FUELSNews 360° - Q4 2017

M A R K E T

N E W S

&

4th QUARTER

I N F O R M A T I O N

Table of Contents FUELSNews 360° Quarterly Report Q4 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.

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Executive Summary

Regional Views continued

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Overview

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October 2017 through December 2017

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Economy & Demand

12

Fundamentals

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Inventories

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Production and Refining Capacity

25 26

28 Mansfield’s Brad Puryear Interviews EPA Administrator Scott Pruitt

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Trump Administration Says Court Cannot Suspend Pipeline Decision

31

Natural Gas Martin Trotter

Strides in Fuel Efficiency Using Existing Technology

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What is the ELD Mandate?

33

Why Are More Diesel Tanks Gelling This Winter?

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Josh Wakeman

PADD 3, Gulf Coast

Sara Bonario

By Nikki Booth

By Clint Hamlin & Alan Apthorp

PADD 1A &1B Northeast, Central Atlantic

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Renewable Fuels

By Dan Kemeny

Regional Views

PADD 1C, Lower Atlantic

Nate Kovacevich

Viewpoints 31

Commerce Department Finds in Favor of Domestic Biodiesel Producers

20

Canada

Alternative Fuels 26

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

Amy Nguyen

Legal

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PADD 2, Midwest

Nate Kovacevich

WTI and Brent Crudes: Trans-Atlantic Cousins Re-examine their Relationship

By Dr. Nancy Yamaguchi

Chris Carter

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Chris Carter

Uniting Natural Gas and Fuel Purchasing Strategies

By Tom Krizmanich

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© 2018 Mansfield Energy Corp

FUELSNews 360˚ Supply Team

Q4 2017 Executive Summary The final quarter of 2017 ended with a roar of enthusiasm. Markets

Together, the mass of bullish headlines, related to both supply

are broadly headed towards supply/demand balance in 2018, and

and demand, sent prices catapulting above $60/bbl by year-end,

inventories are returning to historical levels. Lower inventories and

breaking through the previous $54 ceiling on prices.

lack of replacement supplies have contributed to less slack in the supply chain, increasing volatility in future price outlooks. Overall, WTI crude rose a full $10 throughout the quarter, beginning near $50/bbl and ending slightly above $60/bbl.

Rising crude prices were outpaced by NYMEX diesel prices, which soared throughout the quarter in response to strong agricultural demand and cold temperatures. Where prices had previously capped out around $1.75, Q4 saw diesel prices surpass $2/gal.

The end of 2017 ushered in rising geopolitical and production

Hurricane Harvey was also a major contributor – refining outages

uncertainty. Iraq, Iran, Saudi Arabia and Libya all struggled with

during Harvey caused suppliers to deplete existing diesel stocks,

instability, pulling prices higher throughout the quarter. Headlines of

leading to seasonally low inventory levels in Q4.

coming conflicts came and went with no realized impact, yet markets are still priced in higher risk of outages. In recent years, prices have not reacted strongly to supply risks because inventories were so high.

Suppliers no longer have the luxury of high inventories to meet

Regionally, consumers in the Midwest suffered normal seasonal price increases resulting from strong agricultural demand combined with the timing of refinery maintenance season. The combination of high demand and low supply caused local prices

demand during outages, leading to higher prices.

to rise more than fifteen cents above the NYMEX. Because the

Against a backdrop of geopolitical risk, other fuel infrastructure

Midwest has become an important refining hub in the U.S., the

disruptions affected fuel prices. In the U.S., leaks on the Keystone

impacts of reduced supply were felt in the East Coast and Gulf

Pipeline caused a shutdown, propping up U.S. WTI crude prices. In

area as well. Without large Chicago fuel shipments flowing to the

Europe, the Forties Pipelines was taken offline for repair, pushing

Northeast, the region had to rely on European supply and Gulf

international Brent crude prices higher.

Coast production.

Continued OPEC restraint remains a major contributor to rising

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

prices. OPEC’s compliance with their production deal exceeded

natural gas procurement, sharing how fuel purchasers and

100% at times, keeping supplies off the market. In November, the

natural gas purchasers can learn from each other to promote

group signed a deal to extend cuts into 2018, which was not a

savings and streamline their supply chain. Make sure to check out

surprise to the market but has helped keep prices trending higher.

his article on page 40.

While supplies have been tightening, global oil demand is on the

We hope you enjoy this quarter’s edition of FN360°. If you have

rise. The global economy is firing on all cylinders, with all major

any questions, or would like to request additional copies, email

economies growing in unison. With U.S. unemployment at the

us at fuelsnews@mansfieldoil.com.

lowest level in decades and global growth set to reach 3.9% in 2018, global oil demand could surpass 100 million barrels per day.

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© 2018 Mansfield Energy Corp

Overview October 2017 through December 2017 WTI Crude Oil Prices

Source: New York Mercantile Exchange (NYMEX)

The final quarter of 2017 has passed, and with it came a significant rise in oil prices. Since late 2016, many analysts have noted that OPEC’s cuts would not have a notable impact on oil stocks and prices until the end of the year; those predictions have proven correct.

The beginning of Q4 began without significant fanfare – a few international events caused small market volatility, but prices remained in the $45-52 range. As October continued, however, a shift in market sentiment occurred. High OPEC compliance and separatist movements by the Iraqi Kurds caused prices to surge in late October, and on October 30 crude oil surpassed $54/bbl, its highest point since July 2015.

Since surpassing $54/bbl, crude prices have not looked back. Throughout the quarter, on-going bullish headlines, backed by supportive fundamentals, helped keep prices trending higher.

Saudi Arabia and Iran clashed in early November, and some speculators worried a Middle Eastern war was imminent. Fortunately, that conflict calmed, but shortly thereafter a leak in the Keystone Pipeline helped send prices even higher.

The Keystone Pipeline delivers crude oil from Canada to major refinery areas such as Chicago and the Gulf Coast. Even more importantly, it connects directly to Cushing, OK, the delivery point for the WTI crude index. Outages in this market have an outsized impact on WTI crude oil prices, causing prices to surge to just shy of $60/bbl in late November.

Just before the quarter ended, the Forties Pipeline, a pipeline transporting crude oil from the North Sea to the United Kingdom, went offline. North 6

Sea oil is a major contributor to the basket of crude sources making up Brent Blend crude oil, so the outages kept prices elevated in December.

All these events occurred against an on-going backdrop of speculation regarding OPEC’s actions. Leading up to the OPEC meeting in late November, market consensus held that the group would extend their cuts through the end of 2018 without changing production limits. A few speculated the group might deepen cuts in 2018 to further boost prices, while others worried Russia would not agree to any extension.

On November 30, OPEC officially extended their cuts through the end of 2018 at existing levels, in line with market expectations.

The overall bullish trends of the quarter helped boost quarterly average prices to the highest levels since Q2 2015, shortly after prices began their freefall. Relative to last quarter, Q4 crude prices rose nearly 15%.

This quarter was a break-out period for prices, which otherwise had trended between $45-52 for over a year. Compared to Q4 last year, Q4 2017 was 12% higher.

Changes in underlying crude prices had a notable impact on fuel prices throughout Q4. On the heels of rising crude prices, NYMEX HO (diesel) prices rose 17.5% during the quarter. Beginning the quarter near $1.75, diesel prices raced higher, dragging the oil complex with it.

Agricultural season, mixed with a colder-than-average winter, helped keep diesel prices strong throughout the quarter. By the time the quarter closed, prices had reached $2.07, remaining above the $2/gal level for the last week of December.

© 2018 Mansfield Energy Corp

Overview

Quarterly WTI Crude Prices

Source: Energy Information Administration (EIA)

Gasoline sputtered in Q4, struggling to keep up with a bullish crude and diesel market. In comparison to diesel’s 17.5% growth, gasoline only managed to pick up 15.7%.

Gasoline began Q4 with prices still struggling after Hurricane Harvey sent prices soaring above $2.00 in September. Opening the quarter at just $1.55, gasoline had a long way to go to keep up with diesel’s $1.80 position. The 25-cent spread between gasoline and diesel ebbed and flowed throughout the quarter, and by the end of the quarter gasoline remained 27 cents behind diesel, trading at $1.80.

Gasoline Rack-to-Retail Spread 2017

Source: Energy Information Administration (EIA)

Diesel Rack-to-Retail Spread 2017

At the retail level, rack-to-retail spreads, the difference between wholesale prices (rack) and prices at a gas station (retail), generally showed lower volatility as the year ended. Retail prices often move slower than wholesale prices, causing spreads to widen as wholesale prices fall and narrow when they rise. For instance, between July 2, 2017 and Dec 31, 2017, wholesale diesel prices rose by 35%, while retail diesel prices grew just 20%.

Tracking rack-to-retail spreads is important for fleets buying either retail or wholesale fuel. The larger the spread, the greater the benefit of switching to a wholesale index by installing a bulk tank. Of course, narrow spreads do not mean there’s no benefit to switching – even at its lowest point, retail prices were still over 15 cents higher than wholesale prices.

Source: Energy Information Administration (EIA)

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Diesel rack-to-retail spreads were suppressed in the second half of 2017 thanks to rising wholesale prices. While the front half of the year saw spreads reach as high as 40 cents, the average in the back half was closer to 25 cents. Gasoline rack-to-retail spreads dropped to just five cents during Hurricane Harvey, but have trended between 20-30 cents during Q4. •

© 2018 Mansfield Energy Corp

Overview

Summary, Fourth Quarter, 2017 $2.0755 $1.7992

$60.42

24,719

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

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© 2018 Mansfield Energy Corp

IIIII II

Economy & Demand

IIII II I

U.S. GDP Grew 2.6% in Q4 IIIII II

As oil prices have been rising, the U.S. and global economy have been growing as well. U.S. GDP grew 2.6% in Q4, slower than the previous two quarters but still a strong rate of growth. Overall, the economy averaged 2.3% growth in 2017 – below the target rate of 3% but significantly better than 1.5% growth in 2016.

IIII II I

Economic growth was supported by robust consumer spending, which grew by 3.8% in the fourth quarter.

Consumers had a lot to be thankful for during the holiday season, with wage growth and tax cuts helping to boost available cash for spending.

Source U.S. Department of Commerce

Consumer Sentiment Index Peaked in October

The firming fundamentals were not enough to sure up consumer sentiment, however. After rising in October to its highest level since 2004, the Consumer Sentiment Index (CSI) receded in November and December, reflecting uncertainty about the Trump tax cuts as well as a reaction to higher prices over the holidays. Despite falling, the CSI is at record highs, thanks to strong global growth boosting economic expectations.

Source: University of Michigan

U.S. Unemployment Rate Continued Lower Another factor keeping consumers optimistic this year has been falling unemployment rates, which are quite low currently. Throughout Q4, unemployment in the U.S. has been 4.1%, falling from 4.3% in Q3.

Source: Bureau of Labor Statistics

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Falling unemployment rates have contributed to a boost in incomes. Additional income, along with fewer people seeking employment, leads consumers to feel optimistic about the future. Overall strong data regarding consumer spending, unemployment, and GDP will help to keep America growing in 2018.

Economy & Demand On the international front, growth is still robust, though the World Bank warns that the world growth may have peaked. For the first time since the Great Recession, analysts believe the economy to be growing at full capacity. Every major economy is growing in unison, unleashing a wave of new jobs and rising fortunes. The World Bank warns, though, that “potential growth” (how fast the economy could grow at full capacity) is slowing, as it becomes more difficult for countries to invest in near-term growth opportunities.

Another major institution, the International Monetary Fund (IMF), believes global growth reached 3.7% in 2017, and forecasts 3.9% growth worldwide in 2018 and 2019. If those strong growth rates are achieved, global demand for oil could grow rapidly, surpassing 100 million barrels per day (MMbpd).

Strong economic growth in the U.S. and abroad will spur more fuel demand. In the U.S., demand for diesel and other types of fuel have risen, despite a slowdown in gasoline demand.

Continued fuel demand growth will support higher oil prices globally.

Gasoline demand tends to fall as oil prices rise.

Even when the economy is strong, higher gasoline prices lead more consumers to consider ride-sharing or public transit alternatives. On the other hand, diesel fuel is a necessary product to transport goods around the country, so diesel demand rises in conjunction with economic growth.

Looking towards 2018 and 2019, all fuel products are expected to show rising demand.

Peaking at 20.5 MMbpd in 2017, total liquid fuels growth is expected to reach 20.8 MMbpd in 2018, and could surpass 21 MMbpd in 2019.

U.S. Liquid Fuels Demand

Source: Energy Information Administration (EIA)

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© 2018 Mansfield Energy Corp

Economy & Demand Demand for diesel fuel in 2017 was roughly in line with historical levels, though Q4 saw demand rise slightly above average. Notably, demand in late-December tends to fall dramatically, but the slowdown was less notable in 2017. As predicted by some analysts, demand did slowdown in the few months after Hurricane Harvey, but overall the trend in Q4 was towards higher demand.

U.S. Diesel Demand Tracked Near Average

Gasoline demand has been robust, perhaps in part due to gas prices remaining a bargain relative to oil and diesel prices. As usual, the holiday season gave gasoline demand a boost in December, but the overall trend has been lower as consumers hunker inside through the winter. As we head into a new year, expect the opposite to occur: more consumers will head outside as the year progresses, peaking once again next summer. •

U.S. Gasoline Demand was Above-average

Source: Energy Information Administration (EIA)

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Source: Energy Information Administration (EIA)

Fundamentals Given the radical shift in the pricing environment during the final quarter of 2017, changes in oil fundamentals should be expected. Indeed, from supply to demand to technical indicators, the fundamentals in Q4 indicated that the “new normal” of sub-$55 crude prices may be old news.

At a high level, supply and demand appear to be roughly balanced. The EIA currently forecasts supply to slightly outstrip demand in 2018, though with a net draw in the first quarter of the year. The balancing of supply and demand has resulted in overall less slack in the supply chain – any threat of supply disruptions will likely have a larger impact on fuel prices in 2018.

World Supply/Demand Balance

Source: Energy Information Administration (EIA)

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© 2018 Mansfield Energy Corp

Fundamentals

Crude Inventories Return to 5-Yr Range

Inventories Return to Historical Levels

After a rocky start at the beginning of Q4, U.S. crude inventories remained relatively flat in October and early November, unable to break out of the 450-460 million-barrel (MMbbl) range. By midNovember, the decline had resumed with winter heating demands putting excess pressure on crude stocks. Throughout Q4, stocks fell roughly 38 MMbbls, or an average of almost 3 MMbbls per week.

Inventories ended the quarter with 425 MMbbls.

Source: Energy Information Administration (EIA)

Diesel Inventories Return to 5-Yr Range

Despite the notable draws, crude inventories are well above 20122015 average levels, the period before OPEC flooded the market with crude oil. During that time, the average crude oil level was approximately 365 MMbbls, though for December the average was 370 MMbbls. Even based on a higher December average, inventories remain more than 55 million barrels above historical averages.

For the second half of 2017, a time when inventories traditionally fall, crude draws have averaged roughly 3 MMbbls per week. If the same withdrawal rate continues into 2018, inventories will need about five months to return to historical average. Of course, crude inventories have not risen in the first quarter of the year since 2003, and have only done so five times in the past 35 years, so a return to historical averages remains unlikely in the first half of 2018.

Source: Energy Information Administration (EIA)

Diesel inventories are much closer to their historical average.

At the beginning of 2017, inventories were 33 MMbbls above their 2012-2015 average; at the end of Q4, inventories were just 8 MMbbls above average. Diesel inventories on December 30 held 122 MMbbls, 17 MMbbls (14%) below Q4 2016 levels.

Gasoline Inventories Return to 5-Yr Range

One notable trend this year was the decline of diesel inventories during summer, which is highly unusual for diesel fuel. Diesel typically builds during the summer as school buses are off the road and many businesses are slowed by summer breaks. Over the past ten years, the average build during Q3 has been 9.5 MMbbls; this summer, inventories fell by 4.8 MMbbls.

The decline in diesel inventories has been attributable to diesel exports and strong diesel demand. Strong diesel exports helped diesel inventories fall even faster, as declining output from OPEC cleared the way for American crude and refined products to enter the global arena. Diesel demand has been relatively high as well, though not significantly higher than most years. In Q4, diesel demand has averaged 3.94 MMbbpd, compared to 3.81 MMbpd. •

Source: Energy Information Administration (EIA)

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Fundamentals

U.S. Production Fills the Global Supply Void

Despite some setbacks, U.S. production also celebrated reaching record highs.

Hurricanes Harvey and Nate caused two major downward spikes in production, as rigs in the Gulf Coast were taken out of commission. Despite the outages, though, production in November surpassed the previous record for highest monthly output.

By December, production had peaked at 9.79 MMbpd. Looking towards 2018, analysts expect U.S. production to hit 10 MMbpd, and by 2019 U.S. production could be as high as 11 MMbpd.

In November 2016, OPEC and non-OPEC countries agreed to cut production by a total of 1.2 MMbpd.

Throughout the year, compliance with the cuts has been surprisingly high – in the last few months of 2017, OPEC’s deal compliance was over 100% due to Saudi efforts and disruptions in Venezuela. Because of OPEC’s cuts, crude inventories in the U.S. have trended downward throughout the year.

According to the Federal Reserve Bank of Dallas, U.S. production has a break-even level between $46 and $55. Production in the Permian, the fastest growing area for production in the U.S., only needs prices at $46 to be profitable; non-shale production on average requires prices above $53, though some wells would still be unprofitable if prices rose to $100/bbl.

While OPEC’s production cuts have been a major factor spurring oil prices higher, production in the U.S. is quickly filling the void.

Still, OPEC’s cuts are just part of the global supply picture. While OPEC cut production by 1.2 MMbpd in 2017, U.S. producers rapidly brought new production online. Beginning the year at 8.77 MMbpd, the U.S. grew production to 9.79 MMbpd at the end of the year – nearly completely offsetting OPEC’s cuts.

The most astounding part of the U.S.' renaissance of production is the price environment in which it is taking place. When the previous record was set in June 2015, it came on the heels of prices above $100/bbl – exploration and drilling commissioned at the peak in 2014 came online by June 2015. The latest boom in prices has occurred with prices generally around $50.

Given the large variance in oil field break-evens, markets can expect production to continue rising in response to higher prices. Each new price threshold makes new fields profitable, allowing the U.S. production to continue its explosive growth over the next few years. •

Crack Spreads Were Above Average in Q4

Crack Spreads Decline

Source: Energy Information Administration (EIA)

U.S. Refinery Utilization Rises

During Q4, 3:2:1 crack spreads trended below the previous quarter, though overall higher than historical averages. The 3:2:1 crack spread approximates a refiner’s margins from turning three barrels of crude into two barrels of gasoline and one barrel of diesel.

During Q3, Hurricane Harvey disrupted 20% of U.S. refining capacity, causing spreads to point sharply higher. In Q4, spreads averaged $19.15, about $1.30/bbl lower than the previous quarter but above historical averages of roughly $18/bbl.

The fact that Q4 saw such high crack spreads is a bit surprising – spreads tend to be highest in Q2 and Q3, thanks to summer gasoline requirements boosting gasoline prices. Spreads in Q2 were $17.19, almost $2/bbl (or 5 cents per gallon) below Q4.

Source: Energy Information Administration (EIA)

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© 2018 Mansfield Energy Corp

Legal Mansfield’s Brad Puryear Interviews EPA Administrator Scott Pruitt

In November, SIGMA, the Society of Independent Gasoline Marketers of America, held its annual conference, attracting approximately eight hundred fuel industry participants. One of the highlights of the event was the opening interview between Mansfield’s General Counsel, Brad Puryear, and the Administrator of the Environmental Protection Agency, Scott Pruitt.

The significance of the EPA administrator attending a conference of petroleum marketers was not missed by attendees. According to Puryear, “Pruitt’s attendance showed his desire to engage with private enterprise and individuals to collectively improve the EPA’s environmental stewardship.”

Pruitt underscored the importance of directly communicating with, and seeking input from, all constituents, whether they be individual property owners, the business community or other concerned citizens.

Pruitt stated that the role of the EPA should not be expanded beyond that specifically authorized by Congress. Puryear added, “The Administrator’s commitment to adhering to the rule of law provides needed certainty for business contemplating investment/expansion in all facets of the petroleum industry.”

One of the conversation’s most important take-aways was Pruitt’s commitment to following the rule of law. Over the years, the EPA’s scope has grown expansively and many observers have commented that in recent years the EPA’s reach had been significantly expanded beyond Congressional approval.

The Administrator also addressed his concern that the EPA’s response time to permitting requirements for many projects had devolved into multi-year waiting periods, sometimes up to a decade and longer. Pruitt committed that his team would strive to respond to requests within six months. •

Trump Administration Says Court Cannot Suspend Pipeline Decision On October 10, Department of Justice (DOJ) attorneys argued to dismiss two lawsuits challenging Trump’s presidential permit for construction of the Keystone XL Pipeline. Conservation groups and Native American organizations filed the suits, contending that the three-year old environmental review of the project was inadequate and, therefore, the permit should be revoked.

The Trump Administration countered that the courts cannot interfere because President Trump has constitutional authority over matters of foreign affairs and national security. “The remedy that plaintiffs seek, an injunction against the presidential permit, is not available because such an order would impermissibly infringe on the president’s authority,” said a DOJ attorney.

TransCanada’s Keystone XL Pipeline would transport Canadian crude oil from the Alberta oil sands through Montana and South Dakota to Nebraska. President Obama rejected the permit to construct the pipeline, but President Trump issued the permit last March. • 16

© 2018 Mansfield Energy Corp

Legal

Commerce Department Finds in Favor of Domestic Biodiesel Producers In late August, the Department of Commerce (DOC) formally published its preliminary determinations in the countervailing duty case brought by U.S. biodiesel producers against Argentina and Indonesia. Countervailing duty laws allow U.S. businesses and workers to seek relief from market distortion caused by subsidized imports.

The DOC will now use the preliminary rates to collect cash deposits from importers of Indonesian and Argentinian biodiesel while the federal government considers final duty rates. A final decision must be made by the DOC regarding whether biodiesel from Argentina and Indonesia is being dumped in the United States at below fair-market value.

The DOC set preliminary subsidy rates ranging from 50.29 - 64.17% for Argentina and 41.06 - 68.28% for Indonesia. The agency also found that critical circumstances in Argentina will allow for the collection of duties during a retroactive 90-day period for certain biodiesel imports.

Interested parties will file briefs on issues arising from the agency's preliminary determinations, and DOC will hold a hearing upon request from such parties. Final DOC determinations are likely to be issued in early 2018. •

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PADD 1

East Coast PADD1A,1B

Regional Views Josh Wakeman, Supply Manager See his bio, page 42

Northeast, Central Atlantic

“Diesel inventory levels in

the Northeast are relatively low compared to last year, meaning a cold spike could shorten supply and add strength to the market. “

Quarterly Summary

I’m bullish in the Northeast region on both diesel and gasoline during Q1 2018. Heating oil demand during winter is uncertain, given the debate on how cold the winter months will be. Diesel inventory levels in the Northeast are relatively low compared to last year, meaning a cold spike could shorten supply and add strength to the market.

Prices in the northeast face a number of threats in addition to cold weather. First, given reduced supply coming from Chicago due to Midwest refinery outages, any refinery issues in the northeast could stretch supply thin. Additionally, scheduled imports are lower than is normal for this time of year. Given these trends, upside risks to Northeast basis prices appears more likely than downside movements. •

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© 2018 Mansfield Energy Corp

Regional Views

Laurel Pipeline Debate Continues

Politicians continue debating the benefits and detriments of reversing the Laurel Pipeline. Pittsburgh is the current cross roads between the Midwest and East Coast refiners, but would become a Midwest refiner stronghold if the pipeline is reversed back to Altoona, and potentially to Harrisburg in the longer term.

PADD 1A New England Diesel Stocks

Opponents to the reversal argue that Midwest refiners may not be able to keep up with Pittsburgh demand, causing tight supply and higher prices. They also worry that Pennsylvania may lose jobs as local refineries are driven out of business by competitors further west.

Proponents of the reversal say it would bring more affordable fuel and competition to Pennsylvania markets, lowering the price to consumers. They also argue that government intervention to prevent the reversal may produce an unsustainable artificial market, whereas allowing the reversal supports a more sustainable, market-driven approach. •

Source: Energy Information Administration (EIA)

Northeast Area Refiner Struggles

There are some concerns in the Northeast that refiners may be experiencing cash flow issues. The crash in oil prices has changed some economics for the region, which has led to financial issues. Credit companies have already started downgrading one refiner and have a negative outlook in their forecast. The future is unsure for Northeast refineries in 2018. •

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PADD 1

East Coast PADD1C

Lower Atlantic

PADD 3 Gulf Coast

Regional Views

Chris Carter, Supply Manager See his bio, page 42

Chris’ Concepts

For the Southeast and Gulf Coast, I am overall bullish for Q1 2018. With the possibility of a colder winter in the northern U.S. due to La Nina, as well as challenges facing New York refineries, I believe product will continue to be pulled up from the Gulf Coast. I predict Colonial Line Space values, the market-traded cost to ship on the Colonial Pipeline, for both gasoline and ULSD to stay strong during January and February as NY Harbor prices remain elevated vis-à-vis Gulf Coast prices. Additionally, strong exports reduce the supply of products available to ship north, adding pressure to the region. •

“ With the possibility of a

colder winter in the northern U.S. due to La Nina, as well as challenges facing New York refineries, I believe product will continue to be pulled up from the Gulf Coast. “

Colonial Pipeline Announces Expansion Project

The Colonial Pipeline Company announced in October an expansion project for both their gasoline pipeline (Line 1) and their diesel line (Line 2). Both Colonial lines run from Houston, TX to Greensboro, NC, where additional lines pick up the fuel and flow to Linden, NJ.

Colonial’s plans will add an additional 50,000 barrels-per-day of capacity for each line. Line 1 currently transports 1.37 million barrels of gasoline daily, while Line 2 carries 1.1 million of diesel.

The expansion is currently expected to be completed by the end of Q1 2019. • 20

© 2018 Mansfield Energy Corp

Regional Views

Virginia Still Fighting for Line 25

As mentioned in last quarter’s publication, Colonial remains committed to discontinuing service on Line 25 in Virginia in September 2018.

Following a meeting between the Virginia Petroleum Convenience and Grocery Association and Colonial Pipeline, several congressmen drafted a letter to the Federal Energy Regulatory Commission requesting the commission look for additional options and provide support for upgrades to the pipeline segment.

Large Retailers Enter Unbranded Rack Sales

Two large fuel retailers decided to make the move into the wholesale fuel business along the East Coast. Racetrac will market unbranded rack supply under the name Metroplex Energy.

Metroplex historically focused on bulk fuel for RaceTrac and RaceWay stores.

Metroplex has a strong supply footprint in Florida due to having five vessels chartered. They can also supply fuel via rail, Colonial, Plantation, Explorer, Magellan South and Teppco pipelines.

Colonial is closing the section due to concerns regarding its safety and reliability. Closure of Line 25 will increase the need for over-the-road fuel shipments. One estimate shows a need for an additional 170 tanker trips per day from outside markets to provide sufficient fuel supply. If that estimate is correct, fuel costs could rise by 4-6 cents per gallon.

BP has already notified customers that their fuel supply will be relocated. Fuel suppliers who typically pull from Montvale will need to move supply to Roanoke. BP also communicated that additional changes are very possible. Terminals in Richmond, Knoxville and Greensboro will need to backfill the loss of 34,000 barrels per day transported on Line 25. •

Colonial Pipeline Values

During the fourth quarter of 2017, Line 2 for Colonial finally turned positive.

Shippers who find themselves with excess shipping capacity often re-sell it on the market, sometimes at a loss. For most of 2017, Line 2 capacity traded at or below shipping costs, meaning there was an abundance of capacity available and few wanted to fill it. Generally, negative Line 2 space values indicate that the spread between the Gulf Coast and NY Harbor is not wide enough to incentivize shipping product up north.

During mid-October, as Gulf Coast ULSD basis values began falling, values for ULSD space began trading positive for the remainder of 2017. The premium for space traded as high as .0235 during November as the spread between Gulf Coast and New York Harbor continued to widen. Values for Calendar Year 2018 Line 2 are running flat at -25 pts. •

Q4 2017 Colonial Line Space Values

Pilot Flying J has also moved into the wholesale rack business across the country. Pilot started by posting prices in select markets, and added markets over time. In November, Pilot announced the opening of its new office in Houston, TX, designated for Oil and Trading, as well as the hiring of 15 employees to operate their trading office. The trading shop will help optimize Pilot’s truck stop demand, as well as look for arbitrage opportunities to market. •

Source: Energy Information Administration (EIA)

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PADD 2 Midwest

Regional Views

Nate Kovacevich, Sr. Supply Manager See his bio, page 42

Midwest Refinery Issues Heading into Winter

Midwest fuel supply will be affected this winter by repair concerns at ExxonMobil’s Joliet, IL refinery. The refinery had been down for a month for maintenance, but by the end of November run rates had improved to 80-85% capacity. Within two weeks, however, repair became necessary once again, and now ExxonMobil must once again choose whether to reduce run rates for repairs.

“ Due to refinery outages,

both Chicago and Group 3 ULSD basis values rose slightly, going against normal seasonal trends.“

In other refinery news, HollyFrontier’s Tulsa refinery had a hiccup in early December at one of its reformers.

The unit is expected to be down for a week or so, though output losses aren’t expected to be significant.

Due to refinery outages, both Chicago and Group 3 ULSD basis values rose slightly, going against normal seasonal trends. Based on current refining crack spreads, refiners are well incentivized to continue to produce, despite historical trends hinting at fading demand. •

PADD 2 Midwest Refinery Inputs

Source: Oil Price Information Service (OPIS)

Crude Imports into the Midwest Continue to Rise

Crude oil imports into the Midwest surpassed imports into the Gulf Coast in August. If you look back at 2005, the difference between PADD 2 (Midwest) and PADD 3 (Gulf Coast) was almost 5 million barrels per day. Today, the influx of U.S. shale growth in North Dakota and Texas are satisfying Gulf Coast refining needs. Additionally, widening spreads between Canadian crude oil and U.S. crude blends have made it more economic to import from Canada into the Midwest.

Monthly Midwest and Gulf Coast Crude Oil Imports

In 2005, total crude imports were 10.1 million barrels, which fell to 7.9 million b/d in 2016. Imports will likely drop even further in 2017.

Midwest refining capacity has expanded in recent years as cheap Canadian crude has incentivized new refining activity. From 2005 to 2016, Midwest refining capacity increased by 370,000 b/d to 3.9 million b/d. As of September 2017, total operable capacity sits at 4.01 million b/d.

Source: Energy Information Administration (EIA), Petroleum Monthly Supply

As long as Canadian crude remains so cheap, further expansion in the Northern tier refineries will continue. Gasoline and diesel fuel produced in the Midwest will be pushed south and east, negating the needs for barrels to be shipped up from the Gulf Coast.

The result will be more export opportunities for Gulf Coast refiners and more Midwest fuel being used around the country. • 22

© 2018 Mansfield Energy Corp

PADD 4

Northern Plains

PADD 5

West Coast, AK, & HI

Amy Nguyen, Supply Optimization Supervisor See her bio, page 42

West Outlook

The West Coast and Rocky Mountain regions saw prices rise across the board, driven higher by local tax increases, strong demand, and some refinery concerns. While some of the bullish factors will remain for the long-term, others are beginning to wind down, which should bring some relief to consumers on the western side of the country. Falling winter gasoline demand should help lower prices at the pump relative to national averages, and more refineries coming back online will add supply to the market.

Overall, I expect prices to decrease somewhat for western fuel prices, though in areas like California, the declines may be less pronounced. •

Q4 2017 West Coast Diesel Basis

“ While some of the bullish factors will remain for the long-term, others are beginning to wind down, which should bring some relief to consumers on the western side of the country. “

Source: Energy Information Administration (EIA)

California Fuel Tax

In addition to the negative feedback from consumers on S.B. 1, several truckload carriers are negotiating with shippers to add new fuel surcharges and raise rates to haul freight through California. A tax increase of 20 cents per gallon will cause a sharp increase in carriers’ overall costs, with estimates placing the additional cost at roughly 6-7 cents per mile.

California’s experienced a sizable tax increase this quarter, effective November 1. The tax increase, passed as part of Senate Bill 1 (S.B. 1), raised gasoline taxes by 12 cents and diesel by 20 cents. The additional revenue will be used to repair California roads and bridges over the next ten years.

During Q4 2017, California had the highest gas prices in the country. Only part of this was caused by the tax increase; high travel demand also contributed. As the holidays pass, I believe that local gasoline and diesel prices will begin declining relative to national averages; however, they likely will not decrease enough to reach prices prior to the tax increase. •

The bill will also raise motor vehicle registration fees at the beginning of 2018 and is projected to boost state and local road maintenance budgets by $5 billion annually. Although the purpose of the bill is to benefit drivers by improving roads and driving conditions, the law has faced opposition from numerous groups, including consumers and politicians. Opponents of the new tax have launched a petition to add a measure in the November 2018 election that would repeal the recent tax increases and require future gasoline and diesel taxes be approved by the voters.

Supporters of the tax increase, on the other hand, are prepared to defend the bill against public attack, arguing that the road systems in California have been neglected for decades. No changes should be expected anytime soon. Opponents of the tax increase have until May of next year to acquire the needed signatures. After that, no votes will be cast until the November 2018 ballot, at which point drivers will have grown accustomed to the higher price.

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© 2018 Mansfield Energy Corp

Regional Views

Pacific Northwest Refinery Concerns

This quarter consisted of multiple issues with the Andeavor and Shell refineries in Anacortes, Washington. Andeavor’s refinery was forced to cut capacity by half after a failed restart following a breakdown in late October. Shell’s Anacortes refinery also experienced restart issues after undergoing extended overhauls during the quarter, forcing Shell to shut down the refinery multiple times. These issues, along with the low refinery utilization in the region, led to increased fuel prices during the fourth quarter. Markets expect the refinery issues to be resolved soon, so expect fuel prices to slowly decline in the next quarter •

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Rocky Mountain Demand Increases

Gasoline and diesel prices were significantly higher during this quarter relative to a year ago, especially during late November and early December. Despite relatively stable supply, demand fluctuations have driven prices higher. Historically, gasoline demand declines during the winter; however, demand has remained steady this year. I expect prices to go down as winter conditions begin to deter driving, decreasing demand and following the historical trend. •

© 2018 Mansfield Energy Corp

Canada “ The pipeline expansion

project was approved by the federal government a year ago, and Kinder has begun construction on a terminal in Burnaby which doesn’t require a permit. “

Regional Views

Nate Kovacevich, Sr. Supply Manager See his bio, page 42

National Energy Board Allows Trans Mountain Pipeline to Begin Work

Canada’s National Energy Board announced this quarter that Kinder Morgan could proceed with construction of its $7.4 billion Trans Mountain pipeline expansion without having to comply with certain bylaws from the city of Burnaby, British Columbia. The project will expand an existing 1,150 kilometer pipeline between Edmonton and Burnaby.

The move by the NEB allows Kinder Morgan to begin work at its temporary site near Westridge Marine. The pipeline expansion project was approved by the federal government a year ago, and Kinder has begun construction on a terminal in Burnaby which doesn’t require a permit. Kinder Morgan is already months behind on the pipeline project, so they are eager to move the project along.

Two sections of the City of Burnaby’s bylaws require the company to have preliminary plans and tree cutting permits approved by the city prior to starting any construction efforts. With the NEB’s decision, the company can begin work such as tree removal and construction on larger storage tanks. The City of Burnaby will likely seek legal action and ask the Federal Court to appeal the energy regulator’s decision. •

Keystone Spill in South Dakota Shuts Pipeline for Nearly Two Weeks

In mid-November, part of TransCanada’s Keystone pipeline was shut down following a leak of 5,000 barrels of crude oil (or 210,000 gallons) in Marshall County, South Dakota. The pipeline feeds roughly 590,000 barrels of crude oil per day from Alberta, Canada to Cushing, Oklahoma and to Wood River, Illinois.

The timing of the spill was not ideal. TransCanada has been trying to push forward the controversial Keystone XL line to expand the pipeline. Although President Donald Trump approved the project federally, a state-level approval was still required for the pipeline to proceed. Despite the spill, approval was granted, though with some new requirements that could add further delays to the project.

On November 27, after two weeks of repairs, the Federal Pipeline and Hazardous Materials Administration reviewed and approved the pipeline for activity. In the two weeks after the spill, more than 44,000 gallons of oil were recovered at the site. •

Alternative Fuels

Renewable Fuels It’s Complicated

Sara Bonario, Supply Director See her bio, page 42

The relationship between the Renewable Fuel Standard (RFS) and Renewable Identification Numbers (RINs) has always been complicated. The past six months has been no exception as interested parties square off.

• Corn States and Oil & Gas States

The biofuels industry produces more volume than is used in the U.S. The EPA had considered reducing RVOs under the RFS, which would have caused crop prices to continue their downward turn. However, a court ruling this fall prevented the EPA from considering demand when setting RVO levels.

Corn Price Received by Farmers – Iowa

• Integrated refiners and Merchant Refiners • Biofuel Producers and Biofuel Blenders A quick look at these competing interests and why it matters is worthwhile.

Corn Belt lawmakers have pressured President Trump and his administration to support renewable fuels as he promised to do while campaigning in these Midwest states. Farm income generated from corn and soybeans has decreased since 2012 when a widespread drought pushed crop prices higher. Farmers needed a stable revenue source, and biofuels have traditionally been the answer.

Source: Iowa Ag News – Monthly Prices. USDA – National Agricultural Statistics Service – Upper Midwest Regional Field Office (November 30, 2017)

$$ RINs RFS RVO’s $$

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Alternative Fuels

Millions of Dollars Buying RINs in 2016

Source: Turner, Mason & Company

Texas Senator Ted Cruz has proposed a ten-cent cap on the price of RINs to aid merchant refiners. “Renewable fuel industry sources have rejected any proposal to cap RIN prices, saying that rising credit prices are designed to drive investment in additional blending capacity and increase the amount of renewables in the transportation fuel mix.”

Emily Skor, CEO of ethanol industry group Growth Energy, last week said that if merchant refiners' "heartache" is about RIN prices, then the best solution would be to produce E15 (gasoline with 15% ethanol) with a Reid Vapor Pressure (RVP) waiver permitting the nationwide sale of the blend yearround.

Iowa’s Senators Chuck Grassley and Joni Ernst convinced the Trump administration and the head of the Environmental Protection Agency (EPA), Scott Pruitt, not to reduce the volume requirements for biodiesel for 2018 and 2019 under the RFS. This was a big win for Iowa, which leads the nation in corn growth and ethanol production, with 39% (953 million bushels) of corn grown in Iowa going to create nearly 30% of all American ethanol.

U.S. Corn Utilization

A year-round, nationwide waiver to allow E15 would facilitate more blending of ethanol, generating more RINs and lowering ethanol RINs prices without a legislated cap. The 10ct cap proposed in a 10% ethanol blend of gasoline would only be ‘a tenth of a penny per gallon and would not motivate people to build additional blending infrastructure,’ according to Monte Shaw, Executive Director of Renewable Fuels Association.

A final divide between these competing interest groups is the Point of Obligation under the RFS. This debate has existed for some time but gained momentum during the Trump presidency when Carl Icahn was appointed as a special advisor to the President. Icahn has been an outspoken advocate for moving the point of obligation from the refiners and importers of fuel to the blenders.

On November 10, 2016, the EPA denied requests from petitioners to initiate a rulemaking to change the point of obligation for compliance under the Renewable Fuel Standards (RFS) program. An appeal process was initiated with public comments received through February 2017. The EPA made an official final ruling in late November this year denying the petitions to move the point of obligation. Jeff Barber from OPIS commented: “The EPA ruling states that they found such a change would ‘unnecessarily increase’ the complexity and ‘undermine the success’ of the RFS.” In its 84-page rationale for denying the petitions, EPA was unequivocal, saying [the] record before it does not indicate that ‘a change in the point of obligation would result in net overall benefits to the program.

Note: Marketing year 2017/18 is projected. Source: USDA, Worl Agricultural Outlook Board, WASDE.

Senators from states with a heavy refining presence such as Texas, Oklahoma and Pennsylvania have been less than pleased with the EPA’s decision. They believe the obligation to purchase RINs to meet mandated levels as part of the RFS is creating too large a financial burden on refiners and will cause them to close their doors. Known as merchant refiners, petroleum refiners who do not have the infrastructure to blend their own products and generate RINs must purchase RINs in the market. The figure above depicts various merchant refiners’ 2016 RIN expense as reported in their annual statements.

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Biofuel producers and blenders alike are optimistic that the Tax Extender Act of 2017 introduced by U.S. Senate Finance Committee Chairman and other Senate Republicans will be passed by Congress in January 2018. The legislation will retroactively reinstate the $1/gal federal biomass-based diesel blender’s tax credit for 2017 and extend it through 2018. It is common practice in the industry to share the tax credit between the producer of the biofuel and the blender evenly. Blenders are incentivized to create higher biofuel blends to capture more tax credits, generating more RINs and reducing the cost for refiners. At last, something all parties – Corn Belt and refining state, integrated and merchant refiner, and biofuel producers and blenders – can agree to be happy about. •

© 2018 Mansfield Energy Corp

Alternative Fuels

Natural Gas

Martin Trotter, Pricing & Structuring Analyst See his bio, page 42

Pipeline Expansions Feed More Gas To New England Markets

In a year notable for vacated FERC seats, demand exports, and countless halted and abandoned infrastructure projects, the Northeast has closed the year with a couple of small victories allowing incremental gas supply to flow from the Marcellus Shale region just in time for winter.

After the confirmation of two new FERC commissioners in August, early October saw the greenlight to Williams’s Transco New York Bay Expansion. The pipeline adds to existing capacity flowing to National Grid, the largest regional gas distributor. A series of improved compressors and new segments allow for an additional 115 mmcf/d at various existing interconnects into the region. The additional firm transport capacity is already fully subscribed, all of which has been allocated to National Grid in a long term binding contract.

Enbridge’s Atlantic Bridge Project

Just four weeks later, Enbridge passed a portion of its Atlantic Bridge Project. The project extends the Algonquin Gas Transmission (AGT) and MNP with incremental gas on both existing and new points on both pipes, extending up into the Maritimes. The initial release, which put into service 40mmcf/d, is expected to provide relief to AGT, which has run near capacity for most of the winter. Future capacity is expected to come into service towards the end of 2018. •

DEMAND:

If You Build It, They Will Come

U.S. liquified natural gas export capacity continues rising, with additional infrastructure supporting new export activity. Located in the Gulf Coast, Sabine Pass completed its fourth liquefaction unit in August, boosting U.S. liquefaction capacity to 2.8 Bcf/d. In September, actual exports averaged about 1.9 BCF/d, with utilization capacity creeping towards 80% into October and November. A fifth liquefaction unit is already under construction at Sabine Pass, which could to push export capacity to 3.5 Bcf/day, not counting a sixth unit already permitted.

In addition to Sabine, five additional LNG focused projects are underway in the U.S. Cove Point in Maryland is over 95% complete with exports beginning as the year ends. Freeport, Cameron, and Corpus Christi LNG are all located in the Gulf Coast region with start dates in November 2018 through 2019.

Lastly, Elba LNG off the coast of Georgia, consisting of ten smaller units, expects to be in service by May 2019. While the Sabine Pass has proven to be a key source point for exports to Asia, delays in the Panama Canal expansion and an ongoing disagreement between the Port Canal Authority have limited LNG tankers passing through the canal to one per day. Because travel through the Canal cuts eleven days off travel times to Asia, LNG producers argue stifled passage could limit international sales. • 28

© 2018 Mansfield Energy Corp.

Alternative Fuels

Natural Gas Fundamentals

Natural Gas

U.S. Liquified Natural Gas Export Capacity

U.S. Liquified Natural Gas Exports and Export Capacity (Jan 2016 – Nov 2017)

(Jan 2016 – Nov 2017)

Source: Energy Information Administration (EIA)

Source: Energy Information Administration (EIA)

Cash Prices

GDD Natural Gas Cash Prices – Henry Hub

Cash prices opened the final quarter of 2017 slightly below Q3’s average level and saw some fluctuation in October. Prices fell below $2.73 in the first week before exceeding $3.00 a week later. MidNovember saw prices rise to their highest point in Q4 at $3.18.

Cash strength didn’t show any staying power this season, as warm December weather led prices to dip below October valuations, leading to the quarter’s $2.62 low. Weather models predicting colder weather and greater demand into 2018 indicate that cash prices may bounce in the New Year. •

Forward Prices

Calendar Year ‘18 opened the quarter just south of $3.05 and peaked above $3.10 in mid-October. Gains were not substantiated, however, and prices for the approaching calendar year ebbed and flowed to close injection season. The decline continued into December, trading between $3.00 and finding a low for the quarter at $2.615 in the days before Christmas. Cal ’19 operated within a 19-cent band for the period, with lows around $2.75 and highs failing to break the $2.93 threshold.

Outer years 2020-21 mirrored the trends of ’19 for the better part of the quarter, and traded neck and neck through the first week in December.

By late December, Calendar Year 2021 prices began to trade at a premium to the preceding three years. • 29

© 2018 Mansfield Energy Corp

Source: Energy Information Administration (EIA)

Natural Gas Forward Cal Strips

Source: Energy Information Administration (EIA)

Alternative Fuels

Natural Gas Fundamentals

STORAGE:

The end of October—and the unofficial natural gas injection season—saw inventories close at 3,874 BCF, closing the season just shy of the previous five-year average and nearly 5% lower than the record setting end last October, which closed at 3,977 Bcf. November, typically a neutral month in terms of injection and withdrawal, saw a net withdrawal of 82 Bcf, a first since the Polar Vortex of 2014 when inventories fell by twice that amount during the same time period.

Relatively high injection levels entering April 2017 helped quell seasonal injections, and despite the partial reintroduction of Aliso Canyon storage capacity, net injections for the period failed to return to their previous high. While coal prices have played a role in driving down natural gas usage for power generation, which would have typically led to storage withdrawals, the net effect of trade demand driven by increased recent exports and flat import demand have balanced storage levels. •

Monthly U.S. Natural Gas Supply and Disposition (Jan 2016 – Aug 2017)

Lower 48 States End of Refill Season Inventories

Source: Energy Information Administration (EIA)

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Source: Energy Information Administration (EIA)

Viewpoints

By Dan Kemeny, Senior Logistics Manager, LTL

Strides in Fuel Efficiency Using Existing Technology

America achieved the same efficiency, they would collectively save 9.7 billion gallons of fuel, $24.3 billion dollars and remove 98 million tons of CO2 from the environment each year.

As alternative fuel and electric vehicles storm onto the market, the most measurable reductions in fuel demand in the U.S. have been from improving vehicle efficiency. “Run on Less,” a cross-country roadshow designed to demonstrate fuel efficiency best practices, recently concluded a three month study tracking fuel usage and the reductions associated with using various technologies currently available. The results were quite impressive, with the average fuel usage across all trucks for the entire testing period exceeding ten miles per gallon.

A continued focus on fuel efficiency will drive the transportation market forward. According to the Office of Energy Efficiency & Renewable Energy, commercial trucks account for nearly 80% of the goods transported in the United States. While they make up just 4% of the vehicles on the road, they use approximately 20% of the fuel.

Fuel efficiencies can be realized using a variety of different technologies currently on the market. Those include cruise control, automated transmissions, 6x2 axle configurations, specially designed tires, aerodynamic truck and trailer designs, low viscosity lubricants, regular routine maintenance and efficient driving techniques.

The study, sponsored by Shell and PepsiCo and hosted by the North American Council for Freight Efficiency (NACFR) and Carbon War Room (CWR), was done using over-the-road trucks in real world conditions. The trucks were equipped with Geotab telematics devices, which monitored speed, elevation gain, gallons consumed and miles traveled. “This is real drivers on real routes hauling real freight,” said Mike Roeth, Executive Director of NACFE. “These are not test vehicles that have been designed especially for fuel (economy); these are not on special tracks or anything like that.” In fact, part of the study occurred during hurricanes Harvey and Irma, adding high winds and congestion to those real world conditions.

More detailed information on the cross-country study, including mapping of routes, breakdowns by day, by truck and conditions can be found at www.runonless.com. A full report on Run on Less will be released some time in 2018. • 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.

The final results showed an average 10.1 mpg across all seven trucks involved, nearly 4 mpg better than the 6.4 mpg average of all Class 8 trucks operating in the US and Canada.

At a macro level, if the 1.7 million trucks running in North 31

© 2018 Mansfield Energy Corp

Viewpoints

By Nikki Booth, Senior Logistics Manager, Carrier Relations

What is the ELD Mandate?

Effective December 18, 2017, the Electronic Logging Device (ELD) mandate finally went into place. The ELD mandate requires an electronic record of a driver’s Record of Duty Status (RODS), which replaces the paper logbook drivers have historically used to record their compliance with Hours of Service (HOS) requirements. Fleets had until December 1, 2017 to implement certified ELDs to record HOS.

According to the FMCSA website, the ELD rule is being implemented in three phases:

An ELD synchronizes with a vehicle engine to automatically record driving time, providing easier, more accurate HOS recordings. Moreover, ELDs installed in commercial motor vehicles monitor and record a multitude of data about the vehicle and its driver that go beyond RODS — from Driver Vehicle Inspection Reports (DVIR) and IFTA (International Fuel Tax Agreement) automation to driver behavior reporting on speeding, idling and hard braking.

Many systems can also integrate with map and route solutions, helping drivers navigate construction areas, high traffic zones and structures likes tunnels and bridges that do not allow the passage of hazardous materials. This information can be passed to a system in which fleet managers compile data to identify trends impacting their business and the safety of their fleet.

After December 16, 2019, all drivers and carriers subject to the rule must use self-certified ELDs that are registered with FMCSA. For more information on ELDs, check out www.fmcsa.dot.gov and search for ELDs. •

Fleets equipped with electronic logging technology prior to December 18, 2017 will be “grandfathered in” and have until December 2019 to ensure compliance with the published FMCSA ruling specifications.

Unless a driver/vehicle combination is otherwise exempted, all drivers and vehicles subject to the hours of service MUST be equipped with an ELD. Until April 1, 2018, there will be soft enforcement during the implementation period, during which time drivers properly tracking their hours on obsolete paper logs will be cited, however, the citations will not go towards CSA SMS points. Drivers that have exceeded their hours or are not tracking their hours will be declared out of service per usual. Points and fines will also be assessed on these citations.

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© 2018 Mansfield Energy Corp

Nikki A. Booth Senior Logistics Manager, Carrier Relations 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 Clint Hamlin, Arsenal Fuel Quality Specialist, and Alan Apthorp, Market Intelligence Analyst

Why Are More Diesel Tanks Gelling This Winter?

During the winter, most fleet operators understand the need to keep their diesel fuel protected. Cold temperatures cause wax to drop out of diesel fuel, coagulating together to clog diesel tank and engine filters and shut down operations.

This year, diesel users in some areas have noticed that fuel is gelling at higher temperatures than normal.

Even fuel treated with additive and kerosene is not as protected as usual. Extremely cold weather experienced throughout the country has exacerbated these challenges over the past week. The recent cold snap had a higher-than-average impact on fuel operations, and the culprit may not be what you expect.

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Š 2018 Mansfield Energy Corp

Viewpoints

FILTER FILTER

Wax behavior WITHOUT cold flow improver

Large flat crystals block filter, no flow

Wax behavior WITH cold flow improver

Why Does Gelling Occur?

Emulsified crystals flow through filter

Before we examine what’s happening to diesel fuel this year, it’s helpful to understand why gelling occurs and how kerosene and additive affects the process.

Ultra-low sulfur diesel #2 (normal diesel fuel) contains natural waxes called paraffin wax. Tiny wax molecules float in the fuel along with carbon molecules and other substances. Wax is not always a bad thing – when the waxy molecules remain small, they can easily pass through a fuel filter.

Paraffin waxes have their perks. Paraffin waxes are combustible, meaning they add power when burned in the engine. Paraffin waxes make up a portion of the energy content in fuel – that’s why most candles are made from paraffin wax. On the flip side, kerosene (also known as diesel #1) has far less paraffin wax, and as a result it has a lower energy content. That’s why you may notice lower fuel efficiency and power when burning kerosene blends.

Those waxy paraffins cause problems when they glom together and plug filters. The Cloud Point is the point at which diesel fuel becomes cloudy from waxes lumping together. The colder the weather, the more paraffins drop out of the fuel and gel together. Larger paraffin chunks clog filters, preventing fuel from flowing through. The point at which your filter plugs and operations cease is called the CFPP – Cold Filter Plug Point. The CFPP is the most important metric for fleet operators, since that’s the point at which operations are disrupted.

The Cloud Point and the CFPP both vary depending on geography and fuel quality. In general, when properly treated with winter cold flow additives, the CFPP will be 18° below the Cloud Point – resulting in the 18° Rule. If your fuel is treated with additive and gets cloudy at 10° F, filters will be plugged at -8° F. Without additive, the CFPP could be anywhere from -8° F to +9° F; cold flow additives protect you up to 18° below whatever your fuel’s cloud point is. Kerosene, on the other hand, lowers the Cloud Point, typically buying you 3° lower Cloud Point for each 10% kerosene blended in.

In Summary: • Waxes in fuel bind together when temperatures fall and get stuck on fuel filters • With additives, filters will clog when temperatures are 18° below the Cloud Point • Kerosene can lower the Cloud Point, giving you additional protection at a rate of 3° per 10% blend • The Cloud Point varies based on refinery production and geograph

Poor Winter Fuel Quality This Winter

As mentioned above, Cloud Points are usually less than 10° F for diesel fuel. That means cold flow additives should protect fuel down to -8° F and kerosene could provide some additional protection.

However, new factors this year have fundamentally changed conventional diesel fuel winter performance.

Low crude prices have altered refinery supply chains. With prices so low, refineries are buying from a variety of crude sources, leading to highly variable feed stocks. Diverse feed stocks have made fuel quality less predictable. Diesel fuel specifications have no useful performance standards related to winter operability, so there’s no way to avoid poor quality fuel when it occurs.

Poor fuel quality this year has created two issues for winter operability: Cloud Points have been higher in some states, particularly Missouri, Kansas, and Pennsylvania. Cloud Points have been 5°-10° higher than ideal levels. That small difference is important, especially when temperatures are dipping below zero.

Extremely waxy fuel is causing fuel to gel even when Cloud Point Is at ideal levels. This is a major factor behind the increase of gelling incidents so far this season. Chemical lab tests show high wax contents in fuel in some areas this year, requiring much higher kerosene and additive treatment rates than normal.

These concerns are amplified by biofuel content, which can contribute to higher gelling temperatures. Biofuels are produced using a variety of different oils, ranging from soybeans and corn to animal fat. These can contribute to further filter clogging at cold temperatures. Every gallon of diesel fuel in the U.S. contains up to 5% biofuel, and some states use higher bio blends.

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© 2018 Mansfield Energy Corp

Viewpoints One other contributor, unrelated to fuel quality, is extremely fine fuel filters. During the winter, Mansfield suggests using a 10 micron fuel filter rather than a 4 micron filter. Gelled wax molecules will melt long before they reach engine injectors, so they won’t adversely affect engine performance. Excessively tight fuel filters have been the root cause behind several gelling incidents this year, and needlessly put operations at risk. It’s a small detail, but it can make a significant impact on fuel flow.

Is It Really Gelling?

As a side note, some gelling incidents are caused by water in the fuel, rather than paraffin wax. Like wax, frozen water can clog a fuel filter and cause engines to shut down. Water freezes at much higher temperatures than fuel, so if your filters are causing troubles at 20°-30° F, you may have an ice issue.

Checking whether you have ice in your filter is a fairly simple task. Just remove your fuel filter and if you see a thick waxy substance, you have fuel gelling. To fix it, you will need an emergency reliquefier or kerosene and winter additives to clear your tank. If you see an icy buildup, simply warm the filter to get fuel moving through it once again.

winter for Cloud Point and CFPP levels. With proper fuel testing and analysis, fleet managers can address poor quality fuel before it occurs.

Increase winter fuel treatment rates. Using more winter additive and higher kerosene has been effective in preventing and remediating gelling incidents. Mansfield has begun treating states as far south as Missouri and Kansas with the same treatments we normally use in Minnesota.

Keep emergency reliquefiers and cold flow additive available on-site. While higher winter treatment rates should prevent gelling, sometimes fuel sits for prolonged periods, or your vehicles may fuel offsite. With unpredictable temperatures this year, having extra winter additive and emergency reliquefiers such as Arsenal FIRST+AID can keep your fleet running through the extreme winter cold.

While fuel quality challenges this year present unique obstacles for fleet managers, proper winter fuel procedures can help avoid gelling incidents. Using these tools, fleets can successfully maintain operational performance throughout the winter. •

How to Prepare Your Fleet

This winter has already proven to be colder-than-average, so fleet managers should prepare for more cold weather in the coming weeks and months. Despite the challenges, there are steps fleet managers can take to minimize the risk of fuel gelling.

Test fuel tanks for Cloud Point and CFPP. Fuel testing is even more important this year than in past years. Mansfield recommends preseason and post-season fuel tests, as well as monthly tests during the

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© 2018 Mansfield Energy Corp

Clint Hamlin

Arsenal Fuel Quality Specialist Clint is responsible for Mansfield’s customer fuel testing program, additive product inventory and logistics, and Arsenal product marketing. He analyzes companies’ fueling methods, geography, and fuel samples to prescribe fuel additives and services that meet their fuel quality needs. Clint has been with Mansfield for over nine years, working previously as an inventory management specialist and operations specialist.

Viewpoints

By Dr. Nancy Yamaguchi, Contributing Editor

WTI and Brent Crudes: Trans-Atlantic Cousins Re-examine their Relationship

Introduction

Crude oil is the largest commodity in global trade, and oil prices are arguably the most intently watched prices in the world. Two key crudes have emerged as the benchmarks for Trans-Atlantic pricing: West Texas Intermediate (WTI) in the U.S. and Brent Blend in Europe’s North Sea. Both are light (low in specific gravity) and sweet (low in sulfur) crudes. In terms of quality, WTI and Brent are relatively close. We may liken them to Trans-Atlantic cousins serving as benchmarks in their respective markets. Contracts for the purchase of many other crudes often are based on discounts or premiums relative to these benchmark crudes.

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The price gap between WTI and Brent is closely watched as a barometer of Trans-Atlantic crude supply and demand. When WTI prices stray too far above Brent prices, this eventually stimulates movement of crude to the Americas. Conversely, having Brent prices too far above WTI prices stimulates movement of crude to Europe.

This briefing explores WTI and Brent crudes, their qualities, and their price relationship. Crude prices have been moving dramatically, and the price differential between WTI and Brent has also changed. These TransAtlantic cousins are re-examining their relationship.

Š 2018 Mansfield Energy Corp

History of the WTI-Brent Price Differential

The international market has been accustomed to seeing WTI and Brent prices track one another closely, with WTI priced at a premium. The accompanying chart shows the WTIBrent price differential calculated from monthly average spot prices as reported by the EIA. Between 1987 and 2004, the WTI-Brent price differential averaged around $1.50/b.

Thereafter, crude prices and the WTI-Brent relationship became much more volatile.

Crude prices climbed dramatically, and in 2008, WTI prices skyrocketed above $133/b while Brent prices went over $132/b. The Shale Boom was underway, and U.S. crude production rose by over 4.4 MMbpd between 2008 and 2015. The price spike was followed by a slump. Oversupply in the U.S. drove U.S. prices down relative to global prices, and the WTI-Brent differential went as low as -$27/b in 2011.

By the end of 2013, Saudi Arabia began to boost production to drive U.S. shale producers out of the market. This oil price war drove prices down, and the WTI-Brent differential narrowed. WTI prices climbed closer to Brent prices. The end of 2017 brought a higher price structure overall, plus a run-up in Brent prices caused partly by the rupture of the Forties pipeline. In December 2017, Brent prices were $6.49 above WTI prices. Future prices in January 2018 are pointing higher, with WTI at approximately $62/b and Brent approaching $68/b.

WTI–Brent Price Differential, $/b

Depending on the types of processing units in a refinery and the value of the output product, different crude blends may be more or less valuable. Certain crude blends create more motor fuels like diesel and gasoline, while others produce more of the heavier byproducts, such as fuel oil and asphalt. Regional restrictions also play into the mix, with high-sulfur products acceptable in some countries but not others.

Still, given the similar quality between WTI and Brent, such detailed distinctions should not add more than a couple of dollars to either product. The large price premium currently accorded to Brent crude, averaging roughly $6 in Q4, is not warranted by its quality relative to WTI. The explanation must lie elsewhere.

Three other factors are at play, driving the Brent-WTI spread to be larger than quality alone can justify: • The changes in the U.S. crude slate

WTI and Brent Crude Quality: Difference Beneath the Surface

Source: Author’s calculations and estimates

• The change in the North American supplydemand balance versus the European and Eurasian supply-demand balance, and • The internal logistics of crude transport in the U.S.

During the years when WTI prices steadily surpassed Brent prices, it was commonly accepted that WTI was worth more because it was lighter and lower in sulfur. WTI crude is noted as having an API gravity of 40.8 and a sulfur content of 0.34% by weight. Brent Blend is noted at 40.1 API and 0.347% sulfur by weight. Crude qualities will vary over time, since the streams are blended, but WTI and Brent are quite close in quality according to these two simple measures. Individual refineries will place more or less value on them as feedstocks depending on a variety of factors, including their overall feedstock diet, their technology in place, and the market they serve.

Two crudes with identical API gravities and sulfur contents may differ significantly in their attractiveness to a specific refinery. For example, the weight percent of the sulfur may be identical, but the sulfur levels in specific cuts of the crude may vary. Imagine that Crude A has an unusually high concentration of sulfur in its diesel-range material, while most of the sulfur in Crude B is locked into its heaviest vacuum residue. Most refineries striving to create essentially sulfur-free diesel would favor Crude B. 37 33

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The Changing U.S. Crude Slate

As noted, light, sweet crudes typically are more expensive than heavy, sour crudes. In the 1990s, U.S. refineries assiduously upgraded their facilities to accommodate a heavier, sourer crude slate. By adding technological sophistication, the cost of the crude feedstock could be reduced.

It was generally accepted that heavy, sour crudes would remain abundant and cheap. In 1985, crude inputs to U.S. refining averaged 0.91% sulfur and 32.5 degrees API. The slate grew steadily heavier, and the API gravity averaged 30.2 degrees in 2004 and 2005. The sulfur content crept up to 1.42% by 2005.

By this point, however, U.S. production was rising,

Viewpoints and the new light tight oils (LTOs) from shale plays were changing the average crude slate. The sulfur content stopped climbing, and it has remained relatively flat between 2005 and 2017. The downward trend in API gravity reversed, and it rose to 31.8 degrees during the JanuarySeptember 2017 period.

North American Net Oil Imports Were Surging Until the Shale Boom, European & Eurasian Net Imports Were Falling

The influx of light, sweet crudes has changed the U.S. crude slate, and the value of light, sweet crudes has diminished slightly relative to the heavy, sour crudes that U.S. refineries had geared up to use.

Lighter, Sweeter Crudes Changing the U.S. Crude Slate

The Shale Boom and Internal Crude Logistics

Source: Energy Information Administration (EIA)

The Change in Supply-Demand Balance, North America vs Europe & Eurasia

Another key determinant of the relative value of WTI crude versus Brent crude is the regional supply-demand balance. North America is a major net importer of oil, and the world expected its net import requirements to continue to grow. The accompanying figure uses British Petroleum’s (BP) data on oil demand minus oil production as a rough estimate of North American and European/Eurasian net import requirements from 1965 through 2016. In the years before the oil price shocks of the 1970s, net import requirements were soaring in both regions. The price shocks caused demand to fall and production to rise, cutting into the net import requirement.

Source: BP

The huge upsurge in U.S. production placed enormous pressure on oil transport infrastructure, compounded by the increase in Canadian production of bitumen-based synthetic crudes in Alberta. Bakken LTOs in the Dakotas were already straining the oil delivery system.

The crude pipelines in the area were accustomed to small, locally produced crude batches; they were overwhelmed when North Dakota’s crude production jumped from less than 100 kbpd in 2005 to over 1 MMbpd in 2014.

Looking back to the figure illustrating the change in the WTI-Brent price differential (pg. 31), note the huge drop in relative WTI prices in 2011-2012. Domestic crudes were being sold at heavily discounted prices during those years since there was insufficient infrastructure to cart it away; producers cut prices to get rid of excess inventory.

In the U.S., pipelines are the chief mode of transporting crude to refineries. As pipeline capacity was filled, delivery of domestic crude

Deliveries of Domestic Crude to U.S. Refineries, Non-Pipeline Modes, kbpd

After the collapse of oil prices in 1986, however, North American demand began to climb, whereas crude production peaked and entered a period of decline. The net import requirement grew from around 4.4 mmbpd in 1986 to over 11.4 mmbpd in 2005. The Shale Boom, plus expanded output in Canada, reversed this. North American demand also has declined over the past decade. Between 2005 and 2016, North America’s net supply gap fell below 4.6 mmbpd, an astonishing drop of 6.8 mmbpd.

In contrast, crude production in Europe and Eurasia has been growing steadily for decades while demand has been declining. The result has been a steady decline in the net import requirement, which fell from approximately 7.9 mmbpd in 1992 to less than 1.1 mmbpd in 2016.

In short, the world expected that the U.S. would continue to purchase more and more crude from the international market. The expansion of regional supply reversed this.

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Source: Energy Information Administration (EIA)

Viewpoints Allowing exports also alleviated some of the strain on oil transport.

Already, additional pipeline capacity had come online to ease the flow of oil, reducing the need for more expensive transport options. Freeing up U.S. light crude exports made seaborne tanker trade more efficient as well, since inbound tankers carrying medium or heavy crudes could sometimes load a backhaul cargo for at least part of the return voyage, rather than steaming back in ballast (with empty cargo tanks).

No More “steady state” for the WTI-Brent Price Differential

by non-pipeline modes increased. According to the EIA, delivery by barge rose by over 500% between 2010 and 2015. Delivery by tank car grew a whopping 30x, from 12 kbpd in 2010 to 365 kbpd in 2014.

Delivery by truck doubled during that same period, rising to 484 kbpd in 2015. By 2014-2015, additional pipeline capacity began to come online, and the use of these other modes began to ebb.

Removal of Restrictions on Crude Exports

Regional oversupply of crude in the U.S. was exacerbated by restrictions on crude exports. The restrictions were commonly referred to as the “crude export ban,” though as the figure below illustrates, the U.S. has exported crude for over a century. The EIA reported that the U.S. exported 13 kbpd of crude in the year 1913. In 1975, following the oil price shock caused by the Arab Oil Embargo, the U.S. enacted severe restrictions on the export of crude oil under the Energy Policy and Conservation Act. Some crude trades were allowed, but others required specific licenses from the U.S. Department of Commerce.

The restrictions on exports, although not a ban, were a great deterrent to free trade. The restrictions were in place for forty years, and much of the nation’s petroleum infrastructure was built with these restrictions in mind. In 2015, Congress voted to end the restrictions. Crude exports shot up to 591 kbpd in 2016, and they have averaged 960 kbpd during the first three quarters of 2017. Unsurprisingly, the value of WTI crude improved relative to Brent.

U.S. Exports of Crude Oil, 1913 – 2017, kbpd

When the U.S. was on its staid course of doing everything the global market expected, WTI tracked its Trans-Atlantic cousin, Brent, quite closely. The price differential was on a steady course, with WTI favored with a premium based on its slightly more favorable quality.

But the steady-state relationship has ended. The past decade has been enormously eventful. The oil price spike of 2008 sent crude prices above $130/b. A catastrophic global recession followed. But the high prices fostered the U.S. Shale Boom, bringing over 4 million barrels per day of new supply online in short order. Oil transport infrastructure was overwhelmed, prompting temporary use of nonpipeline modes and a wave of pipeline construction.

Prices weakened, and OPEC launched an oil price war. Many U.S. producers went out of business, but many remained and grew even stronger. As of the time of this writing, U.S. crude production has hit a new record of over 9.6 MMbpd.

The removal of crude export restrictions unleashed exports. Although the accompanying figure shows exports averaging 960 kbpd during the first three quarters of 2017, the EIA’s weekly export data for Q4 show that exports are now close to 1,500 kbpd.

The market has changed in so many ways, and it appears that the changes are irrevocable. Although WTI is likely a more valuable refinery feedstock than Brent, many other factors are at play that refinery economics cannot explain. Numerous forces beyond just quality weigh upon the WTI-Brent relationship: the shale boom, the changing crude slate, the supply-demand balances in regional markets, transport logistics, and regulatory requirements. These are large, powerful forces, and they are changing the relationship between the two Trans-Atlantic cousins.

Will the differential ever revert back to the steady course with WTI slightly above Brent? Such a thing is not expected in 2018. Both crudes have risen in value over the past year, and the crude price outlook for 2018 is expected to be in the $60-$70/b range. What are these crudes really “worth” relative to one another? As the Latin writer Publilius Syrus in the first century BC noted: “Everything is worth what its purchaser will pay for it.” • Dr. Nancy Yamaguchi, Ph.D. 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: EIA. 2017 data are Jan-Sep average

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Viewpoints

By Tom Krizmanich, Director of Business Development Natural Gas & Power

Uniting Natural Gas and Fuel Purchasing Strategies

Second, the two products are regulated differently. We’ve discussed in previous issues the impact of the Federal Regulatory Commission (FERC) on natural gas policies. While natural gas used to be heavily regulated, open competition is available today. Companies can change natural gas suppliers with very little logistical requirements.

Fuel, on the other hand, is heavily taxed and well-regulated from an environmental standpoint, but distribution is quite flexible. Your fuel can be bought in bulk, purchased at a retail station, or delivered directly into your equipment. Because of the intricate logistics involved in fuel deliveries, changing fuel suppliers can be more complex.

Third, deal terms work quite differently for natural gas and fuel. While natural gas supply contracts often extend three to five years, with room of additional extensions; fuel contracts rarely extend that long. Liquidity in futures markets allow natural gas prices to be fixed for five or more years, while fixed fuel prices typically last less than three years. Overall, natural gas tends to be more stable as a commodity, while fuel involves more risk (as well as more opportunities to optimize).

Although natural gas and crude oil have very different applications, many analysts group the fossil fuels together in reporting and analysis. Natural gas and crude oil tend to be found together in nature, and shale production in the U.S. has radically increased supplies of both. While different in application, the similarities between the two products may create opportunities for companies to find synergies when procuring fuel and natural gas.

Crude and natural gas are found together in the earth – natural gas is simply the smallest carbon molecules in oil, too small to congeal into the liquid crude oil. For years, crude and natural gas prices moved together, rising and falling in tandem. With the advent of fracking technology in 2014, natural gas prices decoupled from crude oil prices, but the two are still often grouped when discussions of production and supply occur.

Difference Between Natural Gas and Oil S U P P LY C H AI N

Two Sides of the Same Coin

Due to the differences between the two products, many companies treat natural gas and fuel separately, handled by different resource groups. Despite differences, many companies using both natural gas and fuel can learn from different energy buying styles. Common practices in the natural gas supply world can improve fuel purchasing, and vice versa.

How can companies consuming both products benefit from similarities between the two products? There are at least four ways companies can build synergies across buying groups.

First, as commodities, both products are differentiated in the marketplace by price and service. Natural gas quality does not vary, and all fuel in the U.S. is subject to the same (or very similar) fuel specifications. Both must be evaluated based on what services and pricing structures a supplier can wrap around the fuel.

There are some notable differences between natural gas and fuel:

For fuel, differentiating services include transaction management and reporting, emergency fuel supply, inventory management, and DEF availability. Natural gas has some similarities – rather than managing fuel tank inventory, natural gas suppliers manage pipeline storage and demand optimization, helping to lower costs. For both products, billing consolidation is an important feature.

First, the products are logistically different. Natural gas is transported to each consumption location via pipeline, requiring vast infrastructure to push gas to an end location. As a compressed gas, natural gas travels instantaneously – pressure applied on one side of a pipeline rapidly pushes gas out on the other side. On the other hand, products like gasoline and diesel are liquids, which can take days to flow across the country. Additionally, fuels must be trucked to a final destination, requiring additional logistics oversight.

Second, risk management principles apply to both commodities. Both are traded on the New York Mercantile Exchange (NYMEX), allowing for future price protection.

Forward price budget protection tools can include fixed prices, caps and collars to control risk. Both commodities also have numerous national and regional indexes that can be used for transparent pricing.

WHOLESALE SUPPLY

LOCAL SUPPLY

DISTRIBUTION

PETROLEUM

Production & Refining

Terminal Rack

Carrier Network

NATURAL GAS

E&P & Pipeline Pooling

LDC City Gate or Pool

Local Distribution Utility

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Viewpoints For companies with fixed natural gas prices but fluctuating fuel prices, natural gas buyers can help inform a sophisticated fuel risk management program. Fuel buyers, adept at benchmarking across numerous indexes, can share their expertise when a company considers buying natural gas at indexed pricing.

In addition, some suppliers can consolidate energy purchases into one report and statement bill, reducing administrative costs. Finally, a single point of contact for all energy needs allows the supplier to creatively manage your entire energy needs and optimize across all energy methods.

Third, both natural gas and fuel can be used for transportation or for power. Compressed natural gas (CNG) vehicles are widely available, allowing fleets to diversify their transportation costs and spread out risk. Conversely, diesel fuel is often used in generators to supply back-up power to buildings.

Companies who can master the optionality of these energy sources can implement some unique cost-saving strategies. Investing in CNG vehicles can reduce price risk and provide a greener alternative for fleets; however, it requires that fleet managers develop a thorough understanding of natural gas markets. Using diesel generators can be extremely beneficial during cold winter days when natural gas prices spike. Companies can call on their fleet fuel supplier to keep diesel generators supplied.

Procurement Synergies

Despite the differences between natural gas and fuel, the similarities between them make it an ideal area for cross-functional collaboration.

By working together, fuel and natural gas buying teams can help improve each other’s performance. Receiving competitive pricing, risk management services and structured pricing products that meets each client’s individual needs and risk profile are essential for any buying strategy.

Supply chain management can be a source of competitive advantage for companies who approach it correctly. Finding ways to build synergies between different buying groups is one way to help promote superior buying for the whole company. By hosting team events, or simply establishing regular meetings between groups, companies can begin to improve their total energy buying capabilities. •

Finally, companies can leverage their volume from both commodities to lower their overall commodity spend. Some energy companies, like Mansfield, offer both fuel and natural gas supply. By coordinating natural gas and fuel purchasing strategies, companies can find opportunities to buy both fuel and natural gas from the same supplier.

Vendor consolidation offers numerous benefits. Combining volumes often leads to larger price discounts, reducing overall supply costs.

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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.

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

Joshua Wakeman

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. •

Joshua joined Mansfield’s Supply Team following the recent acquisition of The Earhart Company. Joshua is responsible for gasoline and diesel supply in the northeast. At Earhart, Joshua managed the company’s gasoline, diesel, and propane hedging and supply needs. •

Supply Manager

Senior VP of Supply & Distribution

Martin Trotter

Pricing & Structuring Analyst

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. •

Nate Kovacevich

Sara Bonario

Senior Supply Manager

Supply Director

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. •

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. •

Alan Apthorp

Chris Carter

Market Intelligence Analyst

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. •

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. •

Amy Nguyen

Madi Burton

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. •

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. •

Market Intelligence Analyst

Supply Optimization Supervisor

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Disclaimer: The information contained herein is derived from sources believed to be reliable; however, this information is not guaranteed as to its accuracy or completeness. Furthermore, no responsibility is assumed for use of this material and no express or implied warranties or guarantees are made. This material and any view or comment expressed herein are provided for informational purposes only and should not be construed in any way as an inducement or recommendation to buy or sell products, commodity futures, or options contract.

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