FUELSNews 360 - Q1 2016 by FUELSNews

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Table of Contents FUELSNews 360° Quarterly Report Q1 2016 FUELSNews 360°, published four times annually by Mansfield Energy Corp., analyzes and summarizes the prior quarter’s activity in the oil, natural gas and refined products industries. The purpose of this report is to provide industry market data, trends and reporting both domestically and globally as well as provide insight into upcoming challenges facing the energy supply chain.

Executive Summary

Overview

1st Quarter Summary

23 26

Global Economic Outlook

PADD 3, Gulf Coast Commentary–Dan Luther

U.S. Economic Outlook 32

PADD 4, Rocky Mountain Commentary–Nate Kovacevich

Bulls Find Footing in Falling Crude Oil Production Refined Product Inventories Exceeding 5-year Averages

PADD 2, Midwest Commentary–Dan Luther

Fundamentals

PADD 1B & 1C, Central & Lower Atlantic Commentary–Chris Carter

Economic Outlook

PADD 1A, Northeast Commentary–Evan Smiles

January through March, 2016

Regional Views 20

PADD 5, West Coast, AK and HI Commentary–Matt Elder

36 38

Alternative Fuels 38

IEA Calls the Bottom While Warning of Middle East Price War

Canada

Renewable Fuels Commentary–Jessica Phillips

U.S. Refining Buoyed by Domestic Crudes and Distillate Export Markets 46

Natural Gas

Electrical Power

Transportation 46

Transportation Logistics

Mobile Refueling for DEF

FUELSNews 360˚ Supply Team

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Q1 2016 Executive Summary As Q1 of 2016 has established, this will be a difficult year to predict crude oil prices and a good year for contrarians. Several conflicting global crude oil discontinuities converged into clearer view as we exited 2015 and moved into 2016. These discontinuities are locked in a tug of war to establish a “new normal” crude price and global supply/demand equilibrium. Bearish crude oil realities dominate the news cycle. Iran is re-entering the world crude markets (amid indications that Iran has ambitious goals to ramp crude production) while Saudi Arabia is pumping crude at record levels to drive out higher-cost producers in the Americas. Record crude inventories are building around the world and U.S. crude production continues near record levels despite the decline in active wells. All this bearish news is occurring against a back drop of softening Chinese demand. So, why, against these headwinds, has crude oil rebounded off its $26 low in February to find a footing in the high 30s – low 40s in early April? Two words—”Bullish Sentiment,” stemming from several factors: production degradations in the UAE, Nigeria and Iraq; decreased North American drilling amid the rapid decline in rig counts (down 50% from one year ago, and 80% from 2014); numerous shuttered wells (for the time being anyway) in U.S. shale plays; weakness in the U.S. Dollar; and a rumored (but unrealized) crude oil production freeze by the Russians, Saudis and other Middle Eastern countries. While bearish realities are more visceral and real than bullish sentiment, the bulls have lent early support to a gradually emerging global supply-demand balance that is forecast later in 2016. Domestically, the U.S. oil industry is a tale of two nations. Upstream, tens of thousands of jobs have been lost in the oil and gas sector as unemployment in that industry approaches ten percent. Downstream, refineries are running flat out as robust domestic gasoline consumption and exports (9.75 million b/d in March—a record high for the month) have not kept pace with falling gasoline inventories (11-million barrel decline in March). Gasoline supply/demand realities have helped support domestic gasoline crack spreads and prices over the past twelve months. As refiners maintain gasoline production to meet demand, distillate has been dragged along for the ride with inventories increasing despite slightly growing distillate consumption and exports. High distillate inventories, combined with near five-year peaks in distillate production, have depressed ULSD prices and crack spreads in Q1 with the average ULSD crack spread dropping to 25 cents/gallon in March, the lowest March crack spread since 2010. Strong gasoline consumption and exports should keep refineries running at record levels, maintaining refined products output and inventories. This, of course, is good news for ULSD buyers as increased distillate inventories work to moderate prices in 2016. However, concurrently global crude oil supply/demand should find a balance in 2016. With balanced crude oil supply and demand, we anticipate crude oil prices will firm-up, which will lead to firming distillate prices as well. So, enjoy low ULSD prices in the first half of 2016, but prepare for what will most likely be firming crude and refined product pricing later in the year.

Overview January 2016 through March 2016 WTI Crude Futures dollars per barrel

Source: New York Mercantile Exchange (NYMEX)

The first quarter of 2016 began with a weakening of the futures market, as poor economic news from the end of 2015 and a mild winter depressed prices. Crude supplies continued to expand, as Iran re-entered the market determined to restore production levels to their pre-sanctions levels, and other OPEC countries continued to pump at high levels. OPEC output jumped 280 kbpd in January. WTI futures values dropped below $30/b in February. Oil stockpiles were brimming, and forecasts of demand growth were trimmed. It seemed possible that crude prices could spiral down to $20/b. In the U.S., stocks of crude oil passed 1.2 billion barrels for the first time in history.

With the world seemingly awash in oil, Saudi Arabia, Russia, Venezuela and Qatar stepped in with a proposal to cap oil output at January levels. Admittedly, these were high levels, but the proposal set off a rally. Crude prices climbed back to the high $30s and even low $40s in March. From a barrel perspective, since an agreement was not reached at the Doha Meeting on April 17, the cap remained non-binding. From a market psychology perspective, however, the talks have demonstrated that the producers first, are watching the market, second, will take action if prices dip too low too fast, and third, are staying the course to shut in higher cost producers, particularly those in North America. â&#x20AC;˘

Overview First Quarter Summary Summary, 1st Quarter 2016 $1.1816 $1.4223

$38.68

17685.09

Source: New York Mercantile Exchange (NYMEX)

The crude price rally was quickly reflected in product markets. RBOB (gasoline) futures ramped up quickly and surpassed diesel prices. Winter temperatures in much of the Northeast and Ohio Valley had been mild, which reduced heating oil use and encouraged travel. RBOB prices rose above $1.40/gallon in early March and remained in the $1.40 – $1.50/gallon range for the rest of the month. Diesel prices, which had slumped to $0.90/gallon in January, recovered to the $1.15 – $1.25/gallon range in March. At the retail level, gasoline prices at the end of the quarter averaged $2.066/gallon, 38.2 cents per gallon less than a year prior. Retail diesel prices averaged $2.121/gallon, 70.3 cents per gallon less than in the previous year.

Like crude inventories, product inventories reached lavish levels. Domestic distillate inventories soared well beyond their seasonal averages as refiners aggressively pursued cost-advantaged barrels for their lucrative gasoline outputs and the usual distillate dumping grounds in Europe rapidly filled to capacity. Distillate inventories of 160 – 165 million barrels were at five-year highs. Gasoline inventories also reached record heights, swelling to nearly 259 million barrels in February. End-March stocks of approximately 243 million barrels were higher than end-March stocks in all years extending back to 1990, when the EIA first started reporting gasoline stock levels. •

IIIII II

Global Economic Outlook

IIII II I

As this issue of FUELSNews 360° goes to press, the International Monetary Fund (IMF) has just released its April 2016 World Economic Outlook (WEO). While the news is not all bad, it is significant that the headline is “Too Slow for Too Long.” The baseline projection for global growth is 3.2% for 2016, in line with 2015, but 0.2% less than was forecast in the January 2016 WEO. Among the reasons cited were China’s slowdown and weak commodity prices. Last year’s growth was 3.1%, and the group had looked for better growth this year than the revised forecast of 3.2%. The IMF has in the past considered growth of 3.0% to be a technical recession.

GDP, Constant Prices, Percent Change

As always, oil prices play a key role. Low oil prices have lengthened recessions in Russia and Brazil, and they have slowed growth in other oil exporting countries, including Saudi Arabia, Nigeria, Venezuela and Canada.

Source: International Monetary Fund

According to the IMF, uncertainty has increased, and the “risks of weaker growth scenario are becoming more tangible.” The IMF projects that the recovery will strengthen in 2017, which is driven mainly by emerging economies. Its theme of “too slow for too long,” however, included concern over the slowdown in capital flows to emerging markets. Still, the IMF believes that there are many policy actions available, across the globe, to strengthen growth. 8

According to the World Bank, gross national income (GNI) per capita grew at 5.1% per year from 2004 to 2014, growing from $6,584 in 2004 to $10,799 in 2014 (constant U.S. dollars). The gap between rich and poor is a constant concern. In North America, the GNI per capita was $54,879/capita, versus only $1,646/capita in Sub-Saharan Africa. However, the rates of economic growth in North America have lagged other world regions. Many

developing countries experienced double-digit growth in GNI per capita during the 2004 – 2014 decade. The following figure indexes GNI growth since 2004. The greatest rates of increase have been in Sub-Saharan Africa, Latin America and the Caribbean, and the Middle East and North Africa. In these regions, GNI per capita in 2014 was approximately 2.5 times as much as it was in 2004. These are the regions that have raised the world’s growth rate.•

Indexed Growth in GNI by Region, 2004=1.00

Source: World Bank

IIIII II

IIII II I

As the U.S. economy moves into 2016, the overall feeling is that of a country almost recovered from recession, but with a lingering sense of caution. As the following figure illustrates, unemployment remained stubbornly high from 2009 through 2014. It peaked at 9.6% on average in 2010. Last year, unemployment averaged 5.3%. Data for the first quarter of 2016 show that unemployment has fallen to 4.9%, just 0.3% higher than it was in 2007.

U.S. Economic Outlook Average Unemployment Rate (16 years old & above)

Source: Bureau of Labor Statistics

The first quarter of 2016 also brought a collapse, then a quick rally in crude oil prices, alongside a strengthening then weakening U.S. Dollar, as shown below. The Federal Reserve Bank in December 2015 lifted rates for the first time in nearly a decade, signaling its faith in the strength of the economy. Since then, however, the progress has leveled off. Federal Reserve Chair Janet Yellen stated that the policy would be to “proceed cautiously.” At its meeting in March, the Fed announced that it now forecasts two quarter-point increases in the coming year rather than the four it had initially planned. Some officials warned of “appreciable” risks to the economy depending on the timing of the next rate increase.

U.S. Dollar Weakens, Crude Oil Rallies

Source: DTN ProphetX

The Consumer Sentiment Index dropped three months in succession after hitting 92.6 in December 2015. It fell to 92 in January, 91.7 in February, and 91.0 in March. This indicates a bit more consumer caution, though it shows a far rosier sentiment than was seen in 2008 – 2011, when the index bumped along in the range of 55 to 75.

Consumer Sentiment Index Consumer Sentiment Index Q1 2016 January 92.0

February 91.7

March 91.0

Source: University of Michigan

January and February of 2016 brought a slight increase in Trimmed Personal Consumption Expenditures (PCE). Domestic energy prices remained low, improving consumers’ purchasing power at home. Most economic agencies, however, forecast that energy prices will rise by the end of the year. The U.S. domestic oil and gas industry has been hit hard by low prices. Production is declining. Although unemployment has fallen for the U.S. as a whole, unemployment among oil and gas workers was estimated at 8.5% in 2015, and was expected to reach 10% in 2016. With energy prices forecast to rebound, additional job formation and wage growth will be needed. •

Trimmed Personal Consumption Expenditures (PCE) Percentage of Change

Source: Federal Reserve Bank of Dallas

Fundamentals Crude Oil Lacks that Old Familiar Feeling as Bulls Find Footing in Falling Production Crude Oil Inventories Approach All-time High

Commercial crude oil inventories approached the nationâ&#x20AC;&#x2122;s 545-million barrel record during the first quarter. At the end of March 2016, crude inventories stood at 534.8 million barrels. At the same time, inventories stored in Cushing, Oklahoma (pricing hub for NYMEX crude oil futures) were 66 million barrels. Source: Energy Information Administration (EIA)

U.S. crude inventories grew by more than 47.5 million barrels in the first quarter. Low prices took a steady and severe toll on the U.S. upstream industry. The nationâ&#x20AC;&#x2122;s oil-seeking rig count, already down over 60% at the end of 2015, shed another 214 rigs between the first week of January 2016 and the first week of April 2016. According to Baker Hughes, during the week of January 8, 2016, there were 664 oil and gas rigs at work in the U.S. This number fell to 450 active rigs by April 1, 2016. One year prior, on April 1, 2015, there had been 1,028 rigs, therefore, 578 rigs have shut down in just one year.

The effects of the numerous rig closures manifested as steady weekly production losses beginning in mid-January. A 158,000-barrel-a-day, six-week retreat lasted until the end of February and continued into March. Production of 9,219 kbpd on January 1, 2016, fell to 9,008 kbpd on April 1, 2016, a drop of 211 kbpd during the first quarter. Traders expect declines to only worsen, defending prompt crude oil prices against bearish inventory data.

Fundamentals

Domestic Oil Production Wanes as Rig Counts Collapse

Source: Energy Information Administration (EIA)

Even as rig counts declined sharply, the industry’s sizeable fracklog and rising first-month production rates caused drillers to respond swiftly. •

Average Oil Production per Well in the Permian Region

Source: Energy Information Administration (EIA)

Fundamentals

Refined Product Inventories Exceeding 5-year Averages Domestic Gasoline Inventories Exceed 5-year Averages Meanwhile, domestic gasoline inventories rose from 232 million barrels at the beginning of January to 258 million barrels by mid-February before seasonal drawdowns brought the level to 242.6 million barrels at the end of the quarter. High inventories actually extended the nationâ&#x20AC;&#x2122;s surplus in comparison to 5-year seasonal averages to 24.5 million barrels.

Source: Energy Information Administration (EIA)

Domestic Distillate Inventories Tread Water Ahead of Seasonal Midwest/North Plains Demand Distillate inventories, on the other hand, continued to tread water, refusing to follow the normal seasonal downturn. Inventories at the end of the quarter were 161.2 million barrels, which is 34.1 million barrels, or nearly 27 percent, above the 5-year seasonal average of 127.1 million barrels.

Source: Energy Information Administration (EIA)

ÂŠ 2016 Mansfield Energy Corp.

Fundamentals Without additional cold-weather demand to soak up some of these excess barrels, some refiners may slow output after completing turnaround operations, but ultimately, gasoline will be the deciding factor for driving output. Summer-grade premiums nearly double refinersâ&#x20AC;&#x2122; gasoline margins and with the expiration of cheaper March futures, distillate production will be pulled along for the rideâ&#x20AC;&#x201D;causing excess distillate supply, which will benefit diesel consumers as prices dip lower still. As we begin the second quarter of 2016 (as illustrated in the figure below), gasoline and diesel inventories rose slightly over the prior week and crude had a modest decline. Crude and refined product inventories are up year over year. â&#x20AC;˘

U.S. Domestic Inventories

Source: Energy Information Administration (EIA)

Fundamentals

IEA Calls the Bottom While Warning of Middle East Price War Halfway through the first quarter, the market recorded its lowest domestic crude oil price in twelve years at $26.05 a barrel. Up roughly 50 percent since then, barrel prices now earn more than $40 a barrel and traders seem confident petroleum prices will only continue to mend as rig counts decline further and domestic production slides lower, but the Paris-based International Energy Agency (IEA) does not necessarily share the same opinion. Global oil supplies slipped 180,000 barrels a day in February as non-OPEC nations trimmed output in response to lower barrel prices, according to the Agency’s monthly Oil Market Report (OMR). By the end of the year, IEA analysts expect non-OPEC production to fall by 750,000 barrels a day while OPEC nations struggle to find balance, supporting higher product prices and the IEA’s claim of “signs that prices might have bottomed out.”

Monthly Iran Crude Oil Production

Even so, the Agency went on to say, “This should not, however, be taken as a definitive sign that the worst is necessarily over,” as total global production still rose by roughly 1.8 million barrels a day compared to February 2015 when domestic rates were actually 200,000 barrels a day higher and rising. While domestic rates have declined recently, OPEC nations now wage a very public battle for market share, disregarding lower barrel prices and offsetting all nonOPEC cuts. Domestic suppliers must wait on the sidelines as oildependent nations decide crude oil’s trajectory. A post-sanction Iran could prove to be the fly in the ointment. Talk of a production freeze encouraged bullish traders, increasing barrel prices during the month of March 2016 above $40/b. It is possible that stronger prices in the second quarter could invite struggling domestic drillers back into the field but a production cap would only impact the global supply balance if everyone participates (i.e., Iran) and non-OPEC production continues to decline. Several oil ministers have already threatened to increase production to the max if other producers do not rein in output. While Iran’s return to the market has been more gradual than predicted, the Islamic Republic’s rising output, combined with retaliatory barrels from partner-competitors, could force the price of oil back to February lows.

Source: Energy Information Administration (EIA)

ÂŠ 2016 Mansfield Energy Corp.

Fundamentals

U.S. Refining Rolls Along, Buoyed by Still-Ample Domestic Crudes and Distillate Export Markets U.S. Refinery Utilization Rates Remain Strong Although U.S. crude production is threatened by low prices, output remains well above historic levels. Many refineries in the Midwest, Rocky Mountains and Gulf Coast have enjoyed access to ample supplies of low-cost crude feedstocks, and their utilization rates have soared. Most feared that lifting the outdated restrictions on exports of domestic crude this year would eliminate this advantage. U.S. crude exports during the first quarter remained at approximately 420 kbpd, actually declining slightly from their fourth quarter 2015 levels. Refinery utilization rates remained high. At the beginning of January, the refinery utilization rate was 92.5%. By the last week of March, it declined slightly to 90.4%. Source: Energy Information Administration (EIA)

U.S. Gasoline Import Requirements Are a Small Fraction of Demand The gasoline-maximizing capability of the U.S. refining industry is without peer in the world. In June of last year, a production record was set with refiner and blender net production topping the 10-million-barrel-per-day mark. As the figure illustrates, gasoline exports averaged approximately 440 kbpd during the first quarter, versus gasoline imports of 560 kbpd. Currently, exports are trending down and imports up as the summer driving season approaches, but U.S. import requirements constitute a very small percentage of demand. Source: Energy Information Administration (EIA)

ÂŠ 2016 Mansfield Energy Corp.

Fundamentals Presently, U.S. gasoline demand remains around 2.5 times as large as diesel. As U.S. refineries run at high rates to produce gasoline, however, diesel production has risen in tandem. During the first quarter, U.S. diesel exports averaged around 1,240 kbpd, while diesel imports averaged only 180 kbpd. The meteoric rise of U.S. diesel exports is one of the most astonishing—and often overlooked—results of the Shale Revolution. The figure below illustrates how diesel exports shot up from 110 kbpd in 2004 to 1,186 kbpd in 2015. These exports have found ready markets overseas where many economies are more diesel-oriented than gasoline-oriented, but they also place the U.S. in a role as an export-refining center. As such, the industry’s profitability is more subject to global oil prices, and domestic diesel prices are becoming more sensitive to global demand for U.S. distillate exports. •

The U.S. Has Become a Premier Exporter of Distillate

Source: Energy Information Administration (EIA)

The Meteoric Rise of U.S. Diesel Exports

Source: Energy Information Administration (EIA)

Regional Views PADD 1

East Coast

BEAR BULL

Evan’s Estimation I

The first quarter of 2016 in the Northeastern U.S. turned out to be an unusually warm start to the year, with temperatures well above average for a large part of the winter. As a result of this warmer weather, New York Harbor ULSD basis numbers stayed well depressed compared to previous years. Basis numbers did make a slight rebound compared to the fourth quarter of 2015, however, but still continued to remain a discount to the NYMEX heating oil screen. Gasoline (RBOB and CBOB) basis in the NYH region also traded below the NYMEX RBOB screen on average over the first quarter of 2016.

PADD 1A Northeast

“ My prediction for the

second quarter of 2016 in the Northeast is bearish on the distillates and bullish on the gasoline.

”

My prediction for the second quarter of 2016 in the Northeast is bearish on the distillates and bullish on the gasoline. After coming out of a warm winter and lowerthan-normal distillate demand, already elevated distillate inventories are going to remain steady or continue to build. This will force downward pressure on the NYMEX heating

Evan Smiles, Supply Supervisor See his bio, page 50

oil and push NYH ULSD basis numbers further below the NYMEX. I can see basis numbers returning to values that we saw in late 2015/very early 2016 of 0.03 to -0.05. In regards to gasoline, the peak of the driving season is typically through the summer months. With it already feeling like we are in the early days of summer, gasoline demand could elevate even earlier this year causing some upward pressure on the market. The switchover to summer gasoline will also help bolster prices through this second quarter. Regarding gasoline, the peak driving season is typically through the summer months. It feels like we are already in the early days of summer, gasoline demand could elevate even earlier this year causing some upward pressure on the market. The switchover to summer gasoline will also help bolster prices through this second quarter. •

PADD 1A Wholesale vs. DOE Retail Diesel (dollars per gallon)

Source: Energy Information Administration (EIA)

Regional Views

PADD 1

New York Harbor ULSD—Winter 2015/2016

East Coast

Distillate supply in the New York Harbor region historically runs tight as we trek through the coldest months of the year. The main factors causing this are the extreme cold temperatures, forcing a spike in heating oil and ULSD demand, and the logistical nightmares of delivering product, due to high winds and numerous snowstorms. The previous two winter seasons (before this most recent one) showed just that as distillate supply was constricted and prices spiked.

PADD 1A Northeast

The winter of 2015/2016, however, has proven to be out of the ordinary and one that many will never forget. Milder temperatures and lighter-than-normal precipitation were experienced throughout the Northeast, with temperatures dropping into the negative temperatures in the New England states for just one weekend. These warmer temperatures have kept heating oil and ULSD supply plentiful from the

“ This extension, if

approved, will diminish any supply issues and reduce any price spikes that would have arisen if a stricter gas product were to be mandated.

”

moment winter started to the conclusion of the season. Even the refinery and pipeline issues that were experienced throughout February (PBF’s Delaware City shutting down, the Buckeye pipeline shutting down to Long Island due to a sunken barge, Irving Oil’s St. John refinery’s FCC unit malfunctioning) could not bolster ULSD prices above what the NYMEX was trading at (see graph below). These warmer temperatures have caused an already oversupplied Northeast to become more flooded with distillate supply. Now that the distillate season is coming to a close and we are about to enter the height of the gas season, distillate supply could remain elevated at least through the next winter season. This oversupply means cheaper diesel for the end consumer for an extended period of time (barring any refinery or pipeline disruptions). •

Pennsylvania Gas Requirement The State of Pennsylvania, along with numerous other states, currently has a 1 psi Reid Vapor Pressure (RVP) allowance in place for all gasoline blended with 9% – 10% ethanol that is in effect until May 1, 2016. With this waiver expiring within the next few months (before the ASTM standard is revisited), the state is attempting to get an extension granted. This extension, if approved, will diminish any supply issues and reduce any price spikes that would have arisen if a stricter gas product were to be mandated. 22

The counties around the Pittsburgh markets are still attempting to dissolve a low RVP mandate, as they are the only counties within the state that require low-RVP CBOB product in the summertime. This requirement has caused logistical nightmares for some years from May to September as product has become hard to find, therefore pushing prices higher. If this requirement is not repealed before the start of summer, another season of low RVP gas will have to be endured in the counties surrounding Pittsburgh, which could cause headaches for wholesalers and consumers. •

Regional Views

PADD 1

East Coast PADD 1B & 1C

Central & Lower Atlantic

BULL

Chris’ Concept I

Chris Carter, Supply Manager See his bio, page 50

For the second quarter of 2016 I’m predicting we will see both Gasoline and ULSD prices continue to rise. The spring rally for Gasoline will begin soon as we start turning storage tanks for the summer RVP requirements and will bring higher prices. I’m also slightly bullish for ULSD; I believe we are going to see GC ULSD trade in the -.05/-.06 range for the next few months. As we continue closer to summer, it will be interesting to see how the potential active hurricane season will continue to impact basis. •

PADD 1B Wholesale vs. DOE Retail Diesel (dollars per gallon)

“ As we continue closer

to summer, it will be interesting to see how the potential active hurricane will continue to impact basis.

”

Source: Energy Information Administration (EIA)

PADD 1C Wholesale vs. DOE Retail Diesel (dollars per gallon)

Source: Energy Information Administration (EIA)

Regional Views

PADD 1

Q1 GC Basis

East Coast PADD 1B & 1C

Central & Lower Atlantic

Q1 Colonial ULSD Line Space Premium to Tariff

The first quarter of 2016 didn’t see the large basis swings seen over the past two years. In 2016, GC Basis traded around -.0472. That’s almost .10 higher than experienced in 2015 and .06 cpg higher than in 2014. Several factors contributed to this: lower flat prices, refinery turnarounds, NYMEX carry and a mild winter compared to previous years.

OPIS GCA to NCUL Spread–Trendlines

As a result of higher Gulf Coast Values and lower New York Harbor ULSD basis values, Colonial Line Space traded at much lower levels than 2015. This year line space premiums only traded at or above .03 cpg gallon a few times, while last year during the same period ULSD spaced averaged .06 cpg. Current projections have the remainder of the year less than half a cent. Due to the low volatility over the six months, OPIS spreads continue to show the Gross Contract Average (GCA) to Net Contract Unbranded Low (NCUL) for ULSD in several major cities across the SE. Historically we see spreads increase during the first quarter, however, the mild winter and low flat prices continue to put pressure on OPIS spreads. • 24

Regional Views

PADD 1

East Coast PADD 1B & 1C

Central & Lower Atlantic

Palmetto Pipeline In March Kinder Morgan lost another battle in Georgia regarding their plans to build the Palmetto pipeline into Jacksonville. Kinder Morgan plans to build a pipeline from Belton, SC, to Jacksonville, FL, servicing several terminal cities in South Carolina, Georgia and Florida. In March a Georgia Superior Court Judge upheld a decision from May 2015 denying Kinder Morgan a certificate of “public convenience and necessity.” This permit would allow Kinder Morgan to secure its route. Even after this ruling in March, Kinder Morgan doesn’t plan on abandoning the Palmetto project. Kinder hopes to begin construction by the end of 2016. Kinder Morgan has continually expressed that it would lower gas prices for residents in southern Georgia and Jacksonville. Kinder Morgan also is stating that the pipeline would help take tankers off Georgia Highways. Georgia and South Carolina both are proposing legislation that would prevent eminent domain for petroleum pipelines.

Regional Views

PADD 2 Midwest

BULL

Dan’s Dissertation I

Dan Luther, Sr Supply Manager See his bio, page 50

Fuel buyers in the Midwest should expect higher prices during a volatile second quarter. The region will experience a swath of refinery downtime due to a strong spring maintenance season that will see major regional players such as Flint Hills Pine Bend (MN), Citgo Lemont (IL), Husky Lima (OH) and BP/Husky Toledo (OH) undergo maintenance. This is just as agricultural demand picks up due to spring planting season, increasing diesel demand. Additionally, RVP changes and more demand at the retail pump should send gasoline prices up. Relative to NYMEX futures, expect higher Midwest diesel and gasoline prices during a rocky April and May. •

PADD 2 Wholesale vs. DOE Retail Diesel (dollars per gallon)

“ Additionally, RVP

changes and more demand at the retail pump should send gasoline prices up. Relative to NYMEX futures, expect higher Midwest diesel and gasoline prices during a rocky April and May.

”

Source: Energy Information Administration (EIA)

Regional Views

In February Midwest gasoline inventories reached their highest peak in over twenty years. Falling crude oil input costs—sourced predominantly from heavily discounted Canadian oil projects—and demand for crucial winter distillates stoked refinery production despite lower gasoline needs during a seasonally slow driving season.

High Gasoline Inventories Weighed on Midwest Prices

As inventories swelled, prices moved significantly lower, pinching refinery profitability in the Midwest. Production slates vary widely, but refiners’ margins traditionally follow the price of gasoline as it represents roughly two-thirds of the average facility’s refined product output. As inventories reached their peaks, Midwest markets experienced a nearly 55-percent collapse in Chicago gasoline prices, cutting refiners’ margins to a similar degree.

Midwest Crack Spreads Decline by Nearly Half

If every Midwest barrel were priced using the Western Canadian Select (WCS) discount to West Texas Intermediate (WTI), Chicago area refiners would gross just over $15 a barrel, a $3.25/bbl premium to the national estimate. Those sourcing WTI barrels from the Gulf Coast, however, suffer margins of less than 50 cents a barrel. Once you figure in the higher operating costs of Chicago area refiners, it’s no wonder producers are considering cuts. As summer gasoline season approaches for most on June 1st, buyers may continue to see discounts for prompt prices as suppliers look to move higher RVP inventories. But headed into the summer season, Midwest pricing is set to increase on higher seasonal demand and a heavy spring refinery turnaround season. •

Source: New York Mercantile Exchange (NYMEX)

Regional Views

PADD 3

Gulf Coast

BEAR

Dan’s Dissertation I

Dan Luther, Sr Supply Manager See his bio, page 50

With a majority of the Gulf Coast’s seasonal maintenance coming to an end in April, production should be strong for most of the second quarter. While there will be an opportunity to push barrels into PADD 2, given the strong Midwest turnaround season there, those flows are limited by pipeline capacity. U.S. Gulf Coast exports of products are also expected to remain lower than this time last year as Latin American countries increase their domestic refinery capacity and some countries, such as Venezuela, experience economic woes, decreasing gasoline demand. While the upcoming Summer Olympics in Brazil may lead to a short-term spike in gasoline demand, it should not have a lasting effect on exports. Summer driving season can always be volatile, but supply should outpace demand in the Gulf Coast for both diesel and gasoline leading to lower prices in the region relative to NYMEX futures. •

“ Summer driving

PADD 3 Wholesale vs. DOE Retail Diesel (dollars per gallon)

season can always be volatile, but supply should outpace demand in the Gulf Coast for both diesel and gasoline leading to lower prices in the region relative to NYMEX futures.

”

Source: Energy Information Administration (EIA)

Regional Views

Houston, We Have a Problem The rapid growth of Texas and many oil-producing states has come to an end. Exploration and production companies suffered another round of layoffs during the first quarter as executives conserve capital in the industry’s current lower-for-longer environment. Consequently, most E&P companies will curb capital expenditures on incremental shale projects as long as oil’s forward curve remains under $50 a barrel, which many energy agencies do not expect to change until sometime later this year or in the first half of 2017. According to the Oil & Gas Journal, total U.S. capital expenditures for upstream, midstream, downstream and corporate activities will fall more than a quarter this year to $136 billion after suffering a 36.1percent decline last year. While slimmer year-over-year cuts may seemingly suggest the market’s found its footing, estimates included rising investments in refining, petrochemical and pipeline spending, offsetting steep cuts in the upstream sector and improving figures. 31 29

The stress of low oil not only impacts the E&P companies. JP Morgan warned of “stress” in energy loans, which prompted criticism of Dodd-Frank “too big to fail” provisions, while midstream energy companies slashed all-important dividends to preserve cash assets. In many areas, pipelines have actually been overbuilt, forcing operators to drop rates to encourage shippers. Meanwhile, large “take or pay” deals proved costly in the near term as producers failed to meet their commitments and went into default, leaving pipeline companies few options in recovering their investments. In the end, fossil fuel companies across the nation—not just Texas—should prepare for even harder times to come. Credit-assessment agency Fitch Ratings announced late in the first quarter oil and gas companies had already defaulted on roughly $6 billion this year. Worse still, Fitch expects companies to default on $9 billion before the end of April and another $40 billion before the end of 2016. Companies unable to suffer through lower oil prices will eventually seek bankruptcy protection and liquidate assets at pennies on the dollar to the benefit of competitors with low debt ratios, i.e., Big Oil. •

Production Inhibited at Many Gulf Coast Refineries, Export Demand Down on Lighter Latin American Purchases Several major Gulf Coast refiners operated below capacity during the first quarter of 2016. The list of refineries that ran at reduced rates was a “who’s who” of the biggest producers in the U.S. In mid-January, flooding on the Mississippi caused ExxonMobil to cut production at its 502,000 bpd Baton Rouge (LA) refinery to avoid containment issues. Another unplanned incident occurred at Exxon’s 344,600 bpd Beaumont (TX) refinery when a storm caused a power outage on January 21st that interrupted electricity to the entire plant for two weeks. A robust schedule of planned maintenance also occurred during the first quarter. Refineries—including Motiva’s 603,000 bpd Port Arthur (TX) plant, Exxon’s 560,500 bpd Baytown (TX) plant and Marathon’s 522,000 bpd Garyville (LA) plant—all took units offline for maintenance during the quarter. The effects of reduced production can be seen in the Gulf Coast distillate production estimates by the EIA.

Offsetting diminished production, several large importers of Gulf Coast refined products from Latin America reduced purchases in the first quarter. Venezuela reportedly imported less Gulf Coast gasoline amid the nation’s severe recession and a reduction of domestic gasoline subsidies. On the distillate side, Brazil and Colombia imported less diesel due to domestic refinery improvements. Petrobras, the Brazilian state oil company, claimed that January production of diesel in its Brazilian refineries was a new record high of about eight million barrels. Since 2014, Brazil has cut their monthly imports from the USGC by roughly 40 percent. In Colombia, Ecopetrol’s Cartagena refinery began production at its new processing unit, which some traders believe could cease imports to the country. If that were the case, it would be a reduction from 6.1 million bbl of oil products imported into Colombia from the U.S. in November 2015. The U.S. has acted as the “refiner to the world” for much of the last several years, but reduced products exports to Latin America should mean more refined products are sold domestically. •

PADD 3 Net Production of Distillate Fuel Oil

Regional Views

PADD 3

Gulf Coast

Magellan Pipeline Maintenance Disrupts Fuel Supply into Dallas In early January Magellan initiated the first stage of planned hydrotesting on their 10" Waco-Dallas pipeline, disrupting supply on a major fuel source into the Dallas market. The testing lasted approximately eight weeks through mid-March, constraining refined products shipments on the pipeline. Hydrotesting is routine monitoring to inspect pipeline strength and to check for leaks. With pipeline batches into Dallas hindered, some shippers had trouble keeping inventories afloat, which sent spot fuel buyers chasing product around the Metroplex. Adding to buyers’ troubles, rack prices strengthened given the supply imbalance; Dallas USLD low rack shot up over $.05 on January 11th, the day the hydrotesting began and remained elevated during much of the pipeline work. After completing maintenance on the Dallas portion of the line, Magellan began work on the Waco line, which should last through mid-April. After the work is complete, fuel buyers in Central Texas along the WacoDallas line should expect values to return to normal levels as pipeline shipments flow unimpeded. •

Dallas Rack USLD Premium to Gulf Coast Wholesale

Regional Views

PADD 4 Rocky Mountain

BULL

Nate’s Notion I

Nate Kovacevich, Supply Manager See his bio, page 50

Refined product prices in the Rockies bottomed out during the first quarter as higher crude oil prices translated into higher input costs for refineries. Gasoline economics became extremely weak in the Midwest (PADD 2), forcing many refiners to cut runs in response to less attractive margins. Meanwhile, the West Coast stayed relatively strong compared to the rest of the nation. The Rockies seems to have been more impacted by weakness in the Midwest than strength on the West Coast, however. I think the same conditions hampering Group 3 economics are hitting Rocky Mountain refineries and suspect the rebound in gasoline prices should continue into the second quarter ahead of the summer driving season. Prices should also benefit from planned maintenance in PADD 4, reducing refinery utilization in the region and combining with rising seasonal demand to support prices throughout the second quarter. Whether a rally proves sustainable all the way into the third quarter will largely depend on the direction of crude oil, however. •

PADD 4 Wholesale vs. DOE Retail Diesel (dollars per gallon)

“ I think the same

conditions hampering Group 3 economics are hitting Rocky Mountain refineries and suspect the rebound in gasoline prices should continue into the second quarter ahead of the summer driving season.

”

Source: Energy Information Administration (EIA)

Regional Views

Refinery Maintenance Expected to Thin Supplies in Isolated PADD 4 Markets Refined product prices in the Rocky Mountain (PADD 4) region began their seasonal ascent near the end of the first quarter as demand expectations increase the closer markets get to the summer driving season and supplies tighten with the onset of spring refinery maintenance. Between now and early May, three Rocky Mountain refineries will slow or halt operations to perform much-needed refinery maintenance ahead of peak summer production. Suncor’s Denver refinery, Big West’s Salt Lake City facility and HollyFrontier’s Cheyenne plant all expect at least partial shutdowns. PADD 4’s operable capacity totals roughly 650,000 barrels per day and planned maintenance is expected to reduce crude throughput by at least ten percent at the season’s peak.

The Denver and Cheyenne outages could prove the most problematic from a supply standpoint as both heavily influence regional supplies and plan to cut production in April to perform seasonal maintenance. Colorado’s only refinery, Suncor, will perform plantwide maintenance, further stressing downstream infrastructure as inventories from across the region will likely supply the balance. However, some terminals do not have the capacity for increased demand and truck traffic, which could result in long lines this spring. Suppliers may even long-haul loads from other states, if Colorado terminals cannot support the increased volume and extended wait times disrupt delivery schedules significantly. Replacement barrels will likely originate from the Billings market or cities in western Group 3 (i.e., Nebraska and Kansas) and the Texas panhandle.

Expect rising refined product prices across the Rockies this spring. Of course, just how high prices rise will depend on how well suppliers handle existing inventories. Already below multi-year seasonal averages, distillate inventories could present a challenge this spring. Elevated refiners’ margins actually work in the consumer’s favor this time, however. Gulf Coast (PADD 3) and Midwest (PADD 2) refiners will likely chase lucrative gasoline margins heading into the summer driving season, resulting in greater distillate production as well. These excess barrels should backstop regional inventories, ensuring products flow toward the Rockies instead of eastern markets. •

Padd 4 Distillate Inventories Below Average Heading into Disruptive Refinery Maintenance Season

Source: Energy Information Administration (EIA)

31 33 33

Regional Views

PADD 5

West Coast, AK, HI

BULL

Matt’s Musings I

Basis volatility on the West Coast dropped off significantly versus this time last year thanks to two driving factors (pun intended): extreme weather and Exxon’s anticipated return to the SoCal gasoline market. This year’s record El Niño pattern brought much-needed rain to a parched California. Of course, the phrase, “when it rains, it pours” comes to mind. Daily newscasts were filled with stories of beachfront apartments falling into the ocean, frequent flash flooding and mudslides along the Western seaboard. As you’d expect, torrential rains—typical of a strong El Niño—generally keep non-essential traffic off the roads, cutting into regional fuel consumption and applying downward pressure to gasoline prices in primary commercial supply points. Thankfully, forecasters expect storms to subside as we move into the summer months, encouraging drivers to get out there and DRIVE!! At the same time, major West Coast refineries, with the exception of Exxon’s SoCal refinery, completed first-quarter turnaround early this year without much fanfare,

Matt Elder, West Coast Supply Supervisor See his bio, page 50 contributing to softer basis values this quarter. Adding to bearish pressure, analysts and PBF buyers expect Exxon’s gasoline-producing units to return to full strength by the end of April after more than a year offline, finally balancing the California gasoline market. If all goes according to plan, PBF Energy will then take control May 1st and, given PBF’s history of refinery optimization and maximizing efficiency, consumers could enjoy additional savings as PBF clears the remaining cobwebs. The question then becomes, “Who will win this tug of war? Refiners or consumers?” Lower prices, clear skies and an improving job market should place more cars on the road in the coming quarter and Economics 101 says, “Greater demand should result in higher gasoline prices.” Meanwhile, increased gasoline production/supply and reduced uncertainty should weigh on fuel prices. At the end of the day, I have to believe drivers will end up paying a little more than they have been used to in recent months. Refiner capacity roughly equals consumer demand in the summer, and rising crude oil prices will lend support to an unusually deflated fuel market. •

PADD 5 Wholesale vs. DOE Retail Diesel (dollars per gallon)

“ At the end of the day, I

have to believe drivers will end up paying a little more than they have been used to in recent months. Refiner capacity roughly equals consumer demand in the summer, and rising crude oil prices will lend support to an unusually deflated fuel market.

”

Source: Energy Information Administration (EIA)

Regional Views

CARB Says, “Fossil Fuel, Your Days in California are Numbered!” While consumers save upwards of a billion dollars a day on refined products in comparison to seasonal averages only a few years ago, they could still be as much as 20cpg lower if not for California’s escalating Cap-at-the-Rack (CAR) and Low Carbon Fuel Standard (LCFS) fees. Fourteen months ago, they added less than half a cent per gallon to the cost of fuel and regulators will need to continually increase pressure on refined products to meet aggressive, anti-emission goals set by the State’s legislators. In accordance with Governor Jerry Brown’s plan to cut petroleum consumption by half before 2030, the California Air Resources Board (CARB) re-adopted the LCFS late last year, lowering the statewide carbon intensity threshold of transportation fuels by 10 percent before 2020. Until recently, the LCFS program cost consumers less than 35 points per gallon (0.35cpg) for gasoline. Roughly halfway through 2015, however, that cost crept steadily higher to more than 4.5cpg by the start of 2016 before settling into a 4.8cpg to 5cpg range. In addition to California’s LCFS program, regulators expanded their cap-andtrade program at the start of 2015 to include fuel marketers, who then passed rising expenses to end-users across the wholesale rack. Cap-at-theRack fees—the wholesale rack assessment of California’s expanded cap-andtrade regulations—share a similar story, beginning January 2015 with a baseline rate just over 10cpg, but now trading in the 14.5 to 15cpg range.

LCFS and Cap-at-the-Rack combine to equal the 20cpg premium referenced earlier. Unfortunately, drivers already pay a hefty premium for the State’s lowRVP, low-emission, boutique gasoline standard. Even so, in mid-March, regular, California-grade gasoline prices averaged more than $2.50 a gallon at the retail pump and these two compliance fees alone accounted for over 8 percent of the total fuel cost. Before you break out the pitchforks and torches, understand that these programs are ultimately intended to reduce greenhouse-gas (GHG) emissions. Both the LCFS and cap-and-trade programs penalize suppliers for processing crude oil into motor vehicle fuels while granting low-emission and renewable alternatives a cost advantage in the marketplace. Ethanol, biodiesel and renewable diesel all offer lower CO2 emissions versus their fossil fuel counterparts, qualifying for generous federal tax breaks while side-stepping California’s rising regulatory fees. While reducing GHG emissions by up to 80 percent, renewable diesel also costs less than most traditional diesel refined in California, despite weaker crude prices, adding to the product’s overall cost advantage. Nationwide consumption of renewable diesel increased more than 80 percent year-overyear and Californians consume more than 70 percent of all gallons, providing fairly convincing evidence that CARB programs will ultimately achieve their goal of pricing traditional fossil fuels out of the market. •

Regional Views

Canada

Low Oil Leads to Slower Economic Growth and Fuel Demand in Producing Regions

The substantial drop in crude oil prices deeply impacted oil companies on both sides of the U.S.-Canadian border. At the end of 2014, the energy sector accounted for nearly a quarter of total GDP in Canada’s western province of Alberta and added 63,700 positions, more than half of all jobs created in Canada that year, according to the nation’s employment records. Now, cash-strapped companies have halted new oil projects and slashed capital expenditures in response to the market’s more than 75-percent collapse. Roughly 65,000 workers lost their jobs in 2015, raising unemployment rates from 4.4 percent in October 2015 to 7.0 percent in just three short months. Adding downward pressure to wages and consumer spending, Canada’s Finance Minister, Bill Morneau, expects the oil industry’s rout to reduce the nation’s overall GDP by roughly $15 billion this year. But should Canada be any more or less exposed to falling oil prices than their neighbors to the

Method 1: Steam & Gravity Drains

south? Negative economic headwinds will undoubtedly influence the supply/demand situation for refined products along both sides of the border, but Canada’s oil-sand industry could prove the deciding factor in this debate. According to a 2013 David Hughes study, the average energy return on investment, or EROI, for conventional oil is 25:1, suggesting one unit of energy consumption yields 25 units of crude oil energy. Alberta’s surface mining operations sport a mere 5:1 ratio. Not very good. Worse still, miners can only access resources up to a depth of roughly 250 feet, or about 20 percent of the nation’s 173-billion-barrel proven oil reserves. Beyond that point, drillers employ in-situ recovery methods, which liquefy solid oil deposits with steam and return only 2.9 units of crude oil energy for every unit invested—by far one of the industry’s worst investments.

Method 2: Cyclic Steam Stimulation

Source: Canadian Association of Petroleum Producers (CAPP)

Consequently, production cuts across Canadian oil fields ultimately result in steeper refined product consumption losses, prompting Canadian refiners to either cut runs or find a new home for their fuel in the U.S. If Canadian operators choose the latter, refined product barrels will likely flow south via rail over the coming months, which could further hamper the supply/demand balance in the northern United States. Already suffering an oversupply of their own, states like North Dakota—traditionally net-short diesel and currently quite long—could find tanks overflowing with product, sending prices to new lows on both

sides of the border. Eventually, negative refiners’ margins would prompt production cuts in the U.S. as well, sending prices higher and continuing the cycle of volatility. Markets with the greatest exposure to oil-sector fuel demand—Alberta, North Dakota and Montana—should brace for the worst as regional demand is closely tied to the price of oil. As barrel prices slip, oil recovery operations slow, reducing fuel consumption both at the rig and along the roads as less frequent shipments require fewer trucks, railcars and yard vehicles. Those pursuing

Alberta’s costly oil sands suffer the greatest exposure to oil prices, considering surface miners consume five times as much energy/fuel as their conventional counterparts and oil sands cannot move along traditional pipelines, influencing rail diesel demand. Most energy agencies agree on an average 2016 barrel price close to $40 before increasing another $5 a barrel next year. Until producers consistently lock in rates in that 2017 range, refined product demand in these regions will likely languish and economic development along with it. •

Alternative Fuels

Renewable Fuels “ While renewable fuel

prices reflected much of the refined product market’s year-over-year declines, producers, distributors and consumers could not help but wish for a more dramatic decrease.

”

BULL

Jessica’s Judgment I

Jessica Phillips, Renewable Supply & Distribution Supervisor See her bio, page 50

While renewable fuel prices reflected much of the refined product market’s year-over-year declines, producers, distributors and consumers could not help but wish for a more dramatic decrease. The active tax credit certainly helps, but the Bean-Oil-to-Heating-Oil spread ticked up this quarter and RINs did not rise enough to counteract those effects. Regardless, biodiesel regained its discount to ultra-low sulfur diesel, once again encouraging discretionary blending in markets without a state mandate/incentive. Meanwhile, California renewable diesel imports from Finnish refiner Neste Oil continue increasing to meet CARB standards at considerable discounts to traditional ultra-low sulfur diesel. Ethanol economics improved as well. With 2015 ethanol production estimated at roughly 966,000 barrels per day and the 10-percent blend wall raising concerns, January ethanol exports increased by 5.41 million gallons, or 6.6 percent (in comparison to December 2015) to 87.08 million gallons. Second quarter 2016—and really the balance of the year—has a positive outlook: production up, prices down, supply and demand the way it was intended. Renewable Energy Group’s Geismar, Louisiana, renewable diesel production facility resumed operations this quarter, improving second-quarter U.S. production and consumption figures. •

Finalized EPA Ruling Bolsters Renewable Industry amid Falling Oil Prices At this time last year, the future of the renewable fuel industry appeared uncertain. Legislative support seemed weak and declining petroleum prices placed renewable fuel marketers on the defensive. With the reinstatement of the $1/gal biodiesel blender’s federal tax credit, however, low-emission alternatives finally regained their discount to ultra-low sulfur diesel and production got the shot in the arm it needed. According to the U.S. Energy Information Administration (EIA), December 2015 biodiesel production exceeded November rates by roughly 2 million barrels, largely due to the tax credit’s return.

YEAR

B100 Production

Sales of B100

included in biodiesel blends

2015

1,268

781

465

2014

1,271

792

491

2013

1,359

942

434

Considering crude oil barrels traded at their lowest rates in roughly a decade last year, biodiesel sales proved exceptionally resistant, declining by only 37 million barrels, or 2.9 percent, year-over-year. In January, the Environmental Protection Agency concluded U.S. consumers used approximately 2.1 billion gallons of biodiesel in 2015, surpassing the Renewable Volume Obligation of 1.73 billion gallons and further illustrating the Renewable Fuels Standard’s support of the nation’s biodiesel production and distribution. •

Sales of B100

*Figures in millions of gallons

Courtesy of EIA

Alternative Fuels

RIN Brief RINs enjoyed a relatively uneventful first quarter with 2016 D4 Biodiesel RINs relatively range-bound between 70 and 80 cents per RIN, falling to only 69.75 cents on January 22 before climbing to a first-quarter high of 80.25 cents on February 25. At the end of the quarter, biodiesel RINs traded for 79.38 cents. Similarly, 2016 D6 Ethanol RINS maintained a roughly 10-cent spread throughout the first quarter, mainly hovering between 65 and 75 cents per RIN before moving into the second quarter at a rate of 73 cents per RIN. •

RINs Enjoy Quiet Quarter with No Major Legislation

Source: Oil Price Information Administration (OPIS)

Biodiesel Earns Crucial Support from Heavy-Duty Manufacturer While ethanol advocates contend with the 10-percent ethanol blend wall, encouraging automakers to approve and warranty vehicles consuming E15 or greater, biodiesel supporters bask in the warmth of B20 endorsements. Domestic automakers Ford, GM and Fiat-Chrysler produce more than 78 percent of the nation’s diesel-burning vehicles and have long supported B20 consumption. However, their 78 percent market share accounts for only 13 percent of the nation’s total diesel fuel consumption. Heavy-duty trucks, in fact, represent more than 87 percent of the nation’s actual diesel demand and biodiesel producers have finally gained another important ally in this high-yield market. PACCAR, the manufacturer of Peterbilt and Kenworth trucks, now approves the use of B20 biodiesel blend in their new and legacy heavy-duty equipment, adding more than

100,000 trucks running an average of 12 billion miles annually to the U.S. carbon reduction initiative. Now, every major engine manufacturer in the nation supports B20 consumption with the exception of Daimler’s Detroit Diesel, which still approves blends of only up to 5 percent. •

Alternative Fuels

Domestic Natural Gas Prices

Natural Gas Cash Price Throughout January and February 2016, cash prices generally traded above the prompt month contract, which is typical at a time of peak demand. However, 2016 opened in much the same way as 2015 closed, so although cash traded at a premium to prompt, natural gas prices continued to drop across the board. January and February temperatures were generally mild with no sustained cold periods. As February gave way to March and above normal temps became the norm, cash began trading at a discount to prompt. This was an unusual turn of events while in a winter month, and thus a signal that storage withdrawal activity would be coming to an early close.•

Forward Prices Though term pricing remained flat during January, it resumed its downward trend from 2015 at the beginning of February. A March rebound did bring calendar 2017 and beyond pricing close to where it was at the beginning of the quarter. April 2016 contracts, on the other hand, have seen a steady downward trend throughout Q1.•

Natural Gas Supply/Demand Fundamentals

SUPPLY

Northeast Gas Production—Marcellus and Utica Shales New Natural Gas Pipelines Expand Northeast Production, Flow As we entered 2016, natural gas production in the Northeast continued to increase year over year; January and early February saw an increase in production of 18% YOY. Though production in the Marcellus region has been growing in the recent past, there has been difficulty moving this gas out of the Northeast. With recent infrastructural upgrades by various pipelines, such movement has been on the increase lately. Interstate pipelines that have been able to transport gas in this way include Rockies Express, Texas Eastern, Columbia Gas, Tennessee Gas and TRANSCO.• Source: Energy Information Administration (EIA)

Alternative Fuels

Anticipated Natural Gas Production Growth

U.S. Natural Gas Production and Imports

Source: Energy Information Administration (EIA) Short-term Energy Outlook, 2016

Total U.S. natural gas production is expected to drop to 0.9% in 2016. Drilling activity has been on a steep decline due to the fact that natural gas prices are at historic lows. In 2017, on the other hand, supply is expected to resume growth as new demand from LNG and Mexico exports warrant. It is no surprise that any such growth will occur out of Marcellus and Utica plays where marginal cost of production is lower than anywhere else in the country. •

DEMAND

U.S. Lower 48 LNG Export Facilties

LNG “Exporting-Ability”

Source: Energy Information Administration (EIA)

With the initial export shipment of LNG from the United States that took place in February, the U.S. finds itself in a new position where it can meet LNG demand from outside the country. Because of the growth in supply from shale resources, coupled with the fact that domestic natural gas prices have dropped in recent years, the ability to meet international demand has grown. Though Alaska has been able to export LNG for quite some time, this marks the first time that such an occurrence took place from the Continental U.S. Despite the fact that the U.S. remains a net importer of natural gas, the recent LNG export is a sign of things to come and no longer will natural gas exports to Mexico be one of the only sources of exporting. 41

The Sabine Pass LNG Terminal, in southern Louisiana near the Texas border, was the site of this landmark LNG export. There are four additional LNG export terminals that are currently under construction (three on the Gulf Coast, one on the Atlantic Coast) that will enable the U.S. to have greater opportunities to meet such demand in the future. •

Alternative Fuels

Natural Gas

Natural Gas Supply/Demand Fundamentals

Power Generation: Solar Generator Additions Exceed Natural Gas Generator Additions

Over the last five years, there has been an average of 7.8 additional gigawatts (GW) of available capacity via natural gas-fired generators. Demand for natural gas in the power sector for 2016 looks to be right on par with that average as it is anticipated that 8 GW of electricity, by way of natural gas-fired generators, are due to be added. For the first time, however, it is expected that additions to capacity by way of solar generators will eclipse the addition of any single energy source. Solar installations should add 9.5 GW of electricity in 2016. â&#x20AC;˘

ÂŠ 2016 Mansfield Energy Corp.

Alternative Fuels

Natural Gas Storage Inventory The amount of gas that is in inventory has maintained its position of higher than the 5-year maximum throughout the winter and well into Q1 2016. Continued falling prices throughout the winter has slowed withdrawals, thereby maintaining inventory at a higher than normal level, considering that it is winter. A 58% increase in inventory over the past 12 months, coupled with a 41% increase over the 5-year average, speaks to the fact that as prices declined, storage injections have continued. â&#x20AC;˘

Working Natural Gas in Underground Storage Compared with the 5-year Maximum and Minimum

Source: Energy Information Administration (EIA)

ÂŠ 2016 Mansfield Energy Corp.

Alternative Fuels

Power Prices

Electrical Power

Cal ‘17 Wholesale Peak Power Prices

Cash Over the last five years, there has been an average of 7.8 additional gigawatts (GW) of available capacity via natural gas-fired generators. Demand for natural gas in the power sector for 2016 looks to be right on par with that average as it is anticipated that 8 GW of electricity, by way of natural gas-fired generators, are due to be added. For the first time, however, it is expected that additions to capacity by way of solar generators will eclipse the addition of any single energy source. Solar installations should add 9.5 GW of electricity in 2016. •

Forward/Term As natural gas found a bottom toward the middle of February, forward power curves tended to mute the gas movement. As seen in the chart above, the price of Cal 17 power across various regional markets remained relatively steady throughout the quarter. •

Electricity Generating Capacity Retired in 2015 by Fuel and Technology

Power Supply A review of 2015-generation retirements produced the same old story… less coal in the generation stack, and replaced by? You guessed it—natural gas and renewables. Nearly 18 gigawatts of electric generating capacity was retired in 2015, a relatively high amount compared with recent years. More than 80% of the retired capacity was conventional steam coal. The chart below illustrates the scale of coal retirements relative to other generation retirements. •

Source: Energy Information Administration (EIA)

Alternative Fuels

Power Fundamentals A contributing factor to the significant increase in 2015 coal retirements was the U.S. Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS) rule, which went into effect in April 2015. Some coal plants applied for and received one-year extensions to MATS, meaning that by April 2016, the list of coal retirements grew larger.

As we look forward to 2016, we see the evolution of a new generating stack. We expect to add more than 26 gigawatts of utility-scale generating capacity to the power grid during 2016. Most of these additions come from three resources: solar (9.5 GW), natural gas (8.0 GW), and wind (6.8 GW). The chart below presents the timing of 2016 additions. (Note the significance of scheduled December additions; many projects expected to begin operation sometime in 2016 are conservatively estimated for a December completion date.)

Scheduled Electric Generating Capacity Additions in 2016

Source: Energy Information Administration (EIA), Electric Power Monthly

Power Demand The big news out of last quarter with regard to power demand came from the U.S. Supreme Court in a ruling on FERC Order 745 (regulation of Demand Response Resource, DRR). In a 6 – 2 decision, the Supreme Court vacated a lower court ruling in determining that FERC acted within its powers under the Federal Power Act (FPA) as it asserted jurisdiction over demand response. There is a range of views on how the market for demand response will proceed from this ruling. One thing is for sure: participation by those eligible is certain to increase. ISO and RTO capacity auctions will see supply/demand capacity curves adjusted and price for capacity in future years will decrease (all else equal)—a good thing for consumers! http://www.utilitydive.com/news/what-the-supreme-courtdecision-on-ferc-order-745-means-for-demand-response/413092/ •

Transportation

Transportation Logistics Safety in Numbers— FMCSA Returns CSA Data to Public View

In December, President Obama approved the nation’s first long-term highway bill—Fixing America’s Surface Transportation Act (FAST)— which included provisions geared toward reforming the controversial Compliance, Safety, Accountability (CSA) program. The FAST Act requires a comprehensive review and redesign of the current enforcement prioritization program, ultimately ensuring members of the public and law enforcement agencies have access to the most reliable safety analysis available.

Administrators removed property carriers’ CSA data from public view only minutes after President Obama signed the legislation on December 4, 2015, leaving potential customers with limited visibility into companies’ safety records. However, after completing crucial compliance upgrades to its Safety Measurement System (SMS), the Federal Motor Carrier Safety Administration (FMCSA) announced on March 7th the return of its publicly accessible “absolute measures,” a standardized assessment of motor carriers’ overall safety performance.

FMCSA analysts derive absolute measures from public safety records, but now stop short of comparing carriers to one another, as dictated by the FAST Act. Instead, the agency simply uploads each company’s basic stats along with raw incident logs, allowing potential clients to review data across the industry before making their own decisions. The main point of contention is that property motor carriers’ percentile scores stay hidden from public view to comply with the FAST Act while passenger carrier comparisons remain unaffected and fully accessible. In addition to safety record handling, FMCSA authorities updated their safety fitness rating methodology to better reflect on-road safety data from inspections, the results of carrier investigations, and crash reports. Regulators would also replace the existing three-tier federal ratings (used since 1982) of “satisfactory–conditional– unsatisfactory” for federally regulated commercial motor carriers with a single determination of “unfit,” which would require the carrier to either improve its operations or cease operations. Implementing a powerful, data-driven ratings system has been an FMCSA priority since the launch of the Compliance, Safety, Accountability program in late 2010. Finally, the FMCSA announced a commissioned study from the National Academies of Sciences, Engineering, and Medicine through its Committee on National Statistics and Transportation Research Board targeting high-risk truck and bus companies.

The agency will examine the accuracy with the Behavioral Analysis and Safety Improvement Category (BASIC) safety measures to identify highrisk carriers and forecast future crash risk or other safety concerns for motor carriers. When all is said and done, the FMCSA’s proposed upgrades and currently available data offer carrier clients valuable data regarding their potential haulers. However, the FAST Act shifts the burden of converting data to insight onto the end-user. To avoid operational disruptions and costly carrier errors, consumers should thoroughly vet third-party haulers. This could include— • Years of service—are they relatively new or recently purchased? • Fleet size—small fleets are not necessarily indicative of poor service, but it is certainly difficult to cover deliveries when one of three trucks breaks down unexpectedly. • Geographic footprint—similar to fleet size. Can a carrier cover deliveries under stress or cover long-haul deliveries during a supply disruption? • Crash history—aside from illustrating a history of unsafe driving and possibly poor hiring decisions, a string of severe crashes (major property damage, injury, fatality, etc.) could foreshadow the decline or unexpected cessation of operations. •

Transportation

- - - Po-ta-to, Po-tah-toLanguage Controversy with Hours of Service Rule

In late 2014, Congress ordered the Federal Motor Carrier Safety Administration to suspend enforcement of some controversial provisions tied to the Hours of Service (HOS) restart rule, specifically the provision requiring drivers to take two 1 a.m. to 5 a.m. periods as part of their 34-hour off-duty period and wait 168 hours from the beginning of one restart period to the beginning of the next. A year later when President Obama signed into law the FAST Act, he also approved fiscal 2016 omnibus funding requiring a study of the restart rule, specifically explaining how the rule offers improvements “related to safety, operator fatigue, driver health,” as well as work schedules. Unfortunately, this legislation—intended to strengthen the suspension of a few provisions surrounding the 34-hour restart rules—could actually nullify the 34-hour restart completely. The omnibus bill extends the suspension until the Department of Transportation determines whether or not the more restrictive provisions provide “a greater net benefit for the operational, safety, health and fatigue impacts.” In truth, the suspension can only be lifted if the DOT can establish that commercial motor vehicle drivers who operated under more restrictive restart provisions between July 1, 2013, and the day before the restart provisions were suspended “demonstrated statistically significant improvement in all outcomes related to safety, operator fatigue, driver health and longevity, and work schedules.” But what happens if the agency agrees with the suspension? What comes next? 47

According to an urgent letter to Truckload Carriers Association members, the Department of Transportation had determined if the FAST Act “contains no language to direct our industry on a restart provision, then there is no restart provision to abide by.” The American Trucking Association (ATA) supports permanently suspending “bolt-on” provisions, which may adversely impact safety and productivity by forcing trucks onto the road during peak morning traffic hours. However, legislators must instruct DOT authorities in the event of a decision upholding the suspension. Finally, Congress ordered the FMCSA to produce a study comparing the effectiveness of the two restart systems as part of the original 2013 suspension. However, because the study was not completed prior to the end of the fiscal year and legislators chose to continue the suspension through the highway appropriations bill instead, a negative study at this point could prompt the DOT to vacate the entire restart provision, as technical corrections cannot be made to an appropriation bill. The faulty bill would instead be nullified, allowing legislators to pass a new bill. The ATA emphasized that the daily work rules—11 driving hours, 14 onduty hours, 10 off-duty hours, and a 30-minute rest break—are not affected by the highway bill language and are not “on the table for discussion” as part of any restart-related solution. •

Transportation

What you should know about Electronic Logging Devices (ELDs)

According to new design parameters, devices must—

On December 16, 2015, the Federal Motor Carrier Administration announced changes to the Federal Motor Carrier Safety Regulations (FMCSR), creating minimum performance and design standards for hours-of-service electronic logging devices, or ELDs. To improve HOS compliance and enforcement, new regulations dictate when and how drivers will convert to ELDs while also establishing design parameters for device manufacturers.

• Secure to the truck’s interior, preventing damage and making it easier to access • Easily detach for inspection, allowing enforcement officer to verify data from outside the vehicle • Display specific data—driver name, carrier name and address, total engine hours, total miles for drive period, and a detailed malfunction log

With few exceptions, drivers still using paper logs will need to install an ELD to record their hours of service before December 16, 2017. Those already using compliant automatic on-board recording devices (AOBRDs) will receive an additional two years to upgrade existing equipment to units compliant with new regulations. The few exceptions include short-haul or time-card drivers, affecting drivers operating heavy trucks within a 100-air-mile radius and non-CDL drivers operating smaller motor vehicles within a 150-air-mile radius. Regulators will rescind exclusions, however, if exempt drivers exceed time-card service limits on more than eight days during any rolling 30-day period. Tow/drive-away operators will receive a pass as well, along with anyone operating vehicles manufactured prior to 2000 as their onboard computers don’t support ELDs.

• Prevent/report physical or electronic tampering • Maintain data encryption software • Log users accessing the ELD system • Account for all drive time • Track all engine start and stop time • Capture location at specific time intervals • Make two specific automatic changes of duty status Carriers must educate themselves and perform adequate due diligence before selecting an FMCSA-certified device. The FMCSA may de-certify any device found to be non-compliant with the new requirements. To aid carriers in their research, the FMCSA compiled ELD information on their website at www.fmcsa.dot.gov/hours-service/elds/electronic-logging-devices and intends to update it often. Carriers should also check back frequently for changes to the program. • 48

Transportation

Mobile Refueling for DEF Safety Does your company have the ability to wet hose Diesel Exhaust Fluid (DEF)? If not, maybe you should! More commercial and industrial fleets, which do not want their drivers directly fueling their trucks, are moving in the same direction when it comes refilling DEF tanks. There are also commercial and industrial fleets, such as those serving the construction industry, that operate on remote job sites away from their DEF storage tanks. For these fleets, their need to wet hose DEF directly into costly offroad equipment is quickly rising. There are multiple ways to deliver DEF to offroad commercial and industrial fleets, whether by individual 2.5 gallon jugs (smaller applications), 55 gallon drums or 330 gallon totes delivered via a smaller sprinter van or flatbed truck, or a dedicated DEF tank truck. All of these options are utilized across the U.S., with the most prevalent option being 330 gallon totes on board a box truck or sprinter van, which carries a lower cost investment and driver than a dedicated or co-dedicated (i.e. fuel and DEF) tank wagon. Further, adding a dedicated DEF tank to an existing tank wagon adds weight and reduces the amount of fuel a tank wagon can carry.

So, how is this service priced today? We’ve seen this service priced a variety of ways, including a flat price per gallon, a price per gallon plus a delivery fee, and an hourly fee plus product cost. Pricing depends upon the number of gallons delivered, the time on location, the number of DEF touches and whether or not a dedicated DEF truck is used to make DEF deliveries. In addition, Mansfield is seeing barcode/scanner technology enter the DEF wet hosing space that integrates a barcode/scanner to provide faster and more accurate tracking and reporting •

Mansfield’s National Supply Team 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

Nate Kovacevich

Senior VP of Supply and Distribution

Supply Manager

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.

Matt Elder

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.

Evan Smiles Supply Mangager Evan began his career with Mansfield as an intern in the supply department, assisting in the Southeast region. He quickly advanced into the role of Northeast Supply Optimization Analyst and currently holds the position of Northeast Supply Supervisor, handling various tasks including supply bids, day deal purchasing, long haul analysis, contract negotiations/fulfillment and supply optimization.

West Coast Supply Supervisor Matt is responsible for managing refined product purchasing for both contract and bulk pipeline movements, scheduling, hedging, supply bids, optimization and fixed price analysis in California, Oregon, Washington, Idaho, Nevada and Arizona.

Jessica Phillips Renewable Supply & Distribution Supervisor

Dan Luther Sr. Supply Manager

Jessica is based out of Houston, Texas, and is responsible for nationwide purchasing, hedging, and the distribution of renewable fuels. Since joining the Mansfield team in 2009, she has held multiple titles: Contracts Coordinator, Regional Supply Analyst, Senior Strategic Supply Analyst, and as of late, Renewables Supply Supervisor. Jessica has a strong background in refined products’ scheduling, contracts, optimization and market analysis and continues to expand her knowledge in renewable and alternative fuels.

Dan is responsible for refined products supply and hedging in Mansfield’s region running from Texas north to Chicago. Before joining Mansfield, Dan managed barge, rail, and truck fuel deliveries as well as ethanol trading responsibilities across the U.S.

Ed Young

Chris Carter

Vice President of Commercial Operations, Mansfield Power and Gas, LLC

Supply Manager Chris is responsible for refined product purchases including contracts, day deals and rack purchases. The Southeast region covers Florida, Georgia, Mississippi, Alabama, Tennessee, South Carolina, North Carolina, Virginia and Maryland. His responsibilities also include supply contracts and current bids. Chris manages pipeline shipments of gas and diesel on the Colonial, Plantation and Central Florida Pipelines.

Ed provided consulting services to Mansfield Energy Corporation in the management and optimization of natural gas and power assets to wholesale and retail clients. In July 2015, he accepted a permanent position with Mansfield Power and Gas, LLC (MPG). As Vice President of Commercial Operations, he is currently charged with managing the day to day operations of MPG to include counterparty enabling, pricing power and gas opportunities, development of hedge and optimization strategies, and creating marketing material and fundamental analysis presented to customers. © 2016 Mansfield Energy Corp.

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