FUELSNews 360 - Q4 2014 by FUELSNews

M A R K E T

N E W S

I N F O R M A T I O N

OCTOBER–DECEMBER Q1

4th QUARTER Q4

2 0 1 4

Q11

4th QUARTER Q4

Q4 2014 Executive Summary As a year defined by declining crude and soaring energy savings drew to a close, consumers, investors, producers, politicians, and news outlets across the globe studied the crude oil market intently, wondering “when will it correct? Just how low will it go before rebounding? Will domestic producers cave to negative pricing pressure abroad? Will retail fuel prices share in crude’s roughly 50-percent decline?” While losses in the third quarter proved steep, fourth quarter declines really hit their stride following OPEC’s Thanksgiving Day meeting. Like a groundhog seeing its shadow, OPEC’s declaration of unwavering production quotas prognosticates six more, in this case, months of deflated crude oil —and, consequently, refined product— prices. Even before OPEC’s pivotal announcement, the International Energy Agency (IEA) suggested in its November Oil Market report that 2014’s oil price rout could easily extend into the first half of this year. The Paris-based energy watchdog believes oil markets have entered a new era with lower economic growth and consumption out of China and increased supply out of the U.S. Consequently, the downward pressures causing oil prices to drop approximately 50 percent since late June may not be finished. Though the IEA makes the market’s fourth-quarter woes seem simple, in reality, disappointing fourth quarter demand across Europe and much of Asia (not just China) culminated in the current oversupply sapping strength from petroleum prices. Furthermore, increased supplies out of the U.S. mean nothing without OPEC’s refusal to lower production quotas and rising production from Russia, Iraq, Iran, Canada, and Libya (turbulent as it may be). Until global demand fully rebounds from long-term economic troubles, producers are left with two options: accept slimmer margins or sacrifice market share. Crude oil produced substantial savings for buyers in the fourth quarter, but refined products trailed considerably; though wholesale buyers still saved more than retail consumers as gas station owners proved reluctant to part with hefty margins. Across the nation, retail markups nearly doubled when comparing pump prices to NYMEX futures, suggesting consumers still haven’t joined the party. Even so, retail gasoline consumers saved an estimated $7.5 billion once the slide began while declining retail diesel prices netted drivers approximately $2.1 billion in just six months. So, what’s to come? In the last weeks of the fourth quarter, producers announced severe cuts to 2015 capital expense budgets, citing weak returns on the nation’s less productive plays. As a result, drillers will add fewer rigs in the coming months while existing wells run dry, threatening the momentum which propelled domestic output to current 40-year highs and supporting the price of all petroleum products. At the same time, a growing contango in the crude oil market could prompt sellers to defer delivery of barrels until prices rebound slightly this summer, supporting prompt month futures and bolstering fuel prices further. Further downstream, refiners will contribute to higher refined product prices toward the close of the first quarter as they enter maintenance season. Finally, demand for petroleum products should increase this spring as temperatures warm, key global economies gain their footing, and consumers use their energy savings to travel. All-in-all, the market’s on a path to recovery and we can expect fuel prices to firm in the first quarter before rising steadily in the second.

Index FUELSNews 360° Quarterly Report Q4 2014 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.

Overview

October through December, 2014

PADD 1A, Northeast

Fourth Quarter Summary

PADD 1B & 1C, Central & Lower Atlantic

PADD 2, Midwest

PADD 3, Gulf Coast

PADD 4, Rocky Mountain

PADD 5, West Coast, AK and HI

Canada

Economic Outlook 6

Global Economic Outlook

U.S. Economic Outlook

Fundamentals 38

Regional View

OPEC Speeds Decline

Crude Reserves Grow

Crude-by-Rail Suffers

Retail Margins Grow

FUELSNews 360° Commentaries 18

Commentaries; Andy, Dan, Evan S. and Jessica

Commentaries; Chris, Evan P. and Nate

Alternative Fuels 38 42

Renewables Natural Gas

Electrical Power

Transportation & Logistics

Diesel Exhaust Fluid (DEF)

FUELSNews 360˚ Supply Team

Overview October 2014 through December 2014 Dragging refined products with them, WTI crude futures fell into the New Year at less than $55 a barrel, extending the market’s third quarter slump to nearly 50 percent. Despite pleas from fiscally-strained member nations, OPEC leaders demonstrated unwavering commitment to maintaining market share during their November 27th meeting in Vienna, causing crude oil to tumble nearly $20 a barrel (26%) in a single month and signaling the start of a price war against American producers. Speaking of which, domestic production rose above 9 million barrels a day for the first time in thirty years, contributing to the world’s overabundant crude supply, but weak global demand forced oil prices to their lowest value in over five years. Now, investors and end users alike play a daily guessing game of where the floor will form.

WTI Crude Futures

(Dollars per Barrel)

SSaudi Arabia Announces November Price Cut Sa CCalls for Emergency OPEC Meeting Denied Ca Congress Votes Down Keystone XL Legislation OOPEC Holds Firm to Current Production Quotas China’s PMI Reaffirms Weak Global obbal DDemand

EIA Reports Surprising Inventory Buildss

FN360o Source: Oil Price Information Service (OPIS)

Overview Fourth Quarter Summary Moving in tandem with crude oil’s nearly 50-percent plunge, the onset of winter temperatures provided little support to distillate prices. Consequently, heating oil (diesel) futures plummeted over 30 percent —80 cents a gallon— since the market’s slide began in late June. On the other hand, the weight of falling crude oil prices pulled RBOB (gasoline) futures down more than 40 percent (over a dollar per gallon). Minimal refinery disruptions, weak domestic demand, and the presence of a domestic surplus supported the downward momentum of refined product prices throughout the quarter.

Summary, Fourth Quarter 2014

1.8466 1.4353

53.27

17823.07

FN360

Source: Bloomberg Finance L.P. 5

IIIII II

Global Economic Outlook

IIII II I

Fourth quarter news centered on Russia’s faltering currency, Europe’s lackluster growth, and China’s stagnating industrial activity. While negative headlines typically bolster product prices, these all communicate one discouraging message —

“declining demand.” Drastically reduced crude oil prices and tightening western sanctions have taken their toll on Russia’s economy — particularly the ruble, which declined nearly 30 percent against the dollar since October. Under President Vladimir Putin’s direction, the nation’s economic leaders sold off large portions of their foreign currency reserves while its central bank raised key interest rates by 6.5 percent overnight, up to 17 percent, in a midDecember bid to reinforce the ruble. Still, the International Monetary Fund (IMF) indicates ﬂat GDP growth for Russia in 2014 and predicts a mediocre 0.5-percent growth rate for 2015.

Meanwhile, the European Central Bank (ECB) struggles to resuscitate the Eurozone’s lifeless economy. Despite negative interest rates and stimulus debate, September forecasts of 1.6percent growth this year have been revised to a less optimistic 1.0 percent. The ECB’s governing council discussed quantitative easing (QE), which would include the purchase of sovereign debt — an unpopular idea with Germany, the primary ﬁnancier of the European Union. However, with Germany narrowly avoiding a fullon recession in the third quarter and failed presidential elections in Greece threatening the region’s common currency, some sort of QE is likely in the near future. Finally, China, the world’s second largest economy, continues to see slowed growth. The real estate market, which propelled the Chinese economy forward in recent years, stumbled in the second half of 2014 as home sales fell nearly 10 percent from a year ago due to new government regulations slated to begin this year. These factors contribute to even lower projections for economic growth in 2015. China’s GDP is expected to barely clear 7 percent growth in 2015, marking the lowest projection in nearly a decade. •

IIIII II

U.S. Economic Outlook

IIII II I

As inﬂuential economies abroad search for footing, the United States climbs steadily higher. In December, consumer sentiment reached into the 90s for the ﬁrst time in more than seven years. While previous fourth quarter forecasts of 2.6-percent GDP growth would fall short of the two previous quarters, holiday spending increased by 4.5 percent in comparison to 2013 and unemployment rates reached six-year lows of 5.8 percent. In spite of persistent downward pressure from Europe and China, the U.S. economy is projected to experience even stronger growth in 2015.

Consumer Sentiment Index October

November

December

86.9

88.8

93.8

Consumer Sentiment Index Interpreting comments by Federal Reserve chairwoman Janet Yellen, analysts expected the Fed to end efforts suppressing interest rates early this year, yet lackluster inﬂation stemming from lower energy prices and good—not great— employment gains lead experts to believe the Fed will instead hold interest rates near zero until at least September. Consequently, lower mortgage rates through the summer buying season should spur 2015 real estate sales well beyond those recorded last year. •

FN360

Source: University of Michigan 7

“ While previous fourth quarter forecasts of 2.6-percent GDP growth would fall short of the two previous quarters, holiday spending increased by 4.5 percent in comparison to 2013 and unemployment rates reached six-year lows of 5.8 percent.”

U.S. Economic Outlook The Producer Price Index (PPI), a measure of change in producers’ selling prices, once again weakened in the fourth quarter. Final demand services, aside from transportation, were the only category to show real strength; yet core prices, which exclude food and energy, still proved hardier than headline prices. Falling energy costs, which heavily inﬂuenced headline PPI this quarter, easily eclipsed modest gains by other categories, signaling a bearish direction for both interest rates and the value of the dollar.

Headline Producer Price Index Month-to-Month Change October

November

December*

-0.60%

-1.10%

0.00%

October

November

December

86.9

88.8

93.8

Headline vs. Core Producer Price Index (Year-over-year Percent Change, Seasonally Adjusted)

FN360

Source: U.S. Bureau of Labor Statistics

The Consumer Price Index (CPI), measures change in prices paid by urban consumers. In the fourth quarter, lower prices for used cars and apparel stifled core index prices and outweighed slight gains in food and services. The more volatile headline CPI suffered due to plummeting energy costs, particularly gasoline. If fuel prices find their floor, inflation rates could finally pick up, leading the Fed to increase interest rates for the first time since the global recession began.

Headline Consumer Price Index Month-to-Month Change

Headline vs. Core Consumer Price Index (Year-over-year Percent Change, Seasonally Adjusted)

October

November

December*

-0.60%

-1.10%

0.00%

October

November

December*

-0.25%

-0.54%

0.07%

FN360

Source: U.S. Bureau of Labor Statistics 9

Fundamentals Balancing Domestic Production with Consumption and Exports

OPEC Refuses to Repeat History After nearly ﬁve hours of tense debate, OPEC’s Secretary General announced on Thanksgiving Day the 12-member coalition would maintain its 30 million barrel a day production quota for at least the next six months. Traders reacted quickly, generating the greatest single-day losses since the global recession. When the dust settled, Brent crude futures had fallen 6.7 percent while WTI crude retreated 7.9 percent, extending losses since June’s $107.26 peak to more than 35 percent.

WTI Crude Futures

FN360

Source: New York Mercantile Exchange (NYMEX)

U.S. crude oil production has nearly doubled in the last ten years through unconventional — and costly — drilling methods, such as horizontal drilling and hydraulic fracturing. Rapid economic growth and the resulting demand for petroleum products propelled crude oil prices to new heights, supporting high-cost drilling operations and fueling the nation’s growing output. But OPEC’s decision proves those economics are shifting.

Forty years ago, demand consistently outstripped supply and OPEC nations easily controlled prices through production quotas, but improved fuel economy, declining alternative energy prices (nuclear, natural gas, etc.), and sluggish economic growth among the world’s industrialized nations put producers on the defensive. By 1985, Saudi producers found their output cut by nearly two-thirds in pursuit of higher crude oil prices and domestic crude imports plummeted while newspapers touted the global glut threatening the petroleum industry. Sound familiar?

In fact, OPEC’s efforts to support crude values between 1980 and 1985 only encouraged high-cost suppliers and rogue OPEC nations to increase production — chasing record profits — and add to the market’s overabundance of crude oil. In the end, Saudi producers, tired of sacrificing while competitors and unreliable partners profited, ignored OPEC limits and cranked production to the max. If OPEC had voted to cut production rates this quarter, history would have likely repeated itself, only delaying the inevitable decline of crude oil prices. While the crude oil collapse drove several oilproducing nations to the brink of bankruptcy and dealt a lethal blow to the USSR’s energydependent economy, bargain fuel prices provided struggling consumers a much needed cash infusion. As discretionary funds grew, consumer spending rose; subsequently raising countries mired in economic quicksand to more solid ground. At the same time, growing consumer demand fueled crude oil’s rebound, bringing refined products along for the ride. So, what’s the moral of the story? Here it is — supply imbalances will always be resolved in a capitalist global economy, creating rare opportunities for consumers to lock prices below the market’s true value. For equities, it was the financial collapse of 2008. For commodities, you’re seeing it now. •

Fundamentals

Did You Know?

According the U.S. Energy Information Administration (EIA), lease condensates are light liquid hydrocarbons—mostly pentanes and heavier hydrocarbons— recovered from lease separators or field facilities at natural gas wells. They’ve also sparked significant debate regarding the nation’s crude oil ban in the last year.

Oil Reserves Rise to Near 40-Year High on Strong Production and Pricing RANK

COUNTRY

ESTIMATED CRUDE RESERVES (Billion Barrels)

While gains in crude oil reserves stemmed from improved operating conditions, natural gas reserves beneﬁted from strengthening economics. Last year, the 12-month average spot price for Henry Hub natural gas increased from $2.75 per million Btu (mmBtu) to $3.66 per mmBtu, opening the door for 31 trillion cubic feet (Tcf) of natural gas previously deemed too costly for consideration. Last year’s 10-percent rise in proved natural gas reserves offset the 26 Tcf decline seen in 2012 when prices fell from $4.15 per mmBtu.

According to the Energy Information Administration (EIA)’s annual report, domestic proved reserves of crude oil and lease condensate increased last year for the fifth year in a row, exceeding 36 billion barrels for the first time since 1975. Similarly, natural gas reserves rose last year, setting a new record of 354 trillion cubic feet in 2013. Defined as “recoverable under existing economic and operating conditions,” proved reserves benefited in recent years from technological advancements as well as increasing product prices. With the proliferation of horizontal drilling and hydraulic fracturing, volumes trapped in tight shale formations, previously considered unattainable, now contribute heavily to the nation’s proved reserves. North Dakota, for instance, accounted for 61 percent of last year’s 3.1 billion barrel increase as new drilling techniques granted access to approximately 1.9 billion barrels across the state’s Williston Basin and Three Forks sites. North Dakota’s proved reserves now exceed those beneath federally-leased Gulf of Mexico waters, earning it the No.2 spot among domestic oil reserves by state, behind Texas. 12

Rising domestic reserves certainly contribute to arguments for complete energy independence. However, even our 39 billion barrel record set in 1970 would barely place us in contention for the world’s Top Ten of proved oil reserves and No.9, Libya, beats that record by roughly 10 billion barrels before No.8, Russia, nearly doubles it at 60 billion barrels. Besides, the EIA’s assessment hinges on last year’s $97.28 per barrel average crude oil price. It’s important to remember that while our past successes were built on cheap, abundant energy from oil and coal, they’ve failed to scale with today’s energy and clean air needs. New, truly renewable sources of energy will be required before the next industrial era comes within reach. •

“ According to the Energy Information Administration (EIA)’s annual report, domestic proved reserves of crude oil and lease condensate increased last year for the ﬁfth year in a row, exceeding 36 billion barrels for the ﬁrst time since 1975.”

Fundamentals

BNSF Deals a Costly Blow to Domestic Crude Oil Producers

Becoming the first major U.S. railway operator to incentivize the retirement of less reliable railcars through fees, BNSF Railway Co. announced plans for a $1,000 surcharge on any shipment employing railcars not compliant with the Obama administration’s stricter regulations. Consequently, barrels shipped in DOT-111 containers after January 1st, already targets of a federally-mandated phase out, could cost refiners $1.50 per barrel more — roughly a 10 percent increase in cost. Combined with rapidly declining crude oil values, railcar surcharges may discourage exploration of fields with limited access to pipeline networks — specifically those in the Bakken region which connect to refineries in the East. 14

With approximately 75,000 non-compliant DOT-111s currently hauling flammable liquids across the nation, East Coast refiners could feel the pinch as cost-advantaged crude becomes that much harder to find. Lower global crude oil prices have some producers announcing severe budget cuts for the coming year and others already scaling back production. This could further influence their decisions as few pipelines exist in the Bakken region and transportation by rail remains the dominant delivery method. If that happens, East Coast consumers may experience an unpleasant rise in product prices at the same time seasonal demand for heating oil and distillates reach their peak. •

“ While capturing headlines and politicians’ attention this quarter, falling crude oil values presented a signiﬁcantly diminished impact on retail diesel prices.”

Fundamentals

Retailers Capture More than 50 Cents a Gallon on Energy Decline While capturing headlines and politicians’ attention this quarter, falling crude oil values presented a signiﬁcantly diminished impact on retail diesel prices. So, why did retail prices remain elevated while input costs collapsed and how long should consumers expect to wait before pump prices reﬂect the same savings?

Diesel Cost Comparison

FN360

Source: Oil Price Information Service (OPIS)

WTI crude oil futures have tumbled 47 percent while heating oil futures —the base for most diesel prices— shed roughly 35 percent since the market’s peak in late June. Wholesale diesel prices followed (down 38 percent) with the exception of October/November spikes driven by short Midwest supplies, but retailers retained the lion’s share of savings over the last ﬁve months, increasing wholesale-rack-to-retail diesel spreads by as much as 50 cents a gallon in some regions.

Regardless of whether the market’s on the rise or fall, retailers tend to react more slowly as theirs is a game of market share and price competition rather than reﬁnery runs and crack spreads. As a result, retailers often suffer extremely narrow margins while the market’s on the rise, but enjoy growing margins as wholesale prices decline. It’s important to note retailers typically will not suffer negative margins, but the sky’s the limit when wholesale prices are on the decline; consequently, retail consumers suffer the same spikes as wholesale buyers, yet they don’t enjoy the valleys that follow.

Fundamentals Notice this past January, margins along the East Coast collapsed as constricting supply produced a 40-cent price surge at the wholesale level while retailers remained relatively constant. Over the course of a month, retail prices absorbed rising wholesale costs, gradually increasing by 30 cents a gallon. However, wholesale prices shed the 40-cent premium over the next seven weeks while retailers hung on to higher prices and continue to collect inﬂated margins even today.

Wholesale vs. DOE Retail Diesel PADD 1A New England

FN360

Source: Energy Information Administration (EIA)

To answer the question of when retail prices will fall as far as crude or heating oil futures, look at historical rack-to-retail spreads. As shown below, PADD 4 wholesale prices retreated several times in the past, but retail prices never fall as far as wholesale prices.

Wholesale vs. DOE Retail Diesel PADD 4 Rocky Mountain

FN360

Source: Energy Information Administration (EIA)

In this example, wholesale prices in the 18-month period declined an average of 28 percent more than retail diesel prices. Why? Since retail prices won’t sink below wholesale values, retail’s fall is always cut short by rising costs and the consumer misses out on the market’s full decline. So, consumers hoping to capitalize on the market’s recent downfall should review whether bulk wholesale purchasing makes sense for their business. • 17

FUELSNews 360˚ Commentaries Andy’s Answer

BULL BEAR

Winston Churchill said, “There is nothing wrong with change, if it is in the right direction.” While the market exhibited bearish tendencies in September — declining roughly 12 percent since late-June — no one expected a collapse of this magnitude. In the last quarter, WTI crude futures shed more than 40 percent, heating oil futures lost more than 70 cents per gallon, and RBOB futures are a dollar lower than this time last quarter. The game of chicken between OPEC and domestic producers “bears” watching for the long-term winner (I’m also available for weddings, dinner parties, and other comedic acts). It appears U.S. operations are already under pressure as drillers shift longterm investment towards more cost-efficient locations. Along with lagging global demand, banks’ exodus from the market, and a stronger dollar make it hard to be bullish in this new era. Given the onslaught of financial institutions modifying their 2015 crude levels, we’re likely entering a new age in the fuel industry. Over the last two decades, strong demand justified higher energy prices, but slow economic growth across China and Europe, coupled with alternative energy sources, greater energy efficiency, and booming production, all contribute to weaker prices as the balance shifts to a buyer’s market. Until the global economy picks up steam, we’ll continue to see WTI crude between $45 and $75 a barrel versus the $85 to $110 a barrel we’ve grown accustomed to in recent years.

Dan’s Dissertation

BULL BEAR

I continue to be bearish crude oil and reﬁned products heading into Q1 2015. While values have already plunged considerably from June highs, there is more downward potential as producers don’t appear ready to cut production anytime soon. OPEC stood by its decision to keep output constant and the United Arab Emirates’ (UAE) energy minister said the cartel will wait at least three months before considering an emergency meeting. Similarly, while several domestic drillers have announced reduced capital expenditures next year, existing wells will continue pumping strong and output should, therefore, remain elevated in the short term. Lastly, I do not expect robust global demand at the start of the year, prolonging the current supply imbalance.

Evan’s Estimation

BULL BEAR

In the fourth quarter, petroleum products fell to their lowest values in over 5 years, thanks in part to an overabundance of crude oil in the global market. As a result, product prices remain low and rallies short-lived. I expect the oversupply to continue through the ﬁrst quarter and into the second quarter of 2015. With regards to the Northeast’s fundamental supply and demand, I don’t expect winter weather to impact heating oil prices as they did between January and March of 2014 as several forecasts depict warmer temperatures for the region. With temperatures staying closer to average, fuel oil and diesel demand will rise slightly (as it does every winter) while staying well below last year’s highs.

Jessica’s Judgment

BULL BEAR

I feel I’ve been saying it all year long, but it’s a tough time to be in renewables. Anyone who stood to profit from the retroactive 2014 biodiesel tax incentive probably forewent their holiday vacation to boost the year’s sales as the credit expired again on the 1st, leaving sellers no guidance for 2015 budgets. Without the credit, the security of a finalized Renewable Fuel Standard (RFS), and plummeting diesel prices that feedstocks couldn’t keep up with if they tried, Q1 2015 is already giving me heartburn! Extremely competitive diesel prices currently discourage biodiesel consumption in non-mandated states or those without tax incentives. So, unless you’re health conscious or environmentally friendly, I don’t see the benefit in bioblends at this time.

FUELSNews 360˚ Commentaries (Jessica’s Judgment continued)

As crude pushes toward $50 a barrel and demand for this hot commodity increases, I’m expecting petroleum products to ﬁll a larger percentage of railcars. The resulting railcar shortage — for both feedstocks and ﬁnished products — coupled with winter’s impact on an already strained supply chain will almost certainly create delays, raising the price of renewables and all bioblended products. On the bright side, I have high hopes for Q2. I just recommend hibernating through Q1!

Chris’ Concept

BULL BEAR

With crude values down more than 50 percent since late June, I want to believe the market contains more upward potential than we’re giving it credit, but I don’t think we’ve hit the bottom just yet. Despite ongoing violence in Libya, Iraq, Syria, and Ukraine, the market remains oversupplied, requiring either an increase to demand or a cut in production rates before prices change significantly. In the U.S., we’re seeing positive signs for refined product demand — lower energy costs encourage drivers to get out more, the transportation industry reports strong year-over-year growth, and lower interest rates support construction and manufacturing through increased home sales. European markets, on the other hand, still struggle with weak industrial growth. Similarly, China is expected to report its weakest annual growth rate in more than two decades. Combine weak global demand with OPEC’s refusal to curb production and you’ll understand why I have to be bearish for the first quarter.

Evan’s Expression

BULL BEAR

I’ll go against the mob this quarter and say fuel prices will develop bullish tendencies next year, but not before crude bottoms out in the mid to high $40s in January. Look for support late in the first quarter. While domestic oil producers already announced price-driven spending cuts for 2015, existing rigs can be expected to churn out 9 million plus barrels a day for the first half of the year. By the third quarter, however, declining capital investment should take its toll and we’ll see U.S. production back off record highs. Refined product values haven’t hit their lowest, either. Cheap crude, paired with what’s expected to be a comparatively mild winter, should encourage price competition and benefit consumers. The U.S. Department of Commerce reported surprisingly robust GDP growth in the third quarter and that trend supposedly continued into the fourth as reduced energy costs translated to greater consumer spending. Expect a flurry of acquisitions in the first half of next year as capital spending shifts from asset development to portfolio expansion. Investors will likely focus on midstream assets and the consolidation of retail chains, but don’t be surprised to see a rising number of independent crude oil producers selling operations to the big dogs as losses mount in the new year.

Nate’s Notion

BULL BEAR

Energy markets will bottom out in Q1 and begin forming a base for recovery in the 2nd half of 2015. Crude oil prices are currently trading below $54 a barrel which puts both the Bakken and West Canadian Select crudes in the high $30’s. A number of shale oil producers already announced signiﬁcant cuts to their 2015 CAPEX spending, eventually cutting rig counts and production growth. While OPEC’s not scheduled to meet until next summer, an unexpected intervention on their part, supporting crude prices, would certainly prove signiﬁcant. They appear to be holding strong on their late-November decision, allowing oil prices to remain depressed while they maintain market share, but the organization hasn’t been entirely in agreement on this call. Oil’s dramatic decline hurt oil-based economies in the Middle East, Russia, and Venezuela, each of which relies heavily on oil revenues to fund social programs. They’ll need to make a decision whether to reinvest in new production or distribute revenues back to their citizens to prevent political backlash and/or uprisings until oil prices rebound. I predict crude prices will bottom out near the high $40’s in early January and move back into the $60’s on stronger demand and a slowdown in production. 19

Regional Views PADD 1 East Coast

PADD 1A Wholesale vs. DOE Retail Diesel

(dollars per gallon)

PADD 1A Northeast

FN360o Source: Energy Information Administration (EIA)

Pennsylvania Supply Disruptions Through much of the fourth quarter, portions of Western and Central Pennsylvania suffered short diesel supplies. In the Pittsburgh market, local wholesale diesel prices exceeded regional cash values by more than 25 cents a gallon while Altoona netbacks exceeded 15 cents a gallon. Positive netbacks indicate small-scale supply disruptions which result in premium prices for local consumers. Meanwhile, negative netbacks appear where a supply glut has formed, requiring local marketers to discount their products. Pennsylvania’s positive netbacks this quarter resulted from pipeline constraints, reﬁnery issues, and winter weather.

Did You Know?

The difference between NYMEX futures and the regional cash price is referred to as “basis” while the difference between a regional cash price and a local market price is referred to as a “netback.” Both can be positive or negative and indicate a particular region or market’s demand for refined products.

First, the Buckeye Laurel pipeline, which carries refined products from the Philadelphia area to Pittsburgh, battled delivery delays and strict allocations. Next, severe disruptions at several key refineries in Ohio, Illinois, and Minnesota created a black hole for refined product, consuming all available gallons and eventually diverting product from East Coast markets in lieu of more profitable netbacks. As a result, Ohio Valley customers frequently received deliveries either from or previously bound for Pittsburgh and Altoona, depleting existing inventories and driving local prices higher. Finally, the first cold snap of the 2014/2015 winter season prompted farmers in the Midwest to rapidly harvest their crops, creating additional distillate demand during possibly the worst supply disruption of the year. •

Heating Oil Prices Ease on Declining Crude Oil

PADD 1 East Coast PADD 1A Northeast

“ Like much of the industry,

Northeast heating oil consumers are beneﬁting from an overabundance of product and a lack of demand, allowing more reasonable heating oil prices to persist this winter.”

With crude values at levels not seen in over five years, consumers should enjoy a much needed break in heating oil prices through the 2014/2015 winter season even if demand increases. In addition to lower crude prices, distillate supplies in the Northeast currently surpass suitable levels and there’s still opportunity for shippers moving product between the Gulf Coast and New York Harbor markets due to lower Gulf Coast pricing. With predictions for a warmer winter in the Northeast, favorable temperatures in the first quarter should also decrease heating oil demand. The National Oceanic and Atmospheric Administration (NOAA) forecasts a warmer than average winter for the Northeast while WeatherIntel Services contradicts the NOAA, though refrains from predicting a repeat of last year. Like much of the industry, Northeast heating oil consumers are benefiting from an overabundance of product and a lack of demand, allowing more reasonable heating oil prices to persist this winter. •

PADD 1 East Coast PADD 1A Northeast “ The latest in a long line of owners, SilverRange partner Harsh Rameshwar cites the facility’s strategic location along Atlantic crude oil shipping routes and access to European and East Coast markets as major contributors for the purchase.”

Northeast Sales and Acquisitions Continuing a string of acquisitions going back to the second quarter, investors doubled down on assets in the fourth even as petroleum values fell; potentially changing more than just the face of fuel in the Northeast. First, consumers may have noticed Mutual Oil, a 77-year-old, family-owned business with a significant presence in the Northeast, sold its branded fuel and trucking operations to focus on expanding its unbranded marketing along the East Coast. 7-Eleven acquired the branded fuels while the Kenan Advantage Group (KAG) secured the trucking business. Next, Sprague Operating Resources successfully acquired Castle Oil Corporation in late December, increasing its footprint in New England with an emphasis on the New York City area. The deal included Castle’s Port Morris terminal assets, the city’s largest deep-water petroleum products terminal capable of storing 907,000 barrels of diesel, heating oil, biodiesel, and asphalt products. Following the acquisition, Sprague’s terminal assets amount to nearly 11 million barrels in storage capacity across 18 facilities. Operations will continue under the Castle brand name for the time being, but customers will likely see some new product offerings, such as natural gas and electricity, listed on the company’s website. Further upstream, Petroleum Products Corporation (PPC), the largest privately-owned terminal operator in Pennsylvania, appears to have a buyer for its Pennsylvania 4-million-barrel terminal network. Still fresh on locals’ minds following the second quarter acquisition of Hess’ retail business, Marathon Petroleum reportedly leads the pack of potential buyers, presumably acquiring midstream assets in support of their growing retail presence. Given PPC’s significance in Pennsylvania markets, this sale could easily alter the unbranded wholesale business within the state. Finally, at the start of the fourth quarter, North Atlantic Refining, a subsidiary of Korea National Oil Corporation (KNOC) and a source of products bound for New England markets, sold its 115,000barrel-per-day refinery in Come by Chance, Newfoundland to SilverRange Financial Partners, LLC of New York. The latest in a long line of owners, SilverRange partner Harsh Rameshwar cites the facility’s strategic location along Atlantic crude oil shipping routes and access to European and East Coast markets as major contributors for the purchase. Recurring operational issues have been blamed for poor profitability at the Come by Chance refinery in recent years, but SilverRange expects the facility’s flexible crude slate, limited local competition, and established network of branded stations to offer investors a stable margin asset. •

Come by Chance Reﬁnery Terminal 22

PADD 1 East Coast PADD 1B & 1C Central & Lower Atlantic PADD 1B Wholesale vs. DOE Retail Diesel

FN360

Source: Energy Information Administration (EIA)

PADD 1C Wholesale vs. DOE Retail Diesel

FN360

Source: Energy Information Administration (EIA)

ÂŠ 2015 Mansfield Energy Corp.

PADD 1 East Coast

Florida Gas Peaks due to New York Harbor Opportunities

PADD 1B & 1C Central & Lower Atlantic

While Florida retail gasoline averaged $2.68 per gallon this December —an 84-cent-per-gallon

“ Most often, Florida consumers

discount to what Floridians paid this time last year— it would be easy to assume Florida is experiencing the same relief we’re seeing across the rest of the industry.

Florida Retail Gasoline vs. NYMEX RBOB Futures

suffer steeper markups due to short supply brought on hurricanes, heavy fog, or production disruptions at the product’s point of origin, but 2014 proved an unusually quiet year for both stormy weather and Gulf Coast reﬁners.”

FN360

Source: Energy Information Administration (EIA)

December 2013, January RBOB futures —the base for Gulf Coast gasoline products— were trading around $2.70 per gallon while Florida retail prices averaged $3.52 per gallon, representing a 23-percent markup to the NYMEX. December 2014, January RBOB futures shed a dollar a gallon to $1.60 per gallon while retail prices fell only 84 cents per gallon, nearly doubling the state’s premium to the NYMEX at 40 percent.

As explained earlier, it’s not uncommon for retail prices to lag during periods of extreme volatility, but why does Florida suffer one of the nation’s highest markups? Most often, Florida consumers suffer steeper markups due to short supply brought on hurricanes, heavy fog, or production disruptions at the product’s point of origin, but 2014 proved an unusually quiet year for both stormy weather and Gulf Coast reﬁners. However, something else proved unusual last year —New York Harbor’s premium to Gulf Coast gasoline. With Florida supplied recently by more Jones Act Vessels, New York Harbor’s added thirst for gasoline led to shorter supply in the Sunshine State as vessels bypassed southern ports for higher margins in the Northeast. Consequently, wholesale diesel prices remained elevated while the rest of the nation fell and Florida retailers were inclined to pass the expense on to their customers. •

Plantation Pipeline Shutdown Stresses Southeast Markets It wasn’t until suppliers noticed severe delays in their pipeline shipments that a spokesman for Plantation Pipeline announced the discovery of a pin-sized hole near Belton, SC, requiring the pipeline to close for repairs. Normal operations were initially expected to resume early the next day, but repairs took longer than anticipated, delaying operations an extra day. In most markets, the multi-day shutdown of a single pipeline wouldn’t immediately spell disaster, but much of the Southeast and several Northeast markets receive the majority of their reﬁned products via the Colonial or Plantation pipelines. Consequently, the delay in reﬁned product shipments aggravated already slim supplies to create a supply imbalance, which would typically reward shippers who quickly deliver products to the affected areas. Not the case in this market. Throughout the fourth quarter, enticing premiums across the Midwest turned the Southeast into a discount market. By the end of October, U.S. Gulf Coast diesel traded 40 cents a gallon below what a Chicago buyer paid and 50 cents below Group 3, creating an opportunity for suppliers capable of trucking products from Tennessee, Alabama, and other Gulf Coast markets to capture additional margin. Just as Midwest disruptions were on the mend, New York Harbor began trading at 37-cent premiums to Gulf Coast diesel, further complicating the short supply situation triggered by the Plantation shutdown. •

“ In most markets, the multi-day

shutdown of a single pipeline wouldn’t immediately spell disaster, but much of the Southeast and several Northeast markets receive the majority of their reﬁned products via the Colonial or Plantation pipelines.”

Legislators Says “No” to Atlantic Basin Refining, HOVENSA slips back into Limbo Late in the fourth quarter, senators of the Virgin Islands voted down an agreement to sell St. Croix’s 500,000-bpd HOVENSA refinery, claiming the proposed purchase by Atlantic Basin Refining, Inc. (ABR) would not benefit the government financially. Governor John de Jongh Jr. fears the legislation’s rejection could cost locals dearly as ABR planned to hire more than 700 workers and invest over $1.6 billion through fixed payments. When the facility closed in 2012, it employed more than 2,000 workers and supplied refined products to coastal markets across the East Coast. Since then, demand for Jones Act vessels skyrocketed, driving transportation costs considerably higher and encouraging markets such as Charleston and Jacksonville to adopt New York Harbor pricing methodologies. While the Southeast market learned to cope without HOVENSA, the facility’s significant volume and exemption from Jones Act requirements would have made a welcome impact on the region’s product prices and availability. • 25

HOVENSA’s St. Croix reﬁnery terminal

PADD 2 Midwest

PADD 2 Wholesale vs. DOE Retail Diesel

FN360o Source: Energy Information Administration (EIA)

Midwest Diesel Skyrockets on Tight Supply and Robust Demand Reduced refinery operations and strong agricultural demand throughout the Midwest resulted in volatile fourth quarter diesel prices last year. Beginning in October, seasonal refinery maintenance amid already thin inventories set the stage for impending supply constraints. Enter the remnants of Super Typhoon Nuri, bringing unseasonably cold weather to the nation’s farmlands. Agricultural fuel demand spiked as farmers rushed to complete the fall harvest before cold, wet weather ruined crops. According to the EIA, this one-two fourth quarter punch forced PADD 2 diesel inventories to seasonal lows while daily demand proved significantly stronger than experienced in recent history, contributing to frequent product allocations and terminal outages. A slate of unexpected issues exacerbated the tight supply. The Mid-Valley crude pipeline shutdown after springing a leak near the Louisiana border, leading to reduced Ohio refinery production and drawing diesel barrels from Chicago markets. Additionally, the Badger Pipeline – which feeds local markets Argo and Des Plaines up to Madison, WI from the area refineries – was shut down for nearly a week as digging nearby caused the pipeline to shift, stranding products at refineries while traders scrambled for other sources of supply. Lastly, Flint Hill’s 320,000-bpd Pine Bend, MN refinery remained shut down for several weeks as a winter storm damaged power to the plant. 26

As a result, traders in Group Three and Chicago diesel markets engaged in a bidding war for Gulf Coast pipeline shipments via the Explorer and Magellan systems. At the end of October, Chicago traders were caught short and forced to pay near historic premiums to NYMEX futures. On Friday, October 31st, Chicago cash diesel prices soared over 25 cents per gallon in a single day to settle nearly 60 cents per gallon over NYMEX heating oil futures. Not to be outdone, Group Three cash diesel increased 20 cents a gallon just two trading days later on Tuesday, November 4th, settling 46 cents a gallon over NYMEX futures.

PADD 2 Midwest

Midwest Diesel vs. NYMEX Heating Oil (Dollars per Gallon)

“ Chicago traders were caught short

and forced to pay near historic premiums to NYMEX futures. On Friday, October 31st, Chicago cash diesel prices soared over 25 cents per gallon in a single day to settle nearly 60 cents per gallon over NYMEX heating oil futures. Not to be outdone, Group Three cash diesel increased 20 cents a gallon just two trading days...”

FN360

Source: Oil Price Information Service (OPIS)

Relief arrived in early December when Midwest diesel prices crashed on the back of improved refinery supply and an end to seasonal agricultural demand, finally allowing inventories to climb. Midwest diesel buyers can now expect discounts to the NYMEX or, at the very least, reduced wholesale values through much of the first quarter. Finally, while local rack prices remained elevated compared to regional trading hubs in December, Midwest diesel buyers should see those netbacks fall as shippers balance supplies. •

PADD 3 Gulf Coast

Gulf Coast Diesel Driven Higher by Northern Supply Disruption PADD 3 diesel prices jumped in response to the Midwest’s fourth quarter supply imbalance as Chicago and Group 3 diesel traders bid premiums sky high, prompting Gulf Coast traders to ship barrels northward in pursuit of higher proﬁts and leaving local markets in a lurch. As a result, shipments previously destined for Texas were diverted to markets with a higher netback and rack prices across the state increased relative to the Gulf Coast reﬁning hub.

For instance, in Odessa, TX, the OPIS gross contract diesel average during the ﬁrst three quarters of 2014 averaged roughly 15 cents a gallon more than Gulf Coast cash values while fourth quarter wholesale prices exceeded cash values by nearly 40 cents per gallon. Larger and typically well-supplied markets weren’t immune, either. For example, the Dallas rack average for the ﬁrst nine months of the year averaged roughly 10 cents a gallon more than cash market, but from October to December, the city averaged 22.5 cents a gallon more than Gulf Coast cash prices.

PADD 3 Wholesale vs. DOE Retail Diesel

FN360

Source: Energy Information Administration (EIA)

OPIS Gross Contract Average vs. Gulf Coast Cash

The good news is rack prices have since fallen from their fourth quarter highs and, in most markets, rack pricing are recovering from historic premiums to the Gulf Coast cash hub. •

FN360

Source: Oil Price Information Service (OPIS)

“ Chicago and Group 3 diesel traders bid premiums sky high, prompting Gulf Coast traders to ship barrels northward in pursuit of higher proﬁts.”

PADD 4 Wholesale vs. DOE Retail Diesel

PADD 4 Rocky Mountain

FN360o Source: Energy Information Administration (EIA)

“ Investment in emerging

North American plays like the Niobrara development — trapped beneath Colorado with smaller sections in Wyoming, Kansas, and Nebraska—will likely be slashed as producers concentrate their spending on lower risk, lower cost alternatives.”

Falling Crude Oil Pinches Rocky Mountain Economies The more than fifty percent drop in crude oil prices will likely cause U.S. shale output to slow in the coming months as producers become more selective in the projects they develop. The high-risk, high-cost shale plays will be shelved in lieu of familiar, low-cost geological terrain, such as the Eagle Ford and Bakken plays. Investment in emerging North American plays like the Niobrara development — trapped beneath Colorado with smaller sections in Wyoming, Kansas, and Nebraska — will likely be slashed as producers concentrate their spending on lower risk, lower cost alternatives. According to the Federal Reserve Bank of Dallas, the industry’s reduced spending could easily cost residents of the Rockies and fellow oil-producing regions — Alaska, Louisiana, Oklahoma, and Texas —approximately 250,000 jobs in the first half of 2015. In its last report of 2014, oil field data collected by Baker Hughes indicated 76 oil rigs — 5 percent of all active rigs — had been idled during the last three weeks of the year. While industry experts agree oil fields typically slow production toward the end of the calendar year, not everyone’s convinced these rigs will return in the spring; ultimately, translating to fewer barrels in the market and supporting the Federal Reserve Bank’s estimate. Even lodging companies, once thriving in the industry’s developing boom towns, reported cuts to first quarter expectations. Civeo Corp. of Houston, for instance, trimmed roughly $200 million (70%) in spending from its 2015 budget in preparation for drastically reduced revenues. Consequently, its domestic workforce has been cut nearly in half and Canadian workers by a third. 30

PADD 4 Rocky Mountain

“ While the oil industry’s capital

expenditures contribute only one percent to the nation’s overall GDP, reduced spending on rigs, technology, housing, and related amenities could seriously dampen economic growth in the coming quarters. ”

As shown below, the market’s been through considerably worse, but it’s still unclear how a rapid decline in capital investment and rise in unemployment would affect the Fed’s plans to raise interest rates. While the oil industry’s capital expenditures contribute only one percent to the nation’s overall GDP, reduced spending on rigs, technology, housing, and related amenities could seriously dampen economic growth in the coming quarters. Reduced investment in the nation’s oil ﬁelds may also increase the risk of premature easing by the Fed and threaten state budgets based on much higher crude oil revenues. •

Baker Hughes Domestic Rig Count

FN360

Source: Baker Hughes, Inc. 31

PADD 5 West Coast, AK, HI

PADD 5 Wholesale vs. DOE Retail Diesel

FN360o Source: Energy Information Administration (EIA)

California Cap-and-Trade Update With the start of the New Year, transportation fuels in California became subject to the State’s Cap-and-Trade emission program. The program, created in response to the Global Warming Solutions Act of 2006 (AB32), requires the reduction of greenhouse gas (GHG) emissions to pre-1990 levels by the year 2020. Similar to current restrictions on major polluters, the State will compel obligated parties to purchase and retire carbon allowances for each metric ton of carbon dioxide produced. Unlike existing requirements, however, fuel marketers will be held accountable rather than the parties actually creating the obligation — the everyday consumer. CO2 equivalent emissions generated on a per gallon basis vary from product to product, but as a general rule of thumb, consuming 100 gallons of either diesel or gasoline generates approximately one metric ton of obligated emissions. Greenhouse gas emissions from ethanol and biodiesel are signiﬁcantly lower, however. Consequently, consumption of traditional fuels now costs more per gallon, incentivizing the retirement of less efﬁcient vehicles and the adoption of greener energy. 32

Program administrators set minimum reserve prices for 2015 allowances at $12.10, but values could exceed $40.00 per allowance, resulting in a per-gallon increase between 12 and 40 cents. While the State will release additional allowances into the market through quarterly auctions, trading of existing certificates on the secondary market will likely generate daily price volatility. As a result, the Oil Price Information Service (OPIS) monitors the secondary market’s activity and provides a daily assessment (known as “Cap-at-the-Rack”) of the program’s cent-per-gallon impact on fuel prices. However, suppliers remain divided whether to roll OPIS’ assessment into fuel prices or pass their actual cost along to customers as a separate line item, creating significant confusion in the weeks surrounding the program’s implementation. All fuel buyers in the State of California will see the pricing impact of these regulations taking immediate effect in 2015. Additionally, fuel buyers should determine if they are, in fact, an obligated party under Cap-and-Trade regulations and plan accordingly to fulfill reporting and compliance requirements. Otherwise, consumers should brace for higher costs and a lengthy adjustment period as the market experiments with various pricing methodologies. •

Train Derailment Leaves EPA-Spec Diesel in Short Supply across Southwest Las Vegas Diesel Netbacks

The pipelines connecting Las Vegas and Phoenix to Los Angeles reﬁneries were short EPA-spec diesel this November due to lagging production and a train derailment which led to a massive supply disruption. The CALNEV and SFPP (south) were both affected, causing dramatic price hikes across the Southwest. As shown at right, the price spread between the Los Angeles cash market and Las Vegas and Phoenix markets rose sharply to their highest level in recent years. •

FN360o Source: Oil Price Information Services (OPIS)

Phoenix Diesel Netbacks

FN360o Source: Oil Price Information Services (OPIS)

LAS VEGAS 6"

CALIFORNIA

SFPP SOUTHERN REGION

NELLIS A.F.B.

TERMINAL & PUMP STATION

6" 12" BRACKEN

VALLEY WELLS

BAKER BNSF YARD

12"

EDWARDS A.F.B.

REMOTE CONTROL PUMP STATION TERMINAL & REMOTE CONTROL PUMP STATION JUNCTION PUMP STATION TERMINAL

BARSTOW

6" 14"

LOS ANGELES

YERMO

ADELAN TO

BNSF JCT.

16"

20"

16"

6" MARCH A.F.B.

ONTARIO AIRPORT CARSON

Indio

ORANGE

NILAND

MIRAMAR N.A.S.

6" 4" EL CENTRO N.A.F.

16"

10"

IMPERIAL

6" 6"

LUKE A.F.B.

HOLLOMAN A.F.B.

20"

12"

YUMA

12" 12"

TOLTEC

YUMA MCAS

12"

DAVIS MONTHAN A.F.B. APACHE

AFTON SCRAPE R

16" 16"

TUCSON

San Diego

DEMING

LORDSBURG

ROAD FORKS

12" 12"

HARBOR JCT.

Pacific Ocean

MISSION VALLEY

POINT LOMA

NEW MEXICO

ARIZONA

6" 20"

6" 10"

MIRAMAR JCT.

16"

20"

PHOENIX

SALTON SEA

16"

20"

16"

12"

16"

MEXICO

Source: Kinder Morgan 33

CORP.

WATSON

GEORGE TERMINAL S.C.L.A.

A DO RIV

ONTARIO

STANDA RD

COLTON

INDUSTRY

24"

TRANSP IPE

20"

COL OR

20"

16"

LAKE HAVASU

CAJON

20"

HYNES JCT.

Pacific Region

CALNEV

McCARRAN AIRPORT

“ The pipelines connecting Las Vegas and Phoenix to Los Angeles reﬁneries were short EPA-spec diesel this November due to lagging production and a train derailment which led to a massive supply disruption.”

NEVADA

8" 12" 16"

EL PAS O BR EAKOU T

12"

DIA MON D JC T.

EL PAS O

“Mimicking California’s highly-controversial program, which already affects major polluters and extended to everyday commuters at the start of 2015, Washington businesses exceeding the State’s annual greenhouse gas limit of 25,000 metric tons would be required to purchase and retire compliance certiﬁcates to avoid ﬁnes.”

PADD 5 West Coast, AK, HI

Washington State Considers Cap-and-Trade Proposal Seeking to reduce carbon emissions while filling the State’s coffers, Washington State Governor Jay Inslee proposed a cap-and-trade strategy late in the fourth quarter. Mimicking California’s highlycontroversial program, which already affects major polluters and extended to everyday commuters at the start of 2015, Washington businesses exceeding the State’s annual greenhouse gas limit of 25,000 metric tons would be required to purchase and retire compliance certificates to avoid fines. If approved, the program would go into effect July 1st, 2016 and would likely be linked to California’s Compliance Instrument Tracking System Service (CITSS), saving the state significant overhead.

Washington State Governor Jay Inslee

The California Air Resources Board (CARB) collected an estimated $2.2 billion through public carbon allowance auctions since they began in 2012 and state budget analysts expect the program to net between $12 billion and $45 billion by 2020. In Governor Inslee’s proposal, the $947 million generated through 2016 auctions would contribute heavily to the State’s transportation and education budgets in ﬁscal year 2017 while providing low-income residents an estimated $163 million in tax rebates and housing opportunities. Of course, they’ll need it considering Inslee’s plan would also increase the price of both power and fuel. Drivers could see fuel prices rise 50 cents a gallon or more, once reﬁners and distributors pass along the cost for allowances, and electricity could jump by as much as 6.3 percent, according to some estimates. •

Canada

Keystone Pipeline Prospect Threatened by Bear Market Keystone XL pipeline economics prove less attractive these days with WTI crude prices falling below $55 a barrel. While domestic crude oil prices averaged only $45 a barrel when TransCanada ﬁrst proposed the Keystone pipeline project in 2005, capital expenditures and operational costs associated with developing Canada’s oil-rich tar sands surged as much as 500 percent over the last decade as competition for resources and skilled labor heated up. Higher capital costs weren’t a concern at $100 a barrel, but the Keystone XL’s fate seems even more uncertain now as producers view their 2015 budgets through a different lens. Extracting oil from Alberta’s tar sands already costs signiﬁcantly more than a traditional well, but increasing demand on the region’s limited workforce and strained energy networks boosted those costs to between $60 and $65 per barrel, according to the U.S. Energy Information Administration (EIA). Even companies employing the latest technologies say easily accessible resources still require more than $35 a barrel — up nearly 8 percent since 2011 — while most operations continue to fall short of designed capacity. Consequently, Shell, Total, SunCor Energy of Canada, and, most recently, Statoil all cancelled tar sands projects in the last year citing high development costs and declining returns.

Senate Majority Leader Mitch McConnell

As collapsing oil prices and rising operational costs squeeze western Canadian producers, some say a changing U.S. political landscape could offer struggling projects a helping hand. According to incoming Senate Majority Leader Mitch McConnell, a bill authorizing the longstalled Keystone XL pipeline will be the newly-elected Republican Senate’s ﬁrst order of business; potentially lowering transportation costs by as much as $16 a barrel upon completion. In their September statement, Statoil claimed limited pipeline access to the region weighed heavily on their decision to cancel its Corner tar sands project, but would federal approval of the Keystone pipeline project change their minds now while futures remain below breakeven prices or will Republican reinforcements arrive four years too late? If current prices prompt producers to abandon long-term Canadian investments, 36

Canada jeopardizing production growth, legislators and industry analysts should ask themselves “who even wants the Keystone XL?” Keystone developer TransCanada says its shippers remain committed to the project. According to the company’s president, Corey Goulet, the “Keystone XL is not the driver for increased oil production out of the oil sands… It’s really the long-term price of oil, and even one year is a short time in the types of 20- or 30-year investments these folks are considering.” While the recent decline in crude oil prices doesn’t help pipeline supporters, long-term crude oil demand necessitates the development of these resources and the accompanying infrastructure. Projects may be shelved for the moment, but projects will likely be dusted off when product prices rise once more. •

“ According to incoming Senate Majority

Leader Mitch McConnell, a bill authorizing the long-stalled Keystone XL pipeline will be the newly-elected Republican Senate’s ﬁrst order of business; potentially lowering transportation costs by as much as $16 a barrel upon completion. ”

Canadian Tar Sands Avoid “Dirty” Designation Suncor Energy Inc.

Opposition to the import of Canadian crude stocks cite the EU’s own pledge to reduce the greenhouse gas intensity of automotive fuels by at least six percent before 2020. However, Canada’s own natural resource minister, Greg Rickford, spoke before the 25 EU representatives and, according to his spokesman, reminded the panel that any measure enforcing separate, more onerous restrictions upon bitumen extracted from Canada’s western oil sands would be discriminatory and adverse to the FDQ’s intent without treating comparable products with equal distaste.

The European Parliament spared Alberta’s oil sands the “dirty oil” designation in a December vote; instead assigning bitumen — a variety of crude oil derived from controversial oil sands — the same carbon intensity as its conventional counterparts. The European Union’s Fuel Quality Directive (FQD) sparked intense debate when it ﬁrst proposed bitumen receive a more stringent rating in 2012, but reﬁners are now free to import cheaper Canadian crude stocks without the 22-percent handicap accompanying “dirty oil.” 37

In today’s market of declining crude oil prices, this represents a big win for Canada’s oil industry. Demand has proven lackluster in recent years compared to what U.S. producers initially promised Canadian producers. Now, with overseas demand for heavy crude stocks poised to rise and strong environmentalist opposition to the transport or processing of Canadian bitumen on American soil, domestic reﬁners may not enjoy heavily-discounted Alberta crude for much longer. •

Alternative Fuels Renewables

Renewable Fuel Standard (RFS) Update A year has come and gone and the industry is still without the guidance of the 2014 Renewable Fuels Standard (RFS). The EPA was statutorily obligated to ﬁnalize the rule by November 30th, 2013, but since the deadline’s passing, analysts perpetually speculated the announcement would come “next month” or “next quarter.” The last popular theory suggested a ruling wouldn’t be released until after mid-term elections concluded, possibly aiding Democrats in their bid to retain control of the Senate. Evidently, that wasn’t the case and the EPA announced on November 21st the ﬁnal 2014 RFS2 would be delayed until 2015. Already drawing harsh criticism for its failure to produce a viable ruling, the EPA may also face lawsuits from the American Fuel & Petrochemical Manufacturers (AFPM) and the American Petroleum Institute (API), among others.

The EPA attributes the delay, in part, to overwhelming feedback in response to its proposed reductions earlier this year. Attempting to make amends while still adequately addressing the industry’s numerous concerns, the EPA plans to approve final rulings for 2014, 2015, and 2016 sometime this year —rumor suggests late first quarter. Interested parties speculate the EPA will base its final 2014 RFS renewable volume obligations (RVOs) on what is produced and stated in its Moderated Transaction System (EMTS). Currently, EMTS spots 2014 production at approximately 1.7 billion gallons (~ 2.5 billion RINs) of biodiesel and nearly 14 billion gallons (~ 14 billion RINs) of ethanol. According to EMTS RIN Generator data, 2014 may fall slightly short of the previous year’s biodiesel production while ethanol may exceed it. •

EMTS RIN Generation in 2013

Environmental Protection Agency (EPA) 38

Renewables Legislation Extends Renewable Tax Credits Last April, the Senate Finance Committee elected to renew various tax extensions, some of which expired at the start of 2014. Several provisions promoted alternative and renewable energy efforts, assisting biodiesel and cellulosic biofuel advocates in particular. These tax breaks eased the cost of manufacturing biodiesel and improve its competitiveness in an otherwise difﬁcult market while funding thousands of jobs within the renewables industry and injecting millions of federal dollars back into the nation’s economy.

“ These tax breaks eased

the cost of manufacturing biodiesel and improve its competitiveness in an otherwise difﬁcult market while funding thousands of jobs within the renewables industry and injecting millions of federal dollars back into the nation’s economy.”

The proposed legislation included two-year extensions for (1) a $1.01-per-gallon cellulosic biofuel tax credit — carrying an estimated cost of $55 million over 10 years — and (2) a $1.00-per-gallon biodiesel tax credit — awarding producers an estimated $2.6 billion over 10 years. The National Biodiesel Board and the Iowa Biodiesel Board lobbied aggressively for these biodiesel tax extensions, which prove more important than ever given the EPA’s failure to produce a 2014 Renewable Fuels Standard and the commodity market’s recent decline — both of which contribute to biodiesel’s weakening economics. Fast forward to December and the House approved the tax extenders package (H.R. 5771) by an overwhelming vote of 378-46. The bill quickly passed through the Senate with a 76-16 vote and President Obama provided his stamp of approval on December 19th, retroactively reinstating both the biodiesel and cellulosic biofuel tax incentives through January 1, 2015. However, the House agreed to only a one-year extension, ignoring the Senate Finance Committee’s recommendations and leaving traders in a familiar lurch. Consequently, traders will likely continue negotiating with a wide variety of approaches as they did in 2014. Most included discounts to remain competitive while whispering a silent prayer for the return of tax credits needed to compensate for the booked losses. •

Renewables

RINdicators

2014 RINS gradually ticked up in the fourth quarter before soaring in later December, with biodiesel (D4) RINs peaking at 74.25 cents per allowance, a nearly 24-cent (42%) rise from October’s opening value. Similarly, 2014 ethanol (D6) RINs rose by 29 cents (56%) during the fourth quarter to settle a penny below D4 biodiesel RINs.

Biodiesel (D4) RIN Values since October 15th

FN360o Source: Oil Price Information Services (OPIS)

Meanwhile, 2015 RINs roughly mimicked 2014’s until the latter half of December when 2015 D4 RINs exceeded previous year vintages by as much as 13 cents per allowance. D6 RINs, on the other hand, continued trading with only slight variances from one year to the next.

Ethanol (D6) RIN Values since October 15th

FN360o Source: Oil Price Information Services (OPIS)

The recent ethanol RIN surge does not have a clear culprit. However, motorists will beneﬁt given the combination of decreased spot gasoline prices, reduced ethanol prices, and elevated RINs — all of which could lead to even lower prices at the pump. In late November, the EPA delayed the ﬁnalization of the 2014 RFS Standards until sometime in 2015. Consequently, the compliance demonstration deadline for the 2013 RFS standards are to be delayed until 2015, as well. These deferments extend the validity of 2012 RINs, requiring the department’s EPA-Moderated Transaction System (EMTS) be altered to continue accepting 2012 RINs. Much to the industry’s dissatisfaction, the EPA’s delays make determining an appropriate RIN value nearly impossible. 40

Renewables

Supply and Demand Overview Ethanol production was full steam ahead in the fourth

Biodiesel production capacity for 2014 was approximately

quarter, rising from 901,000 barrels per day to a record-setting 988,000 barrels per day during the week ending December 5th. By early December, record production, coupled with decreased gasoline demand and relaxed ethanol blending, had boosted ethanol supplies to 17.75 million barrels, their highest level since mid-October. As a result, weakened demand and increased supply sent spot ethanol prices down in December. The national average hovered around $1.64 per gallon in early October, rising to approximately $2.59 in late November before closing out the year at $1.89 per gallon.

2 billion annual gallons. Meanwhile, actual production was estimated near 1.7 billion annual gallons, representing a slight decline from 2013. Market conditions proved challenging, particularly for the biodiesel producer needing to maintain high output due to lower margins. Producer margins will continue to be squeezed until some clarity is established regarding the Renewable Volume Obligation and the 2015 tax incentive. Despite lower selling prices, biodiesel demand is down 10 to 15 percent year-over-year as products have not consistently enjoyed noticeable discounts to ultra-low sulfur diesel.

ÂŠ 2015 Mansfield Energy Corp.

Natural Gas

Domestic Natural Gas Supply Domestic natural gas production is anticipated to grow even as lower natural gas prices loom on the horizon. Calendar year 2017 is the ﬁrst year trading above the $4 mark in future months. The largest contributors to natural gas production growth are the lowest cost plays and those containing signiﬁcant liquids content, improving returns. Although the current slide in oil prices to the lowest levels in the past 5 years dampens much of the enthusiasm from this particular play. •

Monthly Dry Shale Gas Production (billion cubic feet per day)

“ The largest contributors

to natural gas production growth are the lowest cost plays and those containing signiﬁcant liquids content, improving returns.”

(Forecast lower-48 natural gas production growth to remain strong, at 3.94 Bcf/d in 2015 and slightly less than that in 2016, at 3.46 Bcf/d on average, compared to 3.66 Bcf/d of growth on average in 2014.)

Source: Energy Information Administration (EIA)

Natural Gas

Debottlenecking the Marcellus and Utica Any story about natural gas production growth begins with the Northeast. Previously a net demand center, shale gas has transformed the Northeast into the most prolific gas play ever, driving overall natural gas production growth in the lower 48 to record highs. In 2015, production growth out of the Northeast is expected at more than 3.7 Bcf/d, and growth will likely continue at more than 2.9 Bcf/d in 2016. Since the beginning of 2014, the pipeline industry has expanded capacity by 2 billion cubic feet per day (Bcf/d) in the Northeast and plans to add another 0.4 Bcf/d in the near future. Significantly more pipeline projects were completed between 2012 and 2014 than in previous years, reflecting the need to expand the natural gas infrastructure in the Northeast to serve growing natural gas production in this region, particularly in Pennsylvania, Ohio, and West Virginia. Some pipeline projects of note in 2015 include TETCO OPEN project and Transco’s Leidy Southeast Expansion project – both scheduled to come online in the fourth quarter of 2015. The TETCO OPEN project will add 550 MMcf/d of capacity to the

Transco system, easing capacity constraints in the Appalachian region and allowing Utica and Marcellus to deliver into points across the Midwest, Southeast, and Gulf Coast. Transco’s Leidy Southeast expansion project will transport 525 MMcf/d of Marcellus gas all the way to southeast markets. Per EIA estimates, 32 percent of natural gas pipeline capacity into the Northeast could be bidirectional by 2017. Additional processing capacity will also help alleviate bottlenecks caused by NGL-rich natural gas that suppliers are otherwise unable to deliver into the natural gas stream. While the Northeast and its ever-growing natural gas production demands much of the industry’s attention, analysts expect volumes captured during crude oil exploration in Texas and North Dakota to contribute 1.3 Bcf/d of growth on average in 2015, and 0.80 Bcf/d on average in 2016. Of course, these forecasts assume a slow decline in crude oil production which could be accelerated due to falling commodity prices and reduce future natural gas contributions. •

Natural Gas Domestic Natural Gas Demand One consistent theme in the ﬁgures below is the continued increase in industrial demand the past few years. U.S. industrial demand has recently eclipsed early 2000s levels.

U.S. Consumption - GasWeek: (11/26/14 - 12/3/14) Percent change for week compared with: U.S. Consumption Power Industrial Residential/Commercial Total Demand

Last Year

This Year

-4.2% -9.6% 2.4% -5.2% -3.6%

2.9% -2.2% 1.1% 6.7% 3.1%

Source: BENTEK Energy LLC

ISM’s Purchasing Manufacturer’s Index for November increased 0.3 percent to 58.7 percent from October’s reading of 59.0 percent. This marks the 18th consecutive month of domestic manufacturing growth. Although month-to-month ﬂuctuations do and will occur in industrial demand, the overall consumption from this sector should remain robust given the current forward curve pricing. •

EIA L48 Industrial Demand (Bcf/day) 2001 2002 2003 2014 2015 2006 2007 2008 2009 2010 2011 2012 2013 2014

May 18.4 19.5 17.8 18.2 17.3 16.7 16.7 17.5 15.1 17.5 18.2 18.6 19.1 19.6

June 17.7 19.6 16.9 18.6 17.0 16.8 16.9 17.1 15.3 17.6 17.8 18.8 18.8 19.6

July 18.2 19.3 18.4 18.2 16.6 16.4 16.4 16.9 15.3 17.3 17.5 18.5 18.6 19.6

August 18.8 19.5 18.6 18.7 16.8 17.0 17.0 17.0 16.0 17.4 17.8 18.9 19.0 19.7

Source: Macquerie 44

Natural Gas Domestic Natural Gas Inventories Although overall storage levels failed to reach the 5-year average, an impressive amount of natural gas went into the ground during the 2014 injection season. Inventories peaked at 3,611 bcf the week of Nov 7th, which was approximately 235bcf under the 5year average. As we closed the book on 2014, inventories had just started their seasonal decline, albeit in a muted fashion. In the last week of the

year, only 391 bcf had been withdrawn from storage since hitting the year’s 3.6 trillion cubic foot peak, an 11-percent decline compared to the 5-year range’s typical 20-percent drop. A signiﬁcant increase in production coupled with mild weather contributed to the dramatic comparison. With the heart of winter still to come, one would expect the increase in production to continue to cast its shadow on overall withdrawal rates as is clearly evidenced in the chart below. •

Working Gas in Underground Storage Compared with the 5-Year Maximum and Minimum (Billion cubic feet)

Lower 48

5-year maximum - minimum range

5-year average

Source: Energy Information Administration (EIA)

Natural Gas Domestic Natural Gas Prices In the fourth quarter, natural gas moved outside the relatively tight range of the previous quarter, reaching heights not seen since the beginning of June. Prompt month NYMEX futures reached $4.68 per million British thermal units (mmBtu) on November 20th as colder than normal temperatures set in across the nation. However, as suggested in our third quarter review, weather extremes at this time of year translate into price volatility and, as December cold faded, so too did premium prices. By the end of the ﬁrst week of December, prompt month prices returned to thirdquarter lows in the $3.60 range and natural gas closed out the year below $3.00 per mmBtu for the ﬁrst time since 2012.

Interestingly, natural gas peaked near the same levels seen at the beginning of last winter where a slight pull back occurred. Only when January weather proved cold and the polar vortex established itself did prices rebound. We don’t anticipate this winter’s price action to be any less volatile than the last. However, a sustained period of colder than normal weather would need to establish itself over a majority of the country before any substantial rebound in price is to occur. Unfortunately for consumers, last winter’s cold did impact forward pricing for the Northeast region. As seen in the chart below, delivered gas to the Northeast has an embedded premium to Henry Hub that has not existed for the past few years, particularly in New England. •

Winter natural gas and spot foreward prices at Henry Hub, New York City and Boston as of October 29, 2014 ($/MMBtu)

Note: November through March are considered winter months. Forward prices for 2014-15 and 2015-16 are as of 10/29/2014. Source: U.S. Energy Information Administration, based on Bloomberg

Boston. Average forward prices in Boston this winter are expected to be $13.70 per MmBtu, which is $2.33/MmBtu lower than the winter of 2013-14, but much higher than previous winters. We’re seeing higher natural gas prices partly because the pipeline industry has not added any new capacity to ﬂow more Marcellus gas into Boston and because production from eastern Canada and liqueﬁed natural gas (LNG) from the Everett (Boston) and Canaport (New Brunswick) terminals are not high enough to serve New England peak demand. 46

New York City. Forward prices for New York City for the winters of 2014-15 and 2015-16 are signiﬁcantly lower than the spot prices for the unusually cold winter of 2013-14. The forward prices are still slightly higher than the spot prices for the 2012-13 winter, even though several pipeline expansion projects within the past two years have added new capacity to ﬂow more natural gas from the Marcellus region into New York City.

Natural Gas A Note on Oil’s Impact on the Price of Natural Gas In the early 2000s, a consistent correlation tied the price of natural gas to oil. Back then, residual oil was commonly used in power generation and heating oil still played a dominant role in the winter warming up across the country. But as shale explorations became more prevalent and the cost to extract gas fell with new technological advances, natural gas become a consistently cheaper alternative to petroleum products. Demand side parted ways with its dependency on oil and little if any correlation exists today.

It could actually be argued that the two fuels become inversely correlated at times like the present. Sustained pricing below $70 a barrel renders some domestic oil plays uneconomical; yet natural gas, sometimes considered just a byproduct of the oil drilling process, often improves margins enough to make a well economically viable. Thus, natural gas supplies will likely decline as producers stop drilling or cap oil wells on the cusp of proﬁtability. Consequently, faltering oil futures may actually generate support for natural gas prices. •

“ But as shale explorations became

more prevalent and the cost to extract gas fell with new technological advances, natural gas become a consistently cheaper alternative to petroleum products. Demand side parted ways with its dependency on oil and little if any correlation exists today.”

Electrical Power In this inaugural report on power, we’d like to provide an introduction to the deregulated power markets from a wholesale perspective. Our initial focus will be to deﬁne some of the “esoteric terminology” of the power industry and help customers understand what choices they may have when it comes to power procurement.

Power 101 Below is a map outlining the regions where wholesale power markets currently exist. Independent Regional Transmission Organizations (RTOs, synonymous with Independent System Operators - ISOs) operate the transmission systems within these regions. Natural gas trading hubs are marked on the map as natural gas is often the marginal fuel source for power generation within these RTOs. •

Deregulation of the U.S. power markets followed natural gas in the 1990s. Today, in several regions of the country, retail energy providers (REPs, synonymous with Energy Service Providers ESPs) are able to provide competitive power pricing in a similar fashion to how a customer’s liquid fuel needs are met. RTOs, also referred to as “pools,” run day-ahead and real-time wholesale electricity markets. Generators submit offers in the day-ahead market using their marginal cost curves and desired proﬁt margins. The demand side (“load”) bids their forecast load needs. Both sides can participate in the market as price takers. The RTOs then optimize the generation commitment for the following day given the bid-in demand and a set of transmission and unit constraints. Any deviations from the day ahead commitment,due to weather or outages for example, are “trued up” in the real-time market. •

Selected price hub locations for wholesale electricity and natural gas reported by Intercontinental Exchange

Electrical Power Power Generation –The Cost of Electricity Regardless of location, a retail power bill is comprised of 3 main components: transmission costs, energy costs, and capacity costs. In open access retail markets (located within deregulated wholesale markets) the transmission costs are still handled by a regulated entity – the Transmission and Distribution Service Provider (TDSP). Thus, we will focus on energy and capacity costs, which are provided by an REP and to which customers have a choice.

Energy Cost The following graph of the New York ISO (NYISO) generation stack illustrates the characteristic “hockey stick” shape of the marginal supply curve. The exact shape of the curve will vary from region to region due to variations in accessible generation.

Typical PJM Generation Stack

Source: Penn State

The units in the lower left portion of the curve are considered base load units. These are typically nuclear plants, hydroelectric stations, and large coal-fired plants. The middle part is comprised of mid-merit units – mostly natural gas fired combined cycles (CCs) and less efficient coal units. What is left in the stack above 29,000MW are units burning heavy oil, quick-start heating oil and diesel combustion turbines (CTs). The sharp upward swing in prices at peak loads is reflective of the historically unprecedented spread between petroleum distillates on one hand and coal/natural gas on the other. Both the day-ahead and real-time markets generate prices called Locational Marginal Prices (LMPs). There are thousands of LMP nodes in each RTO; for example, PJM Interconnection RTO (PJM) has over 10,000 nodes. LMPs have three components – energy, losses, and 49

congestion. While the energy component represents the optimal commitment level for the whole pool, the loss and congestion components reflect the locational aspect of generation and load. A locational marginal price (LMP) is defined as the marginal cost of supplying an increment of electric demand at a specific node (load or generation) on the network. Thus, the further a load is from the supply within an RTO the more costly it will be to supply that load. Looking ahead, the impact of minimal load growth (which is described in “Power Demand” below) looks more severe on coal than on gas. Weather-adjusted gas burn in 2014 appeared to be close to 2013’s level, despite generally higher prices this year. Natural Gas consumed by power generation in 2015 should rise, but only by approximately 0.5 Bcf/d or less due to weaker power load growth and more renewables generation. In contrast, coal burn post-winter has softened vs. 2013 and we look for this trend to continue into 2015. The resulting net effect on price is not exactly clear. However, one thing appears certain – the cost of power will be more highly correlated with the price of natural gas in the future.

Capacity Cost The capacity cost is a function of customer’s peak load contribution. This component is adjusted seasonally into winter and summer periods. One way to look at it is like having an insurance policy on the necessary electricity generation available to meet peak load and customers will pay for this insurance in some form or another. •

Electrical Power

Power Demand – Pricing Load As seen in the ﬁgure below, the nation’s weather-adjusted power load growth remained relatively ﬂat after 2008. Although some had thought an improving economy could boost electricity demand growth, demand growth looked to be partially decoupled from economic growth.

Average retail price of electricity, monthly

Source: Energy Information Administration (EIA)

Regionally, California demand showed a prominent downward trend in actual load post-last winter. Demand response programs, efﬁciency gains, behavioral changes, and the increased use of distributed generation (predominantly solar) are the likeliest contributors to lower utility demand. The following graphs illustrate the signiﬁcant change in year-over-year solar generation increasing per California ISO (CAISO) data. Negative demand growth could continue into 2015, though less severely.

Average hourly California renewable electricity production profile

Source: CAISO Daily Renewables Watch Note: Data do not include distributed generation solar electricity where output is behind-the-meter.

Electrical Power Clearly, California’s supply/demand situation has stabilized considerably since the 2001 California Electricity Crisis. In other areas of the country, a disparity in regional load growth has emerged and system reliability could be affected in the coming years. In Texas, a combination of robust economic growth outpacing growth in supply led to strain on the electric system during summer months over the past few years, most notably in 2011. That year, severe drought, coupled with a sustained summer heat wave, stretched the Electric Reliability Council of Texas (ERCOT) to its limits, as evidenced by the pricing displayed in the following ﬁgure.

ERCOT North Zone - August 1-30, 20122 Hourly day-ahead, daily on-peak, and monthly weighted average prices

Source: Energy Information Administration (EIA)

Events such these tend to adversely impact forward pricing as an additional risk premium will be included to compensate for future occurrences; thus, load will pay more in the future because of something that has happened in the past. In better news, a proactive nature exists among many generators to forward hedge a signiﬁcant portion of their ﬂeets. Unlike what we are accustomed to in the oil and, in some cases, natural gas

markets, many merchant generators ﬁnd security in locking in revenue streams – a possible appeasement to Wall Street and their shareholders. It is not unusual for generators to sell forward their supply up to 3 years in advance to lock in cash ﬂows. This effectively provides load an opportunity to purchase power needs forward at “discounted” levels that we typically don’t see in liquid fuel products.

Conclusion The combination of pending coal plant retirements (a big wave in 1Q15) and future reliance on more expensive generation to meet load will increase power market volatility to the beneﬁt of incumbent generators. The competing factors of low to negative load growth and generation retirements will adjust the intersection of many supply/demand curves across the country. While the impact on energy cost is uncertain, the reduction in supply is sure to have an impact on capacity cost. This is already transparent in forward capacity auctions in PJM where clearing prices 3 years forward have risen dramatically. In future issues, we will explore pending generation retirement and new builds, regional historical pricing, and consider regional forward pricing – is it a good time to hedge? • 51

Transportation & Logistics Hours-of-Service Tops ATRI survey of Trucking Troubles Released during the American Trucking Association’s October Management Conference and Exhibition, the American Transportation Research Institute (ATRI)’s annual survey results scored controversial hours-of-service (HOS) regulations as the industry’s top concern, yet again. Still relatively new to the industry, HOS regulations demanded signiﬁcant changes to the industry’s supply chain, shipping fees, and payroll practices.

Distribution of Industry Issue Prioritization Scores

Source: American Transportation Research Institute (ATRI) via Automotive Logistics

Actually accruing the most “top priority” votes, respondents picked the industry’s growing driver shortage as a close second in this year’s survey, replacing FMCSA’s Compliance, Safety, Accountability (CSA) program in the top ten list. Exacerbated by restrictive HOS regulations, motor carriers are finding it more difficult to retain drivers. According to the American Trucking Association, the industry currently operates with a shortage of roughly 30,000 qualified drivers. On top of that, approximately 20 percent of active drivers are between the ages of 55 and 65 while only 8 percent are under the age of 30. With the domestic economy back on track and transportation along for the ride, companies can finally focus their efforts on reducing turnover and, thereby, improving the bottom line. • 52

FMCSA Seeks Members for Driver Training Rulemaking Committee In response to the Moving Ahead for Progress in the 21st Century Act (MAP-21), the Federal Motor Carrier Safety Administration (FMCSA) seeks comments from affected parties regarding potential members for a negotiated rulemaking committee. According to the Department of Transportation’s website, the committee will offer guidance in establishing minimum training requirements for those obtaining a commercial driver’s license (CDL). Discussions will include length of classroom instruction, behind-the-wheel training, accreditation of schools and training programs, as well as instructor qualifications. As with any regulatory action, the committee’s decision could negatively impact cost — in this case to CDL hopefuls as well as company payrolls — but they could also improve turnover and incident rates. According to the American Trucking Association, freight volumes are growing nicely on a year-over-year basis, but a shortage of experienced drivers led to an 11percent rise in driver turnover by the middle of last year. Smaller fleets suffered a 16-percent increase. Better training often results in greater commitment to the job, reducing turnover rates, but it could also exacerbate the shortage of qualified drivers, possibly fueling higher salary expenses. •

Diesel Exhaust Fluid (DEF) Near-term Outlook (2015) The final quarter of 2014 was plagued by DEF supply challenges in North America. A planned two-week turn-around at the PCS plant in Lima, OH (the largest urea and DEF production facility in North America) turned into a protracted seven week outage. In addition, an early-December fire took down Rentech’s plant in Cherokee, AL. As a result, DEF supply in the eastern half of the U.S. tightened as supply outages in Ohio and Mississippi sent ripples throughout the DEF supply chain. By the middle of December, CF’s plant in Courtright, ON was sold out, Yara’s marine terminals in the northeast were dry, and the PCS plant in Augusta, GA had placed DEF customers on strict allocation. At the time of writing, neither plant has returned to normal operations and DEF supplies in the Northeast and Midwest remain extremely tight. Although, both plants should resume normal operations by the first week of January, it will likely take the better part of January for the DEF supply system to stabilize and the logistics system to return to normal operations.

In the short-term (i.e. the next 2-3 years), plan for tight North American DEF supply and unexpected plant outages that will tighten supply further. All players in the North American DEF distribution system, distributors and customers alike, should consider planning for and investing in supply redundancy by: • Increasing bulk DEF storage capacity at distributor warehouses • Upgrading bulk DEF storage capacity at end-customer locations • Adding DEF rail-terminals and requisite large-capacity storage (30,000+ gallons) wherever it is economically justiﬁed • Adding 50 percent concentrate blending at rail terminaling and large distributor facilities

North America imports 40 percent of the DEF it consumes, resulting in a tenuous DEF supply system. Supply outages layered atop already-short supply wreaked havoc on the nation’s DEF distribution system. Yet, it is a scenario that repeats itself annually. Compounding the fragile DEF supply system is an under-capitalized distribution and end-customer storage infrastructure leaving little margin for error in the DEF supply and logistics chain. When supply interruptions occur, there is limited emergency capacity in the logistics chain to cope with DEF supply outages. Today, there are over 30 nitrogen plant projects underway in North America (either new plants or existing plant expansions). Buyers can expect North America’s DEF supply system to remain fragile through 2017, when these nitrogen and DEF projects wrap up.

Diesel Exhaust Fluid (DEF) DEF Longer-term Outlook (2015+) DEF consumption growth will only accentuate North American DEF supply constraints over the next few years. While supply capacity remains tight, the North American DEF market continues its rapid growth, driven by the sales of SCR-equipped heavy and light-duty trucks, and more recently off-road equipment. Adding to DEF’s troubles, SCR systems and DEF dosing rates are evolving to keep pace with EPA emissions and fuel efﬁciency requirements. By 2017, DEF dosing rates on new engines are expected to increase 30 to 50 percent, helping truck and engine manufacturers meet future fuel economy standards. The combination of growing SCR adoption and increasing dosing rates will continue to drive double digit DEF growth through 2020 when the North American DEF market will top one billion gallons as forecasted by Integer Research. • Our base -case scenario shows DEF consumption is expected to reach 1 billion gallons in North America by 2019 billion gallons 2.0 1.86

Off -highway

“ While supply capacity remains

1.6

tight, the North American DEF market continues its rapid growth, driven by the sales of SCR-equipped heavy and lightduty trucks, and more recently off-road equipment.”

1.22 1.2

0.8

0.36

0.4 0.23

0.0 2013 Source: Integer Research

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

Source: Integer Research

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 Senior VP of Supply and Distribution Andy heads the supply group for Mansfield and during his tenure the company has grown from 1.3 billion gallons to over 2.5 billion gallons per year. Andy’s industry experience spans all aspects of the fuel supply business from truck dispatch, analytics, and index pricing to hedging and bulk purchasing. Prior to Mansfield, Andy worked at RaceTrac Petroleum. 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. Andy’s 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. Andy’s education began at Young Harris College and later at Georgia Southern University where he received a BS in Sports Management.

Dan Luther Manager of Supply & Distribution Dan is responsible for purchasing, hedging, and the distribution of natural gas and renewable fuels. Before joining Mansﬁeld, Dan was Director of Operations at Aska Energy and also worked at RaceTrac Petroleum, where he helped manage all barge, rail, and truck fuel deliveries before assuming ethanol trading responsibilities, including purchasing product to fulﬁll RaceTrac’s demand while trading product across other U.S. markets. Dan holds a BSBA in Supply Chain Management and Marketing from Ohio State University and is currently working towards his MBA at Georgia Tech.

Evan Smiles Northeast Supply Supervisor Evan began his career with Mansﬁeld as an intern in the supply department back in the winter of 2011, assisting in the Southeast region. Evan 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. Evan earned a BS in Sports Management and BBA in Finance from the University of Georgia.

Mansfield’s National Supply Team Jessica Phillips Renewable Supply & Distribution Supervisor Jessica is based out of Houston, TX and is responsible for nationwide purchasing, hedging, and the distribution of renewable fuels. Joining the Mansfield team in 2009, she has held multiple titles over the years: 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 is driven to continue to expand her knowledge in renewable and alternative fuels.

Chris Carter Southeast Supply Manager Chris serves as the Southeast Supply Manager 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. Chris joined Mansﬁeld in 2009 as a Supply Optimization Analyst and earned his BA in Business Management from North Georgia College and State University.

Nate Kovacevich Senior Supply Manager Before joining the company, Nate worked for Yocum Oil Company as a Senior Trader where his responsibilities included managing the company's reﬁned product and renewable fuels procurement, handling all hedging related activities, and providing risk management tools and strategies to help customers mitigate volatility and price risk. Nate previously worked for FCStone, where he performed commodity research and analysis for customers with agricultural and petroleum related risk, devised and implemented risk management programs and strategies, and executed futures and option orders on all the major exchanges as well as any OTC related transactions. Nate earned his BA in Entrepreneurship and Economics from the University of St. Thomas

Evan Poole Supply Support Manager Evan started his career with Mansﬁeld analyzing purchasing strategies and index behavior throughout the US and Canada. He’s the resident expert in Canadian reﬁned products and serves in an advisory capacity to the Canadian Supply team. Evan holds an MBA concentrated in Managerial Leadership from Piedmont College.

Q11

4th QUARTER Q4

FUELSNews 360° M A RKET NEWS & INFORMATION

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

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* 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 2014. 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.

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