level, Algeria, Ecuador, Gabon, Iraq, Kuwait, the UAE, and Venezuela were not yet in compliance. However, Angola, Iran, and Saudi Arabia produced less than their pledged amounts, bringing the total even lower than planned.

Negotiating the OPEC and Non-OPEC production cut agreement was a major diplomatic effort, which occupied members for most of 2016. Once the agreement was finalized, the focus shifted to the matter of compliance. Skeptics expected the producers to “cheat” on the agreement, but once again, OPEC surprised the market. Compliance rates have been high, particularly when only the participating countries are counted.

Adding Libya’s and Nigeria’s production brought the January total to 32,141 kbpd. In November 2016, when OPEC made its agreement, production was 33,306 kbpd. Using these two figures, OPEC cut 1165 kbpd between November 2016 and January 2017. Because the pledged adjustment was 1256 kbpd, as noted in the table, the cuts in January 2017 amounted to 92.8% compliance.

The table on the next page presents a detailed look at OPEC’s production agreement, based on the officially adopted baseline production levels. OPEC has recently released its September Monthly Oil Market Report (MOMR) which includes production levels in August 2017. This makes it

As the table also shows, however, the high compliance rate was made possible mainly because Saudi Arabia went further with its cuts than required. Moreover, Iran unexpectedly contributed to the cuts by not raising its production by the 90 kbpd it had negotiated.

Compliance with the Production Cuts, January–August 2017

Viewpoints Other participants achieved higher rates of compliance than the market had predicted. In June 2017, the OPEC participants had cut production to 29,857 kbpd, which was 397 kbpd below the target. Compliance rates of 90% or so were considered very high, but the rates of compliance are even more extraordinary when the calculations focus only on the original eleven OPEC members committing to the cuts. The OPEC 11 are achieving compliance rates of over 100%. In August, the compliance rate was 101.3%.

OPEC Production Cut Agreement and Complainace Rates August 2017 (kbpd) Member

January 2017 Planned

January 2017 Actual

June 2017 Actual

July 2017 Actual

August 2017 Actual

August Compliance %

Algeria

1,039

1,045

1,060

1,061

1,065

97.6%

Angola

1,673

1,651

1,668

1,638

1,646

101.6%

Ecuador

522

527

537

97.2%

Gabon

193

199

197

206

173

111.6%

Iran

3,797

3,775

3,790

3,830

3,828

99.2%

Iraq

4,351

4,476

4,502

4,471

4,448

97.8%

Kuwait

2,707

2,718

2,709

2,702

100.2%

618

614

616

100.3%

10,508

9,946

9,950

10,032

10,022

104.8%

UAE

2,874

2,931

2,898

2,921

2,901

99.1%

Venezuela

1,972

2,004

1,938

1,950

1,918

102.8%

Participating OPEC 11 30,254

29,890

29,857

29,962

29,856

101.3%

Qatar Saudi Arabia

Non-Participating OPEC (Exempted because of internal unrest)

Libya

675

825

1,003

890

Nigeria

1,576

1,733

1,723

1,861

Libya + Nigeria

2,521

2,558

2,726

2,751

32,141

32,415

32,141

32,607

OPEC 11+ Libya + Nigeria

Source: OPEC secondary sources. Historical data excludes Equatorial Guinea, which joined OPEC mid-2017

The Six-Month Production Cut is Extended by Nine Months, Additional Extension Possible

A key goal of the cuts was to reduce global oil inventory levels to within their five-year average levels, but stockpile levels remained stubbornly high. In fact, the first quarter of 2017 brought an increase of 41 million barrels of oil to stocks held by members of the Organization for Economic Co-operation and Development (OECD). In May 2017, the OPEC and Non-OPEC participants extended the production cut agreement by nine months, rather than the six months initially set out in the original agreement. This will now carry the production cuts through the first quarter of 2018. Although this was yet another noteworthy example of consensus-building within the diverse grouping of participants, the market reaction was one of disappointment. Oil prices promptly declined, and they have not regained and consistently occupied the territory above $50/b. The supply glut is forecast to extend into 2018, with some analysts expecting the entire year to be one of oversupply and weak prices. OPEC is in the process of discussing the continuation of the agreement for another three months. 34

ÂŠ 2017 Mansfield Energy Corp

Viewpoints

The Balance Is Closer Now

The global market has remained in oversupply for far longer than originally foretold. When OPEC first announced that it would extend its cut agreement by nine months, some expressed dissatisfaction, opining that OPEC should have deepened the cuts. Realistically, however, the production cut agreement, the high rates of compliance, and the extension of the cuts were all extraordinary achievements. They did not permanently propel crude prices to $55/b-$60/b, but arguably, the OPEC-NOPEC agreement was the only thing that kept oil prices from collapsing to the $35-$40/b level. The effectiveness of the OPEC-NOPEC cuts has been undermined chiefly by the expansion of production in other areas, notably the United States and the non-participating OPEC countries Libya and Nigeria.

of the responsibility for rebalancing the market. The cuts they have made supported higher prices, but the higher prices in turn have stimulated production increases in other countries. The OPEC-NOPEC producers are understandably reluctant to see this continue. As noted, the original OPEC 11 are achieving compliance rates of over 101%. If they needed to bring all of OPEC into compliance, they would have to boost their compliance rate to around 110%. As noted, OECD stocks of crude rose in the first quarter of 2017. This was caused mainly because of relentless stock additions in the U.S., along with inventory additions in OECD Europe. Yet as the following figure illustrates, the second quarter brought a significant reversal.

OECD Quarterly Crude Inventory Change

Between January and August, Libya’s crude output rose from 675 kbpd to 890 kbpd, an increase of 215 kbpd. Nigeria increased its crude production from 1576 kbpd in January to 1861 kbpd in August, an increase of 285 kbpd. During the January-August period of 2017, U.S. crude production climbed by 277. These three countries, therefore, added approximately 777 kbpd of oil to the market during the JanuaryAugust period. This has severely undercut the effectiveness of the OPECNOPEC agreement. The agreement had a target of cutting output by 1,256 kbpd. Libya, Nigeria, and the U.S. have negated approximately 62% of this cut. As the following figure illustrates, OPEC crude production rose by around 0.5 mmbpd in the third quarter of 2016 and in the fourth quarter. The production cut agreement led to a drop of nearly 1.0 mmbpd in the first quarter of 2017. U.S. production, in contrast, jumped by 378 kbpd in the first quarter. OPEC production rose by 164 kbpd in the second quarter of 2017. U.S. production rose by 268 kbpd. During July and August, OPEC production expanded by 500 kbpd, but U.S. production crept up by only 77 kbpd. Although U.S. production is forecast to increase in 2018, the expansion of OPEC output and the weak price environment did seem to flatten the growth in U.S. output. Some U.S. production is profitable at $45/b, but not all. The OPEC-NOPEC cut participants remain of the opinion that market rebalancing is underway, and that only patience will be required. These countries believe that they already have accepted a large enough share

Quarterly Change in Crude Production

Source: International Energy Association (IEA)

In the first quarter of 2017, crude stocks in the OECD Americas swelled by 0.57 mmbbls. OECD Europe added 0.18 mmbbls to inventory. Stocks fell slightly in OECD Asia and Oceania. However, in the second quarter, crude stocks in the OECD Americas were drawn down by 0.48 mmbbls. OECD Europe stocks remained roughly flat (a small build of 0.01 mmbbls). Stocks in OECD Asia and Oceania were drawn down by 0.09 mmbbls. The total drop was 0.56 mmbbls. Global oil supply and demand is a complex system of equations. Some variables work to reinforce one another, while other variables work to confound one another. As of the time of this report in the third quarter of 2017, there are good reasons to believe that supply and demand are coming into a better balance. First, OPEC achieved an extension to its production cut agreement. Second, production is flattening or declining in other areas. Third, global demand growth has been revised up. And fourth, oil inventories are being drawn down at last. The path has been a long and winding one, but the fourth quarter does appear to be leading to a closer supply-demand balance. •

Dr. Nancy Yamaguchi Contributing Editor Nancy is Contributing Editor for Mansfield Energy's FUELSNews 360° quarterly. She works closely with the Mansfield team to cover a wide range of topics that influence North American fuel markets. Dr. Yamaguchi has over 20 years of industry experience, and has spoken at numerous industry conferences and events nationwide. Source: Organization of the Petroleum Exporting Countries (OPEC), and International Energy Association (IEA)

Mansfield’s National Supply Team Contributors Mansfield’s supply team brings unique experience and industry expertise to the table. From contract pricing and hedging to trading of fuel, renewables, and alternatives such as CNG and LNG, the Mansfield supply team covers the gamut of knowledge that is required to manage today’s complex national fuel supply chain. Although they work as a national team, each member’s regional focus enables Mansfield to deliver geographic-based supply solutions by more efficiently managing market-specific refining, shipping, and terminal/assets.

Andy Milton

Martin Trotter

Andy heads the supply group for Mansfield. During his tenure, the company has grown from 1.3 billion gallons to over 2.5 billion gallons per year. His industry experience spans all aspects of the fuel supply business from truck dispatch, analytics, and index pricing to hedging and bulk purchasing. Andy’s expertise in purchasing via pipeline, vessel, and the coordination via futures and options for hedging purchases enables him to successfully lead a team of experienced and motivated supply personnel at Mansfield. His team handles a wide geographic area of all 50 states and Canada, including all gasoline products, ULSD, kerosene, heating oil, biodiesel, ethanol, and natural gas. •

Martin is responsible for handling natural gas and electricity pricing, deal flow, and analytics for Mansfield’s Power & Gas division. Before his current role, he served as the Sales Analytics Supervisor and held various roles on the Risk & Analysis Team. •

Senior VP of Supply & Distribution

Pricing & Structuring Analyst

Sara Bonario Supply Director

Sara manages the team responsible for procurement and optimization of all refined fuels for Mansfield’s Great Lakes, Central, and Western regions. She is also responsible for nationwide purchasing, hedging, and distribution of renewable fuels. Sara has an extensive supply and trading background, with over 25 years of experience in the oil industry. •

Nate Kovacevich Senior Supply Manager

Before joining the company, Nate worked as a Senior Trader, where his responsibilities included managing refined product and renewable fuels procurement, handling all hedging-related activities, and providing risk management tools and strategies. He performed commodity research and analysis for customers with agricultural- and petroleum-related risk, devised and implemented risk management programs, and executed futures and option orders on all the major exchanges. •

Alan Apthorp

Market Intelligence Analyst

Alan is responsible for content editing, research, and data analysis and visualization at Mansfield, and is an editor for FUELSNews Daily and FUELSNews 360°. He also works with Mansfield’s product marketing team to analyze trends to generate valuable insight for Mansfield’s customers. Alan joined Mansfield in 2015, and has served both as a customer relationship manager and as a supply scheduler with Mansfield’s Power & Gas division. •

Chris Carter Supply Manager

Chris is responsible for refined product purchases, including contracts, day deals, and rack purchases in the Northeastern United States. His responsibilities also include supply contracts and current bids. Chris joined Mansfield in 2009 as a Supply Optimization Analyst. •

Madi Burton

Market Intelligence Analyst

Madi is responsible for industry-specific market research and analysis, generating relevant fueling insights based on developing trends. She also works with the Marketing team to create customized solution recommendations for key customers. Madi joined Mansfield in 2016, and has worked closely with teams in business development, operations, and supply. Madi earned her BSBA in Marketing from Liberty University. •

Amy Nguyen

Supply Optimization Supervisor

Amy is responsible for both refined product purchasing for contract customers and bulk pipeline movements within California, Oregon, Washington, Idaho, Nevada, and Arizona. She is also responsible for scheduling, hedging, supply bids, and other optimization efforts throughout the West Coast. Amy joined Mansfield in 2014 as an optimization analyst. •

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