FUELSNews 360° - Q1 2019 by FUELSNews

M A R K E T

N E W S

1st QUARTER

I N F O R M A T I O N

Table of Contents FUELSNews 360° Quarterly Report Q1 2019 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—to provide insight into upcoming challenges facing the energy supply chain.

Executive Summary

Overview 6

Regional Views continued 22

January through March 2019

Economy & Demand 11

Fuel Demand

Rocky Mountain

West

Canada

Fundamentals 12

Production and Consumption Balance

Involuntary Supply Outages

Crude Inventories

Fuel Inventories Replicate 2018 Trends

Where Did All the Refiners Go?

Gasoline Crack Spreads Reach 10-Year Low

Explosive US Crude Production Growth Continues

US Moves Toward Net Exporter Status – 4 Takeaways

EIA Suggest IMO 2020 Diesel Price Spike

Nate Kovacevich Sara Bonario Nate Kovacevich

Alternative Fuels 26 27

Renewables

Sara Bonario

Natural Gas Supply, Demand, Storage Martin Trotter

Viewpoints 29

Impact of Fuel Prices on Logistics

Nikki Booth

Improve Fuel Economy Potential with Lower Viscosity Engine Oils Amy Macaulay

Regional Views 20

Midwest

Dan Luther

East Coast

Trading Nickels for Dimes: Increase Your Fleet Program’s Bottom Line Brian Hutchinson

Dan Luther

Gulf Coast

Gabe Aucar

FUELSNews 360˚ National Supply Team Contributors

Q1 2019 Executive Summary Oil Market Summary

Regional Fuel Overview

The New Year marked a reversal for oil markets, which had stumbled toward the end of 2018. In fact, by March the vast majority of Q4’s losses had been erased. With 30% growth in just 90 days, crude experienced some of the quickest Q1 percentage gains in trading history.

Weather played a significant role in some markets in Q1. Midwest states saw record-low temperatures that adversely affected refinery throughputs and diesel fuel operability. Strong demand for kerosene led to some regional outages, as Dan Luther discusses on page 22. Houston fog and Southeast flooding taxed markets not directly connected to the Colonial Pipeline, leading to higher prices in Florida and Tennessee.

Supply-side shortages contributed significantly to the run-up in prices. OPEC returned to their strategy of balancing oil markets, and unplanned outages in areas such as Libya caused a sharp drop in product availability. Major geopolitical factors at play included American foreign policy in Venezuela and Iran. Together, these two countries would dominate headlines throughout Q1. Substantial speculation around regime conflicts, economic distress, and ultimately oil output stoked concerns of tighter supply. Supply constraints were not alone in pushing prices up, though. Strong global demand kept steady pressure on oil inventories throughout Q1. A key contributor to Q4’s decline was concern over economic demand in 2019; but, despite warnings that the global economy was beginning to show signs of a “synchronized slowdown,” the first quarter certainly started the year on strong footing. In the months ahead, oil prices should remain roughly balanced with an upward bias. Saudi Arabia is within striking distance of its $80/bbl target needed to balance its government budget, so OPEC is expected to moderate its market approach this summer. With significant spare capacity, the group – joined by a huge uptick in US production – will help displace some of the output from Iran and Venezuela. Of course, IMO 2020 is the wildcard factor. Though forward markets currently have not priced in a large price premium, agencies such as the EIA warn that diesel prices may see effects of 20 cpg or higher. You can read the latest on IMO 2020 on page 19.

With Canada hopping on the production cut bandwagon, Canadian crude prices rose sharply in Q1 as well, partially offsetting the discounts that Chicago fuel consumers typically enjoy. Nate Kovacevich explains the adverse effects these cuts may have on long-term oil prospects on page 25. Market Insights Whichever direction markets move, fleets cannot respond to fuel price changes until they have adequate controls over each fueling transaction and actionable insight into aggregate activity. Tracking every fuel purchase can be a chore without the right tools. On page 31, Brian Hutchinson details a key fleet fueling tool every fleet operator should consider. Often, paying less for a product up front can create long-term costs for your company. Guest author Amy Macaulay, from the leading fuel and lubes distributor O’Rourke Petroleum, explains on page 30 how choosing the right lubes for your fleet can save dividends in fuel and maintenance costs. •

OVERVIEW January through March 2019 The first quarter began with a virtual reversal of Q4’s price declines, bringing prices nearly back in line with market expectations. When crude oil prices fell from $75/bbl all the way to $45/bbl in Q4, markets were perplexed. While President Donald Trump’s waiving of Iran sanctions for eight key countries certainly tilted markets toward oversupply, inventories were nowhere near the heights seen back in 2016, when prices last traded at such a low level. Market panic and automated trading strategies pushed prices artificially low, setting the stage for Q1’s rally. And rally prices did, with crude oil posting 35% gains in just three months.

As the quarter opened, such a rebound appeared far from guaranteed. While fundamentals suggested snapback prices, markets struggled to break free of the $50-$55 range through January. A few very large down days, bringing losses of 2% or more at times, masked the slow, steady rally during this time. The US rang in the New Year with the longest government shutdown in US history, leading many to fear adverse fuel demand affects. The shutdown influenced fuel demand in a number of ways: 380,000 government workers missed their daily commutes, government

Q1 Market Summary

$1.9734 $1.8956

$60.14

26,656.39

Source: New York Mercantile Exchange (NYMEX)

Overview

Q1 2019 Crude Prices

Source: New York Mercantile Exchange (NYMEX)

projects were temporary shuttered, etc. Overall, the Congressional Budget Office estimates the shutdown decreased US GDP growth by 0.4 percentage points ($80 billion), though some of the losses will be recouped in future months. On the supply side, though, efforts by OPEC and Canada gave markets a taste of balance. After loosening production quotas in the lead up to Iran sanctions, OPEC tightened its belt on January 1 and resumed its adherence to cuts. Saudi Arabia led the charge, as their government requires Brent crude oil prices around $70-$80 to balance their budgets. A surprising bedfellow, Canada joined the Saudis in production cuts on January 1, though their mission was quite different from OPEC’s. Canadian crude sank to nearly $50 discounts below WTI crude oil – meaning a barrel of crude was only fetching $20/bbl for producers. Pipeline capacity restraints from Alberta southward caused the province’s abundant production to become stranded locally, pushing down prices. Canada’s output limits were hardly an attempt to influence global prices; 7

rather, they represented an effort to improve local drilling economics. In this, Canada was successful – WCS’s discount to WTI shrank to just $10 by the end of Q1. Throughout the quarter, US-China trade talks dominated political headlines. In July 2018, President Trump slapped 25% tariffs on $34 billion of Chinese goods – firing the first volley in the US-China trade war, to which China responded with tariffs on $16 billion of American goods. By September, the US imposed a 10% tariff on an additional $200 billion of Chinese goods; and China returned the favor with tariffs on $60 billion of US goods. America’s 10% tariff was set to increase to 25% on January 1, but Trump delayed the increase, amid positive advances in trade talks, to March 1— then delayed them again. Throughout the quarter, rhetoric from leaders in both countries has been positive, though talks have yet to translate into action. While OPEC cuts and US-China trade talks extended throughout the quarter, Venezuela reared its head acutely in January, leading to US

Overview

Quarterly WTI Crude Prices

action. The situation began with several Latin American countries refusing to recognize Maduro’s second term in office, claiming elections held the previous May “lacked legitimacy.” National Assembly leader Guaidó declared the presidency vacant a week later, effectively making him the ruler. Maduro refused to relinquish control, however, leading the US to recognize Guaidó and impose sanctions on the country’s national oil company, PDVSA, on January 28.

Source: New York Mercantile Exchange (NYMEX)

Like crude oil, diesel’s quarterly average price loss versus Q4 2018 masks the huge gains in prices made throughout the beginning of 2019. Diesel prices opened the quarter at $1.70, rising to $1.97 by the end of the quarter – a 27 cent (16%) gain. Yet the quarterly price was 13 cents below Q4, at just $1.94 per gallon.

Quarterly Diesel Prices

Source: New York Mercantile Exchange (NYMEX)

No product saw price gains as substantial as gasoline. Starting Q1 at a meager $1.32, prices soared – thanks to EPA summer gasoline mandates and strong demand – to $1.89, a blistering 57 cent (43%) gain. The quarterly average change was less pronounced. While gasoline averaged $1.65 in the final quarter of 2018, the first quarter of 2019 saw the average price fall to $1.59. •

Quarterly Gasoline Prices

Venezuela would continue dominating the oil narrative, with the world closely watching every shipment to find out where it was bound. Production fell from its 2019 opening level of 1.2 MMbpd, nearly halving down to roughly 700 Kbpd in March. With Saudi Arabia still adhering to its production quotas, Venezuela’s output decline has left a large gap in the market that has yet to be filled. Crude oil rose from a beginning price of $46.22 to a closing price of $60.14 – a gain of $13.92, or 30%. The first quarter of the year tends to see prices rise in anticipation of spring demand season, but this year’s was one of the largest gains by percentage ever for the first quarter. Yet looking strictly at the average price, Q1 was below Q4 2018 – simply because prices were so high in October 2018. 8

Source: New York Mercantile Exchange (NYMEX)

Overview

Gasoline Rack-to-Retail Spreads

Retail Spreads Return to Normal

Companies utilizing fleet cards for their fuel purchases were somewhat insulated from the climbing prices. Rack-to-retail spreads, the difference between retail prices – at gas stations or truck stops – and wholesale fuel prices, skyrocketed in late 2018 as wholesale prices fell. During this period, wholesale fuel buyers saw their fuel cost fall 75¢; yet prices for retail consumers fell just 25¢.

Source: Energy Information Administration (EIA)

Diesel Rack-to-Retail Spreads

Source: Energy Information Administration (EIA)

The first quarter brought a reversal of huge rack-toretail spreads, with both gasoline and diesel prices returning to their normal retail thresholds as wholesale prices climbed. Compressing spreads meant retail gasoline prices rose just 45¢, while wholesale gasoline prices gained 60¢. For diesel, the difference was even more pronounced – wholesale diesel prices went up 40¢, while retail prices rose just 3¢. While retail prices move more smoothly than wholesale prices, the benefit is rarely in favor of the consumer. Throughout Q4 and Q1, consumers were better off purchasing at bulk rates than paying full retail price for fuel. Retail stations tend to remain high when prices are falling, but begin passing through higher prices when their costs rise – a phenomenon referred to in this publication before as “sticky pump.” As fuel prices continue rising, expect spreads to remain narrow. •

ECONOMY & DEMAND

As oil supply has tightened, the economy has demonstrated mixed signals. In the US, GDP slowed a bit in Q4 2018, and a government shutdown through parts of January created headwinds as the year began. Still, data confirms that the US grew at 3.0% in 2018, the fastest expansion in over a decade. Forecasters expect this growth to shrink back to 2.4% in 2019.

US GDP Growth

Source: Bureau for Economic Analysis

The Federal Reserve also took steps in Q1 to limit further economic headwinds. Coming into 2019, markets generally expected two or less interest rate hikes for the year. Now, the Fed is taking a more patient approach, saying interest rates likely will not be hiked again from the 2.25%-2.5% range. In fact, the central bank might even choose to lower interest rates at some point this year. Interest rates play a key role in stimulating demand by incentivizing loans. Lower interest rates make it easier to get cash, leading to more business loans and economic activity. Higher interest rates do the opposite. The Fed’s decision to keep interest rates flat to lower will certainly provide some economic support in the months to come. Globally, the economy is facing more serious challenges. Just after Q1, Brookings Institute declared the world seemed to be moving towards a “synchronized slowdown” as major countries seem to lose steam in unison. The World Bank expects global growth this year to be just 2.9%, down from 2018’s 3.0% growth. Higher interest rates around the world, along with a rising US dollar, could put pressure on buying capacity and debt levels in developing economies, which are the lifeblood of the global economy. •

Fuel Demand

Economy & Demand

Within the US, fuel consumption is expected to continue rising despite alternative fuels such as electric vehicles and CNG gaining ground; however, gasoline and diesel make up very little of the 0.4 MMbpd growth in demand expected in 2019. In 2018, distillate demand rose by almost a quarter million barrels per day, but 2019 will bring more subdued demand growth. Still, summer diesel consumption is expected to reach its highest point since 2007, averaging 4.1 MMbpd.

US Liquid Fuels Product Supplied (consumption)

Summer gasoline demand is expected to be just over 9.5 MMbpd this year, slightly higher than last year and on par with 2017’s record demand. With the economy strong and wages beginning to tick higher, the EIA is forecasting a 1.3% increase in highway travel. Despite higher driving numbers, however, demand will be just 0.3% higher than last year due to improved fuel economy. •

Components of Annual Change

Source: Energy Information Administration (EIA), Short-Term Energy Outlook, April 2019

F U N D A M E N TA L S

Starting the year, global supply and demand shifted from the huge builds in Q4 to a slightly undersupplied market. After having loosened their production requirements, OPEC countries reaffirmed their commitment to balancing markets towards the end of 2018, leading to sharp declines in crude inventories. Saudi Arabia and Russia led OPEC’s reductions, with the Saudis going well beyond their committed cuts. Canada also sliced their output by 325 Kbpd starting on Jan 1, though their focus was on improving Western Canadian crude economics, not influencing global oil prices.

World Liquid Fuels Production and Consumption Balance

Countering lost OPEC supply was continued growth of US production – weekly March production surpassed 12 million barrels per day, a new record high. Led by the Permian, US crude output is expected to continue growing rapidly for the next few years, levelling off around 14 or 15 MMbpd. •

Source: Energy Information Administration (EIA), Short-Term Energy Outlook, April 2019

Fundamentals

Involuntary Supply Outages Involuntary cuts arguably played an even larger role than intentional supply plays in Q1. Three countries suffered unplanned production losses – Libya, Iran, and Venezuela.

Libya’s shortfall was caused by militant attacks on their largest oil field, El Sharara, which can produce 300 Kbpd of oil when fully operational. Production went offline in December, and the field was dormant until March 5. In Q1 alone, that outage equates to 20 million barrels of oil pulled off the market – nearly all of the supply shortage indicated in the EIA’s data. Iran and Venezuela, both targets of American sanctions, also reduced output. Iran’s production was less significantly impacted given Trump’s waivers to several of their customers, but Venezuela suffered some huge supply outages. As the country lost one of its largest customers, Venezuelan output fell from 1.2 MMbpd at the beginning of the year to just 0.7 MMbpd in March. Additionally, the US prevented shipment of diluents, light crude blends that are blended with Venezuela’s heavy crude to improve flow rates through pipelines, which further hampered output. Venezuela’s rapid decline was not caused by US santions, however. In early March, widespread blackouts struck the country, lasting a week before being resolved. The outages are attributed to both a lack of infrastructure investment and the ongoing knowledge drain of engineering expertise out of the country. •

FUEL PRICE RISK MANAGEMENT Protect your budget.

Fuel prices can change without warning. Mansﬁeld’s Risk Management team helps you manage fuel price risk and stay on budget. Reliable Nationwide Supply • Firm Pricing Price Insurance • Price Collars Contact a risk management expert today.

678.207.3138 | hedging@mansﬁeldoil.com | www.mansﬁeld.energy 13

Fundamentals

Crude Inventories

Crude Stocks 5-Yr Range

While crude inventories typically rise in the US during the first quarter of the year, Q1 2019 saw them remain relatively flat, with just a modest uptrend for the season. Inventories began the quarter at 440 million barrels, and ended around 450 million barrels. Compared to the normal seasonal build of 50 million barrels, the small increase seen this quarter heralds tight crude markets in the months to come. US inventories are among the most important in the world for two reasons. First, US fuel markets are the most transparent in the world, with weekly government updates on supply, demand, and inventories. Second, the US is both the largest producer and the largest consumer in the world, so American stocks make up a hefty portion of global inventories. US petroleum data is used as a proxy for global trends, causing its strong impact on global oil prices. â&#x20AC;˘

Source: Energy Information Administration (EIA)

Fuel Inventories Replicate 2018 Trends Like last year, diesel inventories were below the five-year average, with the gap widening later in the quarter. Diesel inventories typically contract by 10 million barrels in the first quarter of the year, so the 12 million barrel drop in Q1 was largely expected. Diesel demand was generally at the high-end of the five-year range, keeping steady pressure on inventories.

Diesel Inventories 5-Yr Range

In contrast to diesel, gasoline inventories were above the five-year range early in the quarter. Gasoline inventories rise each year as refineries push to replenish storage tanks ahead of the summer demand season. This year, stocks peaked at 259.6 million barrels, setting a new all-time high for US gasoline inventories. Although gasoline inventories hit a record high, Q1 saw some fast price growth for the product. Why the incongruity? While inventories did set a new record, they peaked very early in the season and began dropping rapidly, moving quickly towards the five-year average. The hefty gains in Q1 were simply a return to more traditional levels for gasoline prices, which took a hard hit from extremely high inventories in Q4 2018. â&#x20AC;˘

Source: Energy Information Administration (EIA)

Gasoline Inventories 5-Yr Range

Source: Energy Information Administration (EIA)

ÂŠ 2019 Mansfield Energy Corp

Fundamentals

Where Did All the Refiners Go?

Refinery Utilization 5-Year Range

During the first quarter of the year, fuel markets saw a notable decline in refinery uptime. Refinery utilization did something in Q1 that it hasn’t done consistently in a long time – it dropped below the seasonal average, and by late March was even trending outside the five-year range. Refinery utilization, the measure of how much of total national refining capacity is being used in any given week, tells markets how much refined product will be available. Low utilization means less fuel being produced and more crude oil staying in inventories. •

Source: Energy Information Administration (EIA)

Fundamentals

Gasoline Crack Spreads Reach 10-Year Low The decline in refinery utilization corresponded with a rapid decline in gasoline crack spreads – the economic difference between a gallon of gasoline and a gallon of crude oil. Typically, gasoline crack spreads are in the 3050 cent range. This range also represents the average profit margin a refiner can expect from converting crude into products like gasoline and diesel fuel. While diesel crack spreads remained strong, gasoline spreads cratered in Q1.

Gasoline Cracks Reach 10-Year Low

Although gasoline demand has been relatively healthy in the past few months, extremely high refinery utilization in 2018 led to a supply glut in gasoline markets, even while diesel supplies were below the average. That glut caused gasoline margins to plummet – hitting a ten-year low in January of 11 cents. The last time spreads fell so low was in 2010, when spreads fell under five cents. Refiners operate in the middle of a complex commodity market – with crude costs fluctuating upstream and refined product prices gyrating downstream. Refineries cannot control prices on either end, so they must either hedge their output or take whatever the market will give. Gasoline is the dominant product coming out of a barrel of crude oil, generally representing almost half of the

Source: New York Mercantile Exchange (NYMEX)

barrel’s total refined product output. When gasoline margins fall, there is lower incentive to produce that product. Refineries will often lower output in order to prevent large financial losses caused by the adverse economics of declining crack spreads. Soon after gasoline spreads hit their low, refineries did begin cutting back their utilization, and spreads quickly leaped back to a normal level. •

Explosive US Crude Production Growth Continues US crude oil production was continuously propelled higher throughout the quarter, getting a lift from rising oil prices. The EIA expects production to average 12.4 MMbpd over the course of 2019 – more than 10% higher than 2018 levels. Even more impressive, the 1.4 MMbpd yearover-year gain is more than the total increase in global production, meaning that without US production, global supplies would have actually fallen.

Crude oil output rose roughly half a million barrels per day from January through March. The Permian Basin in West Texas/New Mexico continues to be the most productive zone,

US Crude Oil Production accounting for one third of total US output. Some analysts have predicted that Permian output, which surpassed 4 MMbpd in March, could continue rising as high as 8 MMbpd within five years. Pipelines are rushing to keep pace with the huge output growth, and so far constraints have created logistics concerns for the companies producing at breakneck speeds.

Source: Energy Information Administration (EIA)

The first quarter saw crude output rise above 12 MMbpd for the first time in US history, steadily increasing to 12.2 MMbpd by the end of March. Sustaining these production levels will require continued capital investment in the US, though, and investors are growing weary with the oil industry’s inability to turn a true profit. But even the majors are delighted with returns in the Permian. ExxonMobil and Chevron are both committing to more than tripling their output in the region by 2024. •

Fundamentals

US Moves Toward Net Exporter Status – 4 Takeaways

While the US is still importing an average of around 1-3 MMbpd in any given week, energy agencies expect the US to move more firmly into the net exporter category by the end of 2020. This would be a huge accomplishment – for the largest consumer in the world to be quantitatively self-sustaining. Here are four things to know about what it means for America to be a net oil exporter:

1. Nationally, the economy will benefit from higher oil prices

rather than lower oil prices. Of course, the benefit will not be universal. Low oil prices benefit consumers throughout the country, while high oil prices benefits a concentrated few companies and states with heavy production.

The US is still tied to global oil prices. Exporting more than importing won’t mean imports are no longer required. For instance, the Northeast is heavily reliant on imports from Europe and other areas because the existing pipelines do not support heavy flows of US oil into the region. OPEC isn’t out of the picture just yet.

3. Higher production levels will force a rush to build new export

As US crude output rises, producers must find an outlet for their abundant products. While much of the raw material can be refined domestically, a growing portion will need to be exported in the coming months as output rises. In Q1, the US had so much product to export that it shipped out more than was brought in – making the US a net oil exporter for the week of Feb 22, 2019. This was just the second time in US history that the country has achieved net exporter status, with the last occurrence happening this past November. Of course, both events were somewhat random in nature – weekly export data can be heavily influenced by the coming and going of just one or two massive crude vessels.

infrastructure. Today, only one port in the US, the Louisiana Offshore Oil Port, is capable of loading a crude supertanker. That number will have to rise to keep pace with supplies, meaning huge infrastructure investment in the next few years.

4. Unlike nearly every major net exporter around the world, the

US does not have direct state control over its producers. While the government can influence output through permitting, infrastructure investment and taxation, it has far less direct control than countries like Saudi Arabia to influence global prices. For global oil markets, that means less command-and-control style price influence, and more market-based economics. •

US Moves Closer to Net Oil Exporter

Source: Energy Information Administration (EIA)

Fundamentals

EIA Suggests IMO 2020 Diesel Price Spike One of the most significant changes within the oil industry is the approaching IMO 2020 mandate that requires all maritime vessels to reduce their fuel’s sulfur content from 3.5% to 0.5%. The measure goes into force on January 1, 2020, and any attempts to delay implementation have been rejected by the International Maritime Organization.

Early in Q1, the EIA released a report on IMO 2020 and its effects on fuel markets. The EIA is known for its very conservative methodology, put in place to prevent political posturing. Markets were surprised, therefore, to see the EIA predicting diesel crack spreads rising even farther than markets anticipate. According to the EIA, diesel crack spreads will reach 65 cents in 2020 – up from just 39 cents this year. That means that if crude prices remain unchanged for the next two years, diesel prices would still rise over 25 cents by January 1, 2020. Interestingly, at the time of this article, futures markets do not reflect the EIA’s bullish scenario. While the current diesel futures for 2020 show an average price of $2.05, the EIA’s analysis suggests prices ought to be closer to $2.25. Seeing a twenty-cent market inefficiency, many consumers are evaluating fixed price options for late 2019 and into 2020 to mitigate price volatility. As the IMO 2020 implementation date nears, markets are growing nervous about the specifics of the deal. There is still significant uncertainty regarding key details. For instance, as of the end of March, the exact fuel specification for compliant bunker fuel has not been created. Fuel specs require much more than just sulfur requirements. Refineries cannot begin planning reconfigurations until they know what product they’ll be producing. The longer it takes to create this spec, the less low-sulfur bunker fuel will be available, and the more diesel will be needed in the short-term. Additionally, the IMO has hinted at other pollution regulations, which may ultimately lead to non-petroleum fuels being mandated. This creates uncertainty that slows investment – for instance, why should shippers invest in scrubbers if they’ll become obsolete in a few years? If refiners delay reconfigurations, or marine fleets delay scrubber installations, even more volatility in the first few months of IMO 2020 is possible. This presents limited downside price benefit to diesel consumers – as any new mandates would not be implemented for many years – but significant upside risk.

Diesel Prices – NYMEX Futures vs. EIA Estimate

Source: New York Mercantile Exchange (NYMEX), and Energy Information Administration (EIA)

Finally, marine fleets have not been forthcoming with their compliance strategy. Fleets can choose between installing scrubbers, using more expensive compliant fuels (i.e. diesel), or switching to LNG. Because there are many options, companies do not have a first-mover advantage, and therefore have been slow to publish their strategy. This lack of transparency means refiners cannot accurately predict demand – contributing further to price volatility. With many questions left to be answered, the countdown to IMO 2020 is beginning to foster concern for many. While there’s little doubt the market will adapt over time, the key question is how long markets will take to smooth out – whether it will be just a few brief months, one year, or perhaps longer. •

REGIONAL VIEWS Dan Luther, Director, Supply Optimization See his bio, page 34

East Coast

Overview

With warmer temperatures, Northeast refinery production should be more reliable in the second quarter. RFG gasoline in the New York Harbor may get tight given the RVP change, but outside of that, expect a balanced supply and demand situation. •

Northeast Refinery Downtime

PADD 1 Refinery Utilization

The Northeast experienced a spate of refinery downtime during the first quarter of 2019, bringing seasonal PADD 1 refinery utilization to the lowest recorded level in over six years. Unplanned incidents at P66 Linden, NJ and a fire that took nearly six hours to extinguish at PBF Delaware City, DE shut units for multiple weeks at the respective plants. Additionally, extensive planned maintenance occurred at PES’s Philadelphia refinery with multiple units offline for over 45 days. The extent of the overall downtime was severe enough that PADD 1 refinery utilization, effectively the total refining capacity currently operating at the time of measurement, dropped in late February to the lowest level since 2012. •

Source: Energy Information Administration (EIA)

Update on Buckeye’s Laurel Pipeline

Buckeye Partners’ CEO announced in February that he expects the company’s Laurel Pipeline to operate bidirectionally by mid-2019. The company is currently waiting on federal regulators to rule on a tariff petition. Previously, the company expected to change the current flow in Q4 2018. Today the pipeline moves East to West originating in Philadelphia and terminating in Pittsburgh. The change in flow would allow Midwestern refiners to ship refined products further into Pennsylvania with the goal to reach the Philadelphia and New York Harbor area. Northeast refiners are reluctant to let this happen as additional products shipped into their local markets could hurt regional refining margins. • 20

Regional Views

Gabe Aucar, Senior Supply Manager See his bio, page 34

Gulf Coast

Overview

Prices in the Gulf Coast, extending up into the Southeast, showed normal seasonal increases relative to national NYMEX levels throughout Q1. Weather anomalies led many to focus on Florida fuel prices, as barges were at times unable to reach this market. Looking ahead to the remainder of the year, I expect crude pipelines being built from the Permian to Gulf Coast refineries to create ample supply for the Southeast. While the Permian creates ample supplies for Gulf Coast refiners, it will continue to keep steady pressure on West Texas demand, leaving local fuel supplies tight until new fuel pipelines and terminal infrastructure are completed. •

The New Year Sees 5-Year Low GC Gasoline Crack Spreads

U.S. Gulf Coast gasoline crack spreads have been declining since mid2018 and saw 5-year lows in January and February while distillate crack spreads remained relatively high. Crack spreads represent the economic return a producer makes by refining a barrel of crude into its component parts of diesel, gasoline, and other products. The low crack spread is attributed to more costly crude oil inputs and high gasoline inventories. Crack spreads in the Gulf Coast are typically among the world’s highest because Gulf Coast refineries are setup to refine lower-cost heavy crude oils into more valuable refined products, such as gasoline. U.S. Gulf Coast refineries have upgraded equipment such as cokers, allowing them to process very heavy, high-sulfur crude oils which typically cost less than light, sweet crude oils. Since December, though, prices of heavier crude oils with higher sulfur content, which tend to come from volatile regions such as the Middle East and Venezuela, have increased relative to prices of light, sweet crude oils from the US and Europe. The narrowing gap between heavy and light crudes comes on the heels of reduced output from OPEC and Canada and the threat of production disruptions in Venezuela. •

Fog and Flooding Tighten Southeast Diesel Market

The Houston Ship Channel, a key waterway used to ship refined products out of the Gulf Coast, faced closures several times in the last few weeks of Q1 due to fog. January – March brings cooler weather to Houston, yielding long periods of dense fog that can close the Houston Ship Channel as warmer humid Gulf air collides with colder onshore air masses. Dense fog advisories in Houston and Galveston normally peak in the first half of February, according to National Weather Service data. Poor weather caused refined products inventories to temporarily build in the Gulf Coast, while simultaneously causing tightness in barge-fed markets such as Florida. Florida had one of the highest gas and diesel rack prices in the Southeast during Q1. Weather has caused the industry to closely watch various rivers in the Southeast as flooding followed a recent round of heavy rains. River cities such as Memphis and Nashville were seeing the second highest diesel and gasoline prices in the Southeast due to barges not being able to access those ports to unload product. Barge deliveries were able to get back into the ports closer to the end of March. The alternative solution, bringing in product from the Colonial pipeline, is limited because the stub line feeding the Tennessee markets is fully allocated. •

Regional Views

Dan Luther, Director, Supply Optimization

Midwest

Overview

As spring planting gets underway, tight supply and elevated diesel and gasoline prices will continue in the Midwest through the start of Q2 on the back of seasonal refinery maintenance and strong demand from the agricultural sector. Expect a volatile April and early May before refining capacity comes back online. Once the supply situation improves mid-quarter, buyers should see prices drop relative to NYMEX futures. •

Midwest Refineries Freeze Production

The record-breaking Polar Vortex in January had a chilling impact on Midwest refinery production in the first quarter. Some of the largest midcontinent refineries experienced unplanned downtime, leading to higher regional prices on fears of reduced supply. In the span of just a couple weeks in late January and early February, weather-related issues struck BP Whiting, IN, P66 Wood River, IL, Citgo Lemont, IL, BP/Husky Toledo, OH, Marathon Detroit, IL, and Imperial Oil Sarnia, ON.

Chicago Wholesale Fuel vs NYMEX

Extreme cold weather can wreak havoc on a refinery’s complex operations. For instance, water and steam systems are susceptible to freezing. Additionally, if crude oil is not kept hot enough, particularly heavier Canadian grades, it may become harder to process and move through the plant. As a result, the Midwestern refineries using cheaper heavy crude oil are also the most susceptible to problems with freezing. As a result of the downtime, buyers in the Midwest experienced bitter price increases for both gasoline and diesel. From mid-January to early February, Chicago diesel increased by nearly $.30 per gallon while Chicago gasoline increased just shy of $.25 per gallon relative to the NYMEX. •

#1 ULSD Supply in Michigan

The historic cold caused an especially frosty situation for buyers of #1 ULSD in Western Michigan. In early February, low temperatures were blamed for knocking offline Marathon’s Detroit, MI refinery, which is an important supply source for the Great Lakes region. In particular, Marathon is a key supplier of #1 ULSD to the region. Many diesel consumers blend #1 ULSD during extreme cold temperatures given the fuel’s better cold weather operability. As a result, buyers in Western and Central Michigan were left sourcing #1 ULSD at higher prices from surrounding markets.

Source: Oil Price Information Service (OPIS)

Detroit, MI #1 ULSD vs. Chicago Trading Hub

The day after the mishap at the refinery, the premium for #1 ULSD in Detroit versus the regional trading hub jumped $.07 per gallon in one day—then another $.05 the next day. The delta remained at elevated levels until Marathon resumed production in early March. • 22

Source: Oil Price Information Service (OPIS)

Regional Views

Nate Kovacevich, Senior Supply Manager See his bio, page 34

Rocky Mountain

Overview

Q1 saw the Rocky Mountain region’s fuel prices gradually move higher as seasonal forces took hold. It’s common for basis to see an approximate 10cent bump throughout Q1 as the few refineries in PADD 4 go offline for seasonal maintenance. This season’s prices rose somewhat faster than usual, with the region generally trading below the NYMEX for most of the quarter. Looking ahead, seasonal trends suggest that local prices will steadily climb over the summer, falling after seasonal activity ends and trending lower in the back half of the year. As oil prices continue to rise, expect drilling activity in the mountain region to put some pressure on local diesel prices, perhaps causing higher-than-usual basis levels if crude remains elevated. •

Pacific Northwest Diesel Basis

Source: CME Group

Drilling Activity Recovering in Wyoming, Stalling Out in Colorado The latest data coming from Baker Hughes’ weekly drilling activity report shows Wyoming has recently overtaken Colorado in the number of active drilling rigs. The Baker Hughes data is a leading indicator for the petroleum industry and its suppliers. The more drilling rigs that are active, the more products and services they are consuming (i.e. diesel fuel).

At the beginning of 2018, Wyoming had 26 active rigs while Colorado had 34. To put this into context, Wyoming was sitting at 56 active rigs at the beginning of 2015. In the middle of 2014, crude was trading for $104/barrel, and the shale oil boom was well on its way, leading companies to secure leases and begin drilling in a number of shale plays across the country. Colorado was also a part of the boom, beginning 2015 at a very healthy 66 active drilling rigs. Like many booms, 2014 was followed by a bust. In the case of crude oil prices and drilling activity, both fell sharply from their respective peaks. Crude dropped to a low of $26/barrel. Rig activity in Wyoming fell to a low of 7 rigs and Colorado dropped to 15 in 2016. As crude oil prices recovered, so did the oil services and drilling community. Rigs began to slowly come online in 2017 and 2018 as crude prices steadily marched higher. While activity in the Mountain region remains relatively muted compared to the 2014-2015 timeframe, things appear to be headed in the right direction. Wyoming has seen some strong year-over-year growth in activity, though drilling in Colorado has been stagnant. Recent legislation passed by a Senate committee in Colorado in early March overhauled the State’s oil and gas industry. Provisions in the bill 23

give local governments more authority to control siting wells, including inspections, and allow cities and counties to push through stringent rules that may hamper future oil and gas development. Critics of the bill say its effects could be worse than Proposition 112, which would have required new oil and gas wells to be at least 2,500 feet away from homes, schools, and water sources. That proposition was on the Nov 6th ballot, which was rejected by Colorado voters.

In any case, the regulatory environment will continue to be a challenging headwind for oil activity in Colorado, which could lead to more companies moving their drilling activity to opportunities in Wyoming. This could lead to a continuation of the 2018 trend of upward movement in Wyoming activity and a sideways to lower move in Colorado. Now, what does this all mean for the products that will impact your business? One would expect that diesel demand in Wyoming should increase, which should put upward pressure on diesel prices. In 2018, we saw how fragile the Mountain region can be when impacted by refinery issues. Diesel spent most of the year 10-15 cents higher than the national average. Although drilling activity in Colorado is lower, don’t expect diesel prices in Denver Metro to be lower relative to the rest of the Mountain region. Supplies that would have headed to Denver may now be redirected to satisfy increasing Wyoming activity. It’s all connected – an uptick in demand in any area puts further pressure on the industry to keep up with supply. This can be challenging during a year of high maintenance or unexpected disruptions.•

Sara Bonario, Supply Director See her bio, page 34

West

Regional Views

Overview

PADD 5 fuel markets are expected to behave consistently with historical patterns for the region as we complete spring RVP gasoline blend down and planned refinery maintenance. As peak driving season approaches, expect refiners to maximize their returns by operating at high utilization rates. While the focus will be on maximizing gasoline production which is net short in PADD 5 markets, diesel fuel production will also increase as a result of high run rates. Diesel fuel, which is net long in the region, will compete with gasoline for the limited pipeline and marine infrastructure available to move product within PADD 5 to balance stocks.

This is expected to result in an abundance of diesel fuel available in markets where a concentration of refineries exist, such as Northern and Southern California. Diesel fuel streams are likely to be exported from PADD 5 over the summer to balance supply. Watch for news of refinery disruptions or unplanned pipeline issues to guide fuel purchase decisions. Short term supply disruptions limiting supply often cause rapid price spikes and the duration is extended relative to other regions which are more readily connected to one another. •

IMO 2020 Affects the West Coast

IMO 2020 regulations, which go into effect on January 1, 2020, are expected to be positive for coastal market refiners while pressuring prices for consumers. The regulation requires all maritime vessels to go from 3.5% sulfur down to 0.5% sulfur, meaning refiners will have to do more work to extract sulfur. The policy change will require more middle distillates (diesel) be blended with higher sulfur fuels to meet the spec. The West Coast is extremely isolated from the rest of the country’s fueling infrastructure. Pipelines tend to go out from California, but none bring fuel to the state. With more diesel demand but no increase in diesel production, markets could be tipped out of balance. While California does currently have sufficient diesel stocks, increased demand from IMO 2020 could strain local supplies. •

Southwest Shortage Disrupts Fueling

As the quarter came to a close, the Southwest experienced some extreme supply tightness, leading to outages in some areas. Reduced refinery production in LA, paired with pipeline maintenance and delays on the Kinder Morgan East and West lines, impacted product availability in Southern California and Arizona. The LA refinery group, composed of eight refineries cumulatively processing 1.2 MMbpd of oil, could not get products to local terminal markets, reducing availability. • 24

Regional Views

Nate Kovacevich, Senior Supply Manager

Canada

Canadian Oil and Gas Outlook Significantly Deteriorated, per IEA The International Energy Agency (IEA), in its annual oil market report published in early March, painted quite a different a picture of Canada’s oil and gas landscape than that of one year ago. Last year, analysts were unsure whether Alberta had enough takeaway capacity to keep up with the rapid growth in oil sands activity. Pipeline companies were expected to build new lines to take away the vast amounts of Canadian crude. That supply situation, however, failed to hold.

Massive discounts on Canada’s WCS crude oil in late 2018 left the oil industry reeling, and the Government of Alberta ordered a production cut to relieve pressure on the supply bottleneck. Unfortunately, this shaky regulatory environment forced many oil pipeline companies to abandon plans to build the necessary infrastructure, which would have sufficiently increased takeaway capacity. Oil companies are now reluctant to invest in future production projects, fearing new oil supply would face the same issues which caused WCS to trade at a $50 discount to WTI back in 2018.

Unlike the outlook for Canada’s southern neighbor, where supply has jumped significantly over the past 12-18 months, the outlook for Canada’s supply growth is pretty grim. The IEA forecasted that Canadian oil supply would reach 5.5 million barrels per day in 2024, which represents just a 300,000 barrel increase from the average in 2018.

It will be interesting to see how Canadian refineries respond to the downtick in activity. They benefited from cheaper crude oil pricing in 2018, which allowed them to capitalize on export opportunities into the US for refined products. However, since the Alberta government cut production last year, the discount to WTI has fallen to just over $10 per barrel. While pricing has improved for producers, it’s still not enough for them to reinvest into new projects. Canadian producers continue to fear that any new production will be met with the same challenges seen in 2018. •

A LT E R N AT I V E F U E L S Sara Bonario, Supply Director

RENEWABLES In early December 2018, the Environmental Protection Agency (EPA) temporarily delayed consideration of any new small refinery waiver applications from Renewable Fuel Standard (RFS) program requirements. The Department of Energy (DOE) was set to review the scoring system it uses to evaluate waiver applications.

The expansion of the waiver program has angered farmers and producers of biofuels because the announcements crushed credit prices (RINs) which are an important component of the ethanol and biodiesel industry, often determining the profitability or solvency of producers.

Under the waiver process, the DOE evaluates the waiver requests and provides recommendations to the EPA. Small refineries may be exempt from RFS requirements if they prove that “compliance would cause disproportionate hardship.” The DOE has traditionally considered whether a plant would remain viable if required to comply. Prior to May 2017, a refinery would have to pass both tests to get an exemption. The determination of how this process changed and the legality of same has been an ongoing legal battle. Documents were filed by the Advanced Biofuels Association (ABFA) in early March 2019 challenging the new process, which has dramatically increased the number of exemptions granted from seven in 2015 to at least twenty-nine in 2017.

On March 14, 2019, the EPA announced the exemption of the balance of the 2017 SRE's requested, granting five more exemptions, which affected an additional 360 million RINs. ABFA, which represents thirty-five companies responsible for 4.4 billion gallons of renewable fuel production around the globe, is asking a federal judge to rule whether the EPA’s expansion of the waiver program was legal, which they argue depresses demand for their biofuel. The 2018 SRE announcement is being watched closely by market participants. The EPA is set to decide on thirty-seven additional pending applications for 2018 waivers. •

2018 RINs Prices

Source: Argus

Alternative Fuels

Martin Trotter,

NATURAL GAS

Pricing & Structuring Analyst

Regional Natural Gas Flows To and From Eastern Midwest Region (1990 –2050)

See his bio, page 34

SUPPLY:

In March, EIA data confirmed that natural gas production in the United States reached record highs for calendar year 2018. Increased natural gas production was accompanied by continued export growth, both in the form of pipelines and liquefied natural gas.

Billion cubic feet per day

Currently, regional supply and demand relationships continue to mature as well. The Appalachia region continues to be the largest regional producer of natural gas in the US. While traditionally trading at a discount to the national average due to fewer outlets, gas from the Appalachia region now finds many paths to new homes through increased pipeline capacity and bidirectional flow. As one of the fastest growing domestic demand markets, Texas and the Gulf Coast region have become major bidders for the domestic exports from the Appalachia region. Demand in the Gulf Coast and South Central region continues to outpace local production, driven largely from increased LNG exports. •

Sources: U.S. Energy Information Administration, Natural Gas Annual and Annual Energy Outlook 2019 Reference case

DEMAND:

After the early November cold snap in the Midwest threw the natural gas markets into a frenzy, many wondered whether winter would rear its head again. Historically low storage inventories sent prices skittering at any change in weather expectation. It took until the end of January, but winter showed up in a big way. Temperatures in the Midwest dropped as low as – 45⁰ F in some places. Heating Degree Days (HDDs), a common indicator of natural gas demand, reached a record 81.5 on that day, and averaged 73.8 over the three day period ending January. Demand for electricity on January 30th did not set a record, but the corresponding natural gas demand did. New demand response techniques mitigated record electricity usage, while increased use of natural gas over coal pushed demand over the previous record events.

Average Departure from Normal Temperatures on January 30, 2019

While demand moved wildly, the scare of previous events and the early November bump in prices likely played a role in limiting price volatility in the cash markets. Delivered prices into Chicago citygates traded north of $9/dth during the surrounding trading session, and while that’s the highest level in years, it’s a far cry from the $30-$45/dth traded in 2014. •

Sources: U.S. Energy Information Administration, (EIA) based on National Oceanic and Atmospheric Administration data

Alternative Fuels

NATURAL GAS

STORAGE:

Colder than normal temperatures in Southern California resulted in substantial depletion of the region’s nat gas storage throughout the quarter. Temperatures in the area averaged more than 5 degrees colder than the 30-year average during February. The colder weather drove demand up and broke a nearly 10-year record for demand in the month. Pipeline constraints in the area caused storage withdraws to reduce inventory by over 30% over the time period. Demand was so great that SoCal implemented multiple demand response measures, including curtailing the use of natural gas for power generation and leaning on the Aliso Caynon storage facility. Deemed an “asset of last resort” following regulatory restrictions in the fallout of the 2015-16 leak, SoCal Gas filed a motion to withdraw from Aliso, as their unrelated storage assets would not be enough to meet demand. SoCal’s storage picture resonates nationwide. Through March, total storage inventories equaled 1,143 bcf, over 30% below the five-year average with further withdrawals likely before heading into injection season. •

Working Gas in Underground Storage Compared with the Five-year Maximum and Minimum

Note: The shaded area indicates the range between the historical minimum and maximum values for the weekly series from 2014 through 2018. The dashed vertical lines indicate current and year-ago weekly periods.

Southern California Natural Gas Storage Inventory

Source: U.S. Energy Information Administration, (EIA) Source: U.S. Energy Information Administration, (EIA): SoCalGas, ENVOY

VIEWPOINTS By Nikki Booth, Senior Logistics Manager, Carrier Relations

Impact of Fuel Prices on Logistics

After declining at the end of 2018, fuel prices are beginning to creep back up in Q1. Much time is spent prognosticating on fuel price direction, yet the effects of price fluctuations are not always clear. Unsurprisingly, the consistent variability of fuel prices has a direct impact on the logistics industry. Rising fuel prices present a challenge for freight management companies, as rising costs typically force carriers to either raise prices or suffer financial losses. When carriers raise rates, that increase is eventually passed along to the consumer as higher prices on goods and greater transportation costs.

must keep up. With a driver shortage already pressuring trucking companies, additional demand is hard to absorb. Logistics companies not ready to take on new volume may lose market share to competitors with more spare capacity. Fuel prices are constantly changing, and the volatility keeps the logistics industry on its toes. To manage fuel price fluctuations, logistics companies can focus on improving their operations and finding efficiencies that enhance service levels. If they have a lower risk appetite, they may also choose to lock in their fuel price risk exposure to guarantee their budget numbers for the year. •

Higher prices create a ripple effect throughout the economy. By pushing up prices of key consumer goods, higher energy costs end up in government inflation data, which informs Federal Reserve policy and, ultimately, interest rates. Ironically, higher inflation and interest rates have an inverse relationship with prices, meaning higher fuel prices ultimately influence factors that cause prices to return to lower levels.

On-Highway Diesel Fuel Prices

Higher prices are also not felt uniformly throughout the world, which can disrupt the direction of trade flows and force logistics companies to pivot their strategies. For instance, when oil prices are high, some countries – especially developing economies – subsidize oil prices, keeping energy costs lower for domestic producers. This can artificially spur exports from those low-energy-cost countries that may otherwise not have been a market leader. Finally, higher energy costs bring higher interest costs for those dealing in energy products. When fuel prices rise from $2.00 to $3.00 per gallon, interest costs rise 50% – even though no more fuel is trading hands. This can be a double whammy for logistics companies with higher interest expenses, who not only face higher fuel costs but also extended credit terms. Since fuel is a top operating expense for most logistics companies, this can be a significant additional cost. On the flipside, declining fuel costs make most goods cheaper – which can be both a blessing and a curse. Cheaper goods mean stronger economic demand, which in turn can strain logistics companies that 29

Source: U.S. Energy Information Administration, (EIA)

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 Amy Macaulay, Marketing Manager, O’Rourke Petroleum

Improve Fuel Economy Potential with Lower Viscosity Engine Oils

Fuel represents a large operating expense for commercial fleets. Fleet managers know, however, that the life force of their businesses is their vehicles. Any unplanned downtime, increased maintenance costs, or fluctuating fuel costs will have a direct impact on a company’s efficiency and profitability. These same fleet managers, in an effort to see immediate cost savings, often select lower cost lubricants. However, the long term effect on equipment can prove more expensive when considering a total cost of ownership model. Selecting the right lubricant can offer bigger cost savings over time through reduced maintenance costs, minimized downtime, extended drain intervals, and improved fuel economy. Fuel economy targets and associated penalties continue to become increasingly important and are driving current industry trends. For engine manufacturers as well as fleet owners, there is a constant need to improve heavy duty diesel engine fuel efficiency. High quality engine oils, by delivering excellent equipment protection and fuel efficiencies, have a critical role to play as an enabling technology. A Manfield Energy Company.

O’Rourke Petroleum

TOTAL PETROLEUM MANAGEMENT Fuel

Lubricants

www.orpp.com

With the most recent PC-11 and CK-4 engine oil standards, the move toward greater energy efficiency and improved fuel economy is well under way. These standards require lighter viscosity oils that deliver improved mileage and lower emissions. The lighter viscosity diesel engine oils, by their composition alone, use less energy in the combustion cycle, leaving more energy to expend on the road. The result is lower fuel consumption and lower cost per mile for the fleet. Engines have to work harder to circulate thicker, heavier viscosity oils through the system. Because of the added stress to fuel pumps—especially during warm-up cycles—and the added drag on oil flow, fuel efficiency is negatively impacted, making the case for lower viscosity oils. However, to help ensure increased fuel economy without compromising overall protection, the latest low viscosity heavy duty diesel engine oils need to deliver the exact same wear protection and oil life as their thicker counterparts. By decreasing engine friction and offering exceptional flow characteristics, low viscosity, fully synthetic engine oils can help support engine efficiency, enhance fuel economy potential, and allow the equipment to maintain diesel fuel economy throughout its life. Depending on the number of trucks in a fleet and total miles driven, a small increase in fuel economy can result in large fuel savings each year. In studies conducted by Shell Lubricants and Warren Distribution, fleets see fuel economy improvements of 1-4%, sometimes more, when they change from 15W-40 heavy duty conventional engine oils to 10W-30 conventional or upgrade to a synthetic blend or full synthetic heavy duty motor oil. These slight improvements can go a long way with heavy duty trucks and fleets. In a report on the topic, John Walters, Shell Lubricant’s Global Sector Manager for Fleet, said, “With fuel costs amounting to as much as 39% of total fleet operating costs, a lubricant that helps deliver even a small increase in fuel efficiency has the potential to greatly impact total cost of ownership.” •

800.683.1331

Select Environmental Services Marine Fueling and Dockside Services Locations: Houston, TX | Dallas-Fort Worth, TX | Tyler, TX | Beaumont, TX | Midland-Odessa, TX

Amy Macaulay Marketing Manager, O’Rourke Petroleum Amy provides strategic leadership for all aspects of marketing at O’Rourke Petroleum. Prior to O’Rourke Petroleum, she worked in various marketing positions for several companies in oil and gas and environmental technologies. Amy holds an MBA from Rice University.

Viewpoints By Brian Hutchinson, Account Executive

Trading Nickels for Dimes: Increase Your Fleet Program’s Bottom Line For most businesses, raw material cost is only half the battle. Labor, compliance, shrinkage, data organization – you name it, all carry an additional, hard to quantify price tag. Historically, managers chalked these expenditures up to “just the cost of doing business,” given the difficulty to track and manage; that is no longer the case. Bottom lines beg to be bigger, budgets continue contracting, and soft and hard cost savings are coming into focus.

An important distinction must be made between price and cost. Your fuel price is often an index differential: “OPIS Low plus” or “Retail Minus.” Price is evaluated by pennies – or sometimes fractions of a penny. Your cost, on the other hand, is made up of dollars, gallons, and hours. While receiving a competitive fuel price is crucial, there are far more savings to be found in managing costs. The age old expression “You get what you pay for” is often thought to be irrelevant and is frequently disregarded in the world of common commodities like fuel – after all, isn’t all diesel the same? This point of view is also changing. As businesses become more complex, and outsourcing more economical, the road to fuel program efficiency ironically begins to straighten out. The era of the value based “one-stop shop” fuel supplier is emerging. As we consider the best practices of fleets who optimize their total cost of fueling, a common foundation persists: the universal vehicle card.

PRICE COST

Acceptance, Flexibility, Optimization

Many Americans carry multiple credit cards to optimize their cash back rewards; in the same sense, fleet managers continuously evaluate the most efficient ways to fuel their vehicles. Often managers must choose between complex multi-mode fuel programs (retail, bulk tank, and mobile fueling) and higher-cost single mode programs for the entire fleet. Either of these options may leave significant money on the table, money that could have fallen to the bottom line. 31

Viewpoints The emergence of the universal fleet fueling card has resolved this conflict and revolutionized both regional and national fleets. Universal Fleet Cards can be used for any type of purchase – bulk tanks, retail, or mobile fueling – with every transaction reported in one centralized portal. A universal card allows companies to easily optimize their fueling based on price and convenience, without sacrificing accurate data or spending countless hours organizing, consolidating and managing multiple files and vendors. Over-the-road vehicles frequently traveling out-of-route to a backyard bulk tank may now use a single card to fuel either at a backyard tank or at the closest retail location. Units that are wet hosed overnight can make unanticipated fill-ups during the day without disrupting the integrity of their fueling data. Fleet managers can select a default fueling method, ensure seamless back-up fueling method options, and forego the internal cost of managing multiple programs and vendors – all through a single universal card. Recent analysis of a midsized county in Tennessee resulted in $150,000 of annual soft and hard cost savings by expanding their card program from bulk tank/cardlock fueling to also incorporating retail locations. The following cost saving items were realized: • Eliminated 40 minute return trip to bulk tanks to fuel during the day • Increased productivity in the field by 30 min per day per vehicle • Saved 2.5 gallons/day/vehicle by eliminating the return trip • Reduced maintenance, mileage, and depreciation on each vehicle affected

Administrative Efficiency

As the terms “value” and “soft cost savings” become more synonymous, “efficiency” begins to etch its way into every fuel program administrator’s rubric for vendor evaluations. When searching for the optimal energy and fuel supplier, businesses expect more bang for their buck. Fortunately, vendors like Mansfield have found ways to deliver these expectations through programs such as the universal vehicle card. By consolidating all fuel purchases with one vendor in one portal, fuel providers have easy access to your data and can make short work of custom reporting, software integration, and program adjustments. Perhaps the most valuable aspect of a universal card program is customer’s access to their own data and custom report generation tools. Without having to synthesize multiple reports, consolidated programs strip out the legwork in consolidating your fueling facts and figures. The “one-stop shop” generates thousands of dollars in hard and soft cost savings, allowing businesses to spend the saved labor, time, and energy on completing higher ROI tasks. Fleet managers and administrators used to spend an inordinate amount of time merging excel sheets from various business units for the mere purpose of aggregating data. Now customers can have consolidated, actionable data insights at their fingertips to make better informed business decisions. Once you begin using the universal fuel card, you can begin analyzing, shaping and presenting data in ways that deliver value to your organization, erasing countless hours of labor cost and days of turnaround for reporting. The fear of additional soft cost expense from managing a multi-mode fueling program has been eliminated.

Viewpoints

Checks and Balances

Of course, as businesses begin to roll out this cost optimizing universal card tool, there will be new and different challenges to address. Drivers may accidentally pay retail prices when a bulk facility is right around the corner. At worst, fuel theft may occur if transactions are not monitored. How do companies address these new concerns? Managing your fleet’s new freedom and flexibility is quite simple. There are dozens of parameters fleet managers are able to flag for breach notifications: time of day, day of week, dollar limits, tank capacity, mileage variation – all the way down to locking out that corner store with 10 cent higher fuel prices. A universal card program, which can be used at backyard tanks, retail truck stops, or for mobile fueling, was created to marry cost optimization with actionable data. The simplicity of a single card program covering any and all fueling needs of a fleet was long overdue. The era of data driven fleet fueling is here. • Brian Hutchinson Account Executive Brian leads Mansfield’s public sector sales efforts of multi-service based programs in which his key responsibilities include designing and expanding comprehensive fuel programs. Brian currently manages many of Mansfield’s largest and most complex government customer contracts. Before his appointment to a government services Account Executive, Brian worked as a business development specialist for Mansfield’s commercial sales team.

www.mansﬁeld.energy

Better Insights Reduced Costs The Mansfield Fleet Card Program is an effective fuel management solution for fleets of any size. LOWER FUEL COSTS | IMPROVED CONTROL & SECURITY | INCREASED CONVENIENCE Mansfield Energy partners with leading fleet card networks to design the optimal card solution for your specific fleet or locations. With acceptance at locations nationwide including retail stations, cardlocks, truck stops, backyard tanks, and mobile fueling locations, Mansfield has the card of choice for your business.

Contact Mansfield Today

866.275.7338

fleetcards@mansfieldoil.com Ask for a complimentary fuel spend analysis to identify opportunities to reduce your fuel costs.

Mansfield 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 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

Sara Bonario

Andy heads the supply group for Mansfield. During his tenure, the company has grown from 1.3 billion gallons to over 3 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. •

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. •

Senior VP of Supply & Distribution

Supply Director

Gabe Aucar

Senior Supply Manager

Gabe manages Mansfield’s southeast fuel procurement team with responsibilities for supply contract negotiations as well as providing trading and business development expertise. Gabe holds an MBA from Pace University and has over 12 years’ experience in the energy industry. •

Nate Kovacevich Senior Supply Manager

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

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. •

Alan Apthorp

Dan Luther

Chief of Staff

Director, Supply Optimization

Alan is the lead author and editor for FUELSNews Daily and FUELSNews 360. He is responsible for providing insights to the executive team, including market trends and analysis. Before his appointment to Chief of Staff, Alan worked in data analysis and visualization as a Market Intelligence Analyst. •

Teamwork

•

Innovation

•

Integrity

Dan manages Mansfield’s Great Lakes and Northeast fuel procurement teams with responsibilities for supply contract negotiations, bulk inventory purchases, and hedging. Dan holds an MBA from Georgia Tech University and a BSBA in Supply Chain Management and Marketing from Ohio State. He has over 13 years’ experience in the energy industry. •

Excellence

•

Conscientiousness

•

Personal Ser vice

Download Our App Android Market

* Some of the information provided is owned and licensed by OPIS. In no event shall any user copy, modify, publish, retransmit, or otherwise reproduce information from OPIS. Copyright 2019. All rights reserved. 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.

FUELSNews 360° M A RKE T N EW S & IN FORMATION

Mansfield Energy Corp www.mansfield.energy www.fuelsnews.com 678.450.2000 1025 Airport Pkwy SW Gainesville, GA 30501 United States of America

Teamwork • Innovation • Integrity • Excellence • Conscientiousness • Personal Ser vice