FUELSNews 360 - Q2 2016 by FUELSNews

M A R K E T

N E W S

I N F O R M A T I O N

Table of Contents FUELSNews 360° Quarterly Report Q2 2016 FUELSNews 360°, published four times annually by Mansfield Energy Corp., analyzes and summarizes the prior quarter’s activity in the oil, natural gas and refined products industries. The purpose of this report is to provide industry market data, trends and reporting both domestically and globally as well as provide insight into upcoming challenges facing the energy supply chain.

Executive Summary

Regional Views continued

Overview

April 2016 through June 2016

2nd Quarter Summary

Commentary: Nate Kovacevich

Global Economic Outlook

U.S. Economic Outlook

32 33

Oil Stocks and the Global Supply Overhang

Price Recovery—Restoring Rig Count and U.S. Production?

Rising Prices, But U.S. Gasoline and Diesel Remain a Bargain

36 40

Viewpoints 42 50

PADD 1A, Northeast

Electronic Stability Control by Dan Kemeny

PADD 2, Midwest

Commentary: Dan Luther

Smart Truck: The Future is Now by Nikki A. Booth

PADD 1B & 1C, Central & Lower Atlantic

PADD 3, Gulf Coast

The Seven Shales by Dr. Nancy Yamaguchi

Fuel Quality and Tank Cleanliness by Clint Hamlin

Commentary: Dan Luther

Electrical Power Commentary: Keith Crunk

Commentary: Chris Carter

Natural Gas Commentary: Martin Trotter

Commentary: Evan Smiles

Renewable Fuels Commentary: Jessica Phillips

Regional Views 20

Canada

Alternative Fuels 33

Fundamentals 12

PADD 5, West Coast, AK and HI Commentary: Amy Nguyen

Economic Outlook 8

PADD 4, Rocky Mountain

FUELSNews 360˚ Supply Team

Q2 2016 Executive Summary Crude began 2016 deep in bearish territory, but as the second quarter began there was an indication that the bulls might just gore the bears. Harking back to last quarter’s FUELSNews 360°, we projected that crude and refined products prices would firm as we moved through 2016. We did indeed begin to see that occur in Q2, particularly on the crude oil side where crude prices ran-up by one-third to the mid-to-upper 40s range. Similarly, refined products pricing strengthened as RBOB prices increased heading into spring, while heating oil prices followed a gradual upward trajectory throughout the quarter.

However, while crude oil and refined products prices increased in Q2, both remain at historically low levels. It is difficult to conclude whether bullish or bearish sentiment will drive the crude and refined products markets in Q3. There are signs to indicate both.

growing at the same anemic 2% rate of the past three years. Couple this slow growth with the economic uncertainties of “Brexit,” a looming U.S. election, and a strengthening U.S. dollar that dampens worldwide crude demand, and short-term bearish sentiment creeps in.

Making the case for the bears, the world is awash in crude. Crude oil operating stocks remain well above 5-year ranges in the U.S. with domestic crude stocks continuing to skirt the 545 million barrel all-time record. As with crude, supplies of U.S. refined products remain at exceptionally high levels. U.S. distillate stocks closed the second quarter at 149 million barrels, 10% above their five-year average. Gasoline inventories were stable in the second quarter, remaining in the 240 million barrel range, which is well above the 215 million barrel 5-year average. The supply glut of refined product stocks and excess crude inventories have combined to push domestic wholesale gasoline and diesel prices down by 30 – 50 cents per gallon compared to the same quarter one year ago.

The most significant political and economic uncertainty overhanging crude and refined products is Britain’s vote to leave the EU. There were short-term ramifications that appear to be settling, but long-term questions remain that will affect aspects of the global economy. From a fundamental perspective, the vote is unlikely to affect supply or demand significantly; fluctuations in fuel prices after the vote were mainly tied to the strengthening of the U.S. dollar rather than demand concerns. Some economists have forecast a recession in Britain, which is not an unreasonable projection, but also not a certainty. The EU is our number one trading partner as an entity, and the UK is number eight taken singly as a country. Given the significance of these trading partners to the global and U.S. economy, the “Brexit” uncertainty is likely to cast a shadow over domestic crude and refined products pricing.

Making the case for the bulls, crude oil supply and demand appears to be creeping back into balance. U.S. crude production declined from 9.2 to 8.4 million barrels per day during the first half of 2016. Tales of woe out of the boomtown fracking fields are not as common now as they were in 2015—likely due more to a bottoming than a significant reversal of fortune. Rig counts have declined one-third, to 431 during the first half of 2016. This compares to a peak rig count of 2,026 in November 2011. And, in another recent bullish sign, we began to see rig counts increase at the end of Q2 for the first time since August 2014. On the demand side, the World Bank forecasts 2.5% – 3.0% worldwide GDP growth over the next three years, a slight increase over the 2.5% growth experienced during the past five years. Worldwide economic growth is generally the most important driver of oil demand. Steady economic growth, coupled with more balanced supply/demand, is a more bullish indicator for crude oil and refined products. However, World Bank growth forecasts vary significantly by region and type of economy. The World Bank forecasts the U.S. economy will continue

However, absent another significant global catalyst, economic and political uncertainty in Britain and the EU is likely to dampen but not snuff out more balanced crude sentiment. As excess inventories are worked off, and crude oil and refined product supply/demand re-balance, we expect crude oil and refined products pricing will maintain their current ranges through the U.S. election cycle. This quarter, we begin a two part series intended to enhance your understanding of domestic crude supply and demand dynamics. In Part I of the article “The Seven Shales” on page XX, Dr. Nancy Yamaguchi gives insight into the shale reserves that drive American production of oil and gas. Make sure to get a copy of the Q3 edition of FN360° to read Part II of “The Seven Shales” and further your fuel market education. We welcome your input and commentary related to both FN360° and FUELSNews Daily. Please do not hesitate to contact us at fuelsnews@ mansfieldoil.com so that we may continue to improve and expand our content for you, our readers. •

Overview April 2016 through June 2016 WTI Crude Oil Futures dollars per barrel

Source: New York Mercantile Exchange (NYMEX)

The world oil market in the second quarter of 2016 was wildly different from the first. Initially, global demand forecasts were revised downward, causing prices to sag. The oil taps remained open, as large producers continued their strategy of boosting output to drive out the higher-cost producers. WTI futures values were below $40/b for much of the first half of April. The supply overhang was continual. Crude stockpiles, already brimming after the first quarter, continued to swell. In February, U.S. stocks of crude oil passed 1.2 billion barrels for the first time in history, and have remained above this level ever since. The second quarter soon brought signs that supply and demand were moving closer to balance. During the first quarter, there were crude stock builds in eleven of the thirteen weeks and stock draws in only two. During the second quarter, there were crude stock builds in only five of the thirteen weeks, and stock draws in eight. The U.S. crude stockpile appeared to have hit its zenith at the end of April, and has slowly declined since then.

Volatility remained a daily element, but the overall crude price trend was strongly upward. Although OPEC producers continued to produce at high levels, there were several significant unplanned supply outages. The most catastrophic were the persistent wildfires in Canada’s Alberta Province and the destructive and violent militant attacks on Nigeria’s oil and gas infrastructure. These outages took approximately one million barrels per day off the market. Bullish buying created a crude price rally that brought WTI crude prices briefly above $51/barrel in June. On June 23rd, voting was held on the EU Referendum in the UK. Although 10% of the voting public remained undecided until the last possible moment, it still was expected that the UK would remain in the European Union. Instead, most of the undecideds voted to leave, and the “Brexits” won the day 52% to 48%. Global equity markets were thrown into turmoil. The UK pound dropped sharply, as did the Euro, and the U.S. dollar rose. As the figure illustrates, WTI prices dipped at the end of June. The markets are still in the process of adjusting. •

Overview Second Quarter Summary Summary, Second Quarter, 2016 $1.514 $1.512

$48.99

17949.37

RBOB 9($/gal)

Heating Oil ($/gal)

WTI ($/bbl)

DJIA Source: New York Mercantile Exchange (NYMEX)

Product prices rallied in the second quarter, ending well above the first quarter averages. RBOB (gasoline) futures ramped up quickly before the summer driving season, surpassing diesel prices. Futures prices for RBOB rose above $1.40/gallon in early March, hovered around $1.40 – $1.50/gallon in April, and went as high as $1.65/gallon in May. RBOB prices in June, however, slid back to the $1.50 – $1.60/gallon range. Diesel prices began the quarter at around $1.10 – $1.20/gallon, and these prices strengthened to $1.30 – $1.40/gallon in April and May, then rose to $1.40 – 1.50 by late May and early June. At the retail level, gasoline prices at the beginning of the second quarter averaged $2.083/gallon. Average retail gasoline prices rose to $2.329 by the end of the quarter. This price was $0.472/gallon less than it was at the end of the second quarter in 2015.

Retail diesel prices averaged $2.115/gallon at the beginning of the second quarter, rising to $2.426/gallon by the end of the quarter. This price was $0.417/gallon less than it was at the same time the previous year. Like crude inventories, product inventories remained well above seasonal and five-year averages. Also like crude, gasoline and distillate inventories at last began to recede from their all-time highs. Gasoline stockpiles started the quarter at 244 million barrels, and this leveled off and declined slightly to 239 million barrels for the end of the quarter. Distillate inventories declined more noticeably, falling from 163 million barrels at the start of the quarter to 150.5 million barrels at the end of the quarter. •

IIIII II

Global Economic Outlook

IIII II I

The second quarter brought a note of caution to the global economic outlook. The World Bank released its Global Economic Prospects report in June 2016. The World Bank downgraded its forecast of 2016 global economic growth from the 2.9% projected in January to 2.4%. The reasons behind the downgrade were summarized as: sluggish growth in developed countries, low commodity prices, weak global trade and diminishing capital flows.

Emerging and developing economies increasingly are the engine of world growth Percent

The World Bank noted the dramatic differences between growth in the developed world versus emerging markets and developing economies (EMDE). As the following figure illustrates, growth in the EMDEs avoided the move into negative numbers even during the global economic recession of 2009. For the current year, the World Bank forecasts EMDE growth at 3.5% versus 1.7% in the Advanced economies. In the next two years, the gap is forecast to widen even further. In 2017, EMDE economic growth is forecast to be 4.4%, while Advanced economies will grow at 1.9%. In 2018, Advanced economies will grow once again at 1.9%, but EMDE growth is forecast at 4.7%. In other words, without the EMDEs, there would be anemic global economic growth. Source: World Bank. Note: Shaded area indicates forecast.

ÂŠ 2016 Mansfield Energy Corp.

Growth by Country Group

Within the EMDEs, there is a sharp divide between commodity exporters and commodity importers. Low commodity prices have huge impacts on economies that depend on resource extraction, including oil and natural gas. Commodity importers, in contrast, are forced to develop other economic activities. They also are reaping—finally—the benefits of lower energy and commodity prices.

Percent

An examination of growth by country group, 2011 through 2016, reveals several key features of the global economy: First, that growth in EMDEs is orders of magnitude more rapid than growth in advanced economies.

Source: World Bank

Second, that EMDE commodity importers are achieving much higher and more stable rates of growth than commodity exporters. In 2011, this group of countries achieved 7.2% growth—the highest of any of the groups— and they achieved 5.9% growth from 2012 through 2016, with a slight slowdown to 5.8% forecast for 2016. The EMDE commodity exporters have been battered by low commodity prices. In 2015, the economies stagnated at 0.1% growth. Growth is forecast to creep up to 0.3% in the current year, mainly because of higher commodity prices. Third, that economic growth in all of these country groups—without exception—for the years 2011 through 2016, has been lower than the average growth rates achieved during the year 2003 through 2008. Moreover, in 2015 and 2016, the average growth is expected to be below the average growth achieved over the eighteen-year period 1990 – 2008.

Median EMDE Inflation: Oil Exporters vs. Oil Importers Percent

Source: World Bank

Low oil prices have lengthened recessions in Russia and Brazil, and they have slowed growth in other oil exporting countries, including Saudi Arabia, Nigeria, Venezuela and Canada. Yet low energy prices are a two-edged sword. The EMDE oil exporters are contending not only with stagnant growth, but they also face higher inflation rates, which are forecast to move from 4.0% in the first quarter of 2016, to 4.2% in Q2, to 4.4% in Q3, and back to 4.2% in Q4. In contrast, rates of inflation among the EMDE oil importers are forecast to be 2.1%, 2.5%, 2.2%, and 2.4% for each quarter of 2016, respectively. •

IIIII II

U.S. Economic Outlook

Consumer Sentiment Index

IIII II I

Consumer Sentiment Index Q2 2016

APRIL 89.0

MAY 94.7

JUNE 93.5

The second quarter of 2016 had an optimistic tone, with the two-edged sword of low energy prices appearing to help the economy on the whole, even as it took a toll on the country’s energy industry. The Consumer Sentiment Index improved considerably during the second quarter. It had dropped to 89 in April, but it rose to 94.7 in May before tapering off to 93.5 in June. Economic indicators were up and down. The Federal Reserve Bank refrained from any interest rate increases, despite the fact that at least one increase was deemed likely by the June Meeting. In fact, at the March meeting, two quarter-point increases had been planned for 2016, down from four planned initially. At the June meeting of the Federal Open Market Committee (FOMC), the FOMC reported that the pace of improvement in labor market conditions slowed in April and May. Offsetting this, however, real gross domestic product (GDP) appeared to be rising faster than it had in the first quarter. Consumer price inflation continued to remain below the FOMC’s guideline of two percent. Low energy prices played a major role in this. JPMorgan Chase Institute research found that middle-income households in 2015 spent $477 less on gasoline than they had in 2014. Their economists concluded that this was equivalent to more than a one-percent increase in annual income for 60% of households.

Source: University of Michigan

Average unemployment rate, 16YO+ Unemployment Rate

Source: Bureau of Labor Statistics

As the figure at left illustrates, unemployment rates have fallen in 2016. They remained stubbornly high from 2009 through 2014. Peak unemployment was 9.6% on average in 2010. In 2015, unemployment averaged 5.3%. Data for the first five months of 2016 show that unemployment fell to 4.9% in January and February, edged up slightly to 5% in March and April, and then dropped to 4.7% in May, partly reflecting a large number of unemployed persons exiting the labor force.

Rising U.S. Dollar Drives Crude Oil Lower

The second quarter of 2016 also brought a remarkable upward trend in oil prices, leading to the conclusion that global supply and demand were gradually coming into balance. Most agencies believe this balance will arrive by the end of the year. The rising oil prices have corresponded with a low U.S. dollar. Oil prices leveled and declined at the end of the second quarter, and the U.S. dollar has climbed. The end of the second quarter brought a major change to the international community when on June 23, the United Kingdom voted 52% to 48% to leave the European Union. Multiple surveys had predicted that the referendum vote would be close, but there was an overwhelming sentiment that the “Brexits” would lose and the “Bremains” would win. An unusually high 10% of the voters were still undecided right up until the last moment, and these undecideds came down on the Brexit side.

Source: New York Mercantile Exchange and Forex.com

The vote rocked the financial and equities markets. The Prime Minister, David Cameron, announced that he would resign. The UK and the EU are now in uncharted waters. There is no clear exit plan. Many economists predict an economic recession to set in either this year or in 2017. There is no doubt that the U.S. economy will be affected. The EU is the United States’ main trading partner, and taken singly, the UK is the eighth-largest trading partner. Currency markets are in a major period of readjustment. The British pound has taken a pounding, and it has lost close to 15% of its value against the U.S. dollar, as shown in the figure following. As the U.S. dollar strengthens, seen as a safer haven than the pound and the Euro, oil becomes more expensive in a global sense, and prices weaken. Other global commodities also become more expensive, since many are priced in U.S. dollars.

U.S. Dollar-Pound Sterling Exchange Rate: Brexit Causes a Pounding Exchange Rate

Higher prices for global commodities are not an unmitigated boon for the commodity producers. These often are developing economies, and the relatively higher costs can reduce demand. Foreign investors may also grow cautious about extending credit to countries whose currency is seen as losing value. As noted in the preceding section on the Global Economic Outlook, the Emerging Markets and Developing Economies (EMDE) are the main driver of global economic growth. Events that dampen this growth affect the entire global economy. Finally, a stronger U.S. dollar makes U.S. exports less attractive to foreign markets, cutting into export-led economic activity. This can reduce job creation, which already in May was a disappointment relative to the earlier forecasts for the year. The U.S. economy, therefore, entered into the second quarter with optimism, and ended the quarter with a bit more caution. •

Source: Forex.com

Fundamentals Oil Stocks and the Global Supply Overhang

Evidence of global oversupply: Brimming inventories When Saudi Arabia stepped away from its selfimposed role as OPEC’s key swing supplier, the world was soon awash in oil, and prices began to slide. Oil output steadily has exceeded demand, and crude and product inventories are now swollen to recordhigh levels in markets around the globe. The ebb and flow of oil inventories have become key market indicators. With no other place to go, crude and products are added to stockpiles. A steady increase in inventories is bearish for prices. The existence of large stockpiles can place an upper bound on how high prices can go. Conversely, when inventories start to dwindle, it is taken as a sign that supplies are being cut, or demand is rising, or both. This is viewed as bullish for prices.

To explore why crude stocks can be used as a bellwether for the market, the following figure compares the weekly addition/(drawdown) in crude stocks (million barrels), with the weekly change in WTI values (dollars per barrel,) with a five-day delay. We have added the five-day delay to account for the date the EIA releases its information on crude inventories. That is to say, the crude stock draw reported for the week ended May 20 was released on May 25, so the price corresponding with the May 20 stock movement data is the May 25 price. In this way, it is easy to see how the WTI prices track the stock movements.

Weekly movements in crude inventories vs Weekly movements in crude prices Change

Crude and product inventories have a complex relationship with futures markets and prices. Futures trading has developed a symbiotic relationship with storage—the more that traders made decisions to hold petroleum, the more tanks were built, which made it easier to hold speculative stocks, which created demand for more tanks, and so forth.

Source: Stock movements per EIA, WTI prices per NYMEX

Fundamentals

Categories of Oil Stocks Petroleum stocks may be sorted into three general categories: Operating Stocks, Strategic and Mandatory Stocks, and Speculative Stocks. Operating Stocks: The oil industry must maintain a level of operating stocks simply to keep their businesses on course. The world has a massive, far-reaching petroleum logistics infrastructure, with tanks, pipelines, refineries, trucks, railcars, tankers and bargesâ&#x20AC;&#x201D;all of which must be kept full and flowing in order to work. The Trans-Alaska Pipeline System, for example, has a linefill volume of over nine million barrels of oil. A single VLCC crude oil tanker can carry approximately two million barrels of oil. Operating stocks also include precautionary buffers against supply interruptions, plus stocks on hand to cope with seasonal patterns of demand. Strategic and Mandatory Stocks: Strategic and mandatory stocks include strategic petroleum reserves, minimum required stock levels and private corporation emergency reserves. Many governments maintain oil stockpiles. Decisions of when to buy and when to release can have a major impact on the market. China is building a strategic petroleum reserve, and purchasing crude for it can cause a significant upsurge in tanker traffic and imports. The U.S. Strategic Petroleum Reserve (SPR) is the largest emergency supply in the world, with a storage capacity of 714 million barrels. It currently holds 695.1 million barrels. Governments also may mandate that private companies maintain a minimum level of stocks. This often is considered burdensome by the private sector because of the high costs involved. Nonetheless, many private sector companies maintain strategic stocks, particularly among oilimporting members of the International Energy Agency (IEA.) In 2001, the twentyeight members of the IEA agreed to maintain strategic petroleum reserves equal to 90 days of the prior yearâ&#x20AC;&#x2122;s net oil imports for their respective countries. The oil exporting members Canada, Denmark and Norway are exempt. Some of these stockpiles are public, and others are maintained by private companies. Countries may also contract to stockpile oil in other countries under bilateral agreements.

Speculative Stocks: Speculative stocks are held by all facets of the petroleum industry. They exist because of oil price fluctuations. Short contract lengths and access to oil supplies via the spot market make it practical for many market participants to manage price volatility by buying and selling speculative stocks. Traders also buy and sell purely as speculation, with no intention of participating in the physical market. The main purpose of managing speculative stocks is to maximize profits and minimize losses during periods of price adjustment. As a simple example, a speculator may store oil believing that its price will rise by $1.00/barrel in two months, but the cost of storing it will be $0.30/barrel. Technically, holding speculative stocks can be done on a very small scale: an individual who believes that the price of oil will rise may opt to fill his or her heating oil tank and automobile tank. Petroleum stocks also are sorted into three categories according to where they are held: Primary Stocks include crude at producing fields, stocks in pipelines, stocks at tanker loading ports and at discharge terminals, stocks at sea, stocks at refineries, and stocks at large distribution terminals. Secondary Stocks include inventories held at small distribution stations, held by wholesalers and marketers, and held at retail outlets and service stations. Tertiary stocks are inventories held by end users, including gasoline, ethanol, diesel and biodiesel in automobile tanks, heating oil in residential tanks, fuel oil and other fuels held by electric power generators, and product inventories held by industrial end users.

Strategic Petroleum Reserve site, Freeport, TX

ÂŠ 2016 Mansfield Energy Corp.

Fundamentals

Development of U.S. Crude, Gasoline and Diesel Stocks In reality, there is no way to know precisely how much oil of what type is actually stored at any given time. Stocks held by end users are called tertiary stocks, and there is no practical way to measure these volumes. Imagine how many end users there are in the United States alone. End users store a huge amount of oil: gasoline, diesel, ethanol and other fuels in vehicle tanks and storage cans, heating oil in residential tanks, diesel and fuel oil held by electric power generators, and all manner of products held by industrial users. The government is able to track strategic reserves and mandatory stockpiles, and it calculates changes in operating stocks. The stock movements reported by the Energy Information Administration (EIA) have become one of the most important market indicators published every week.

Crude Oil Receding from All-Time High

Source: Energy Information Administration (EIA)

In the U.S., commercial crude oil inventories in April and May were skirting the all-time record of 545 million barrels. Only recently have stock draws exceeded stock additions, and the EIA has reported crude stock draws in nine of the fourteen weeks in the second quarter. Last quarter, in contrast, there were crude stock builds in eleven of the thirteen weeks in the quarter and stock draws in only two of the weeks. As the accompanying figure shows, however, the amount of crude in inventory remains far above last year’s level, and far, far above the 2010 – 2014 seasonal average and range. The amount of non-SPR crude in inventory, as reported for the week ended July 1, 2016, was 524.4 million barrels, down 2.2 million barrels from the prior week’s 526.6 million barrels. The SPR stockpile contains an additional 695.1 million barrels.

Fundamentals

U.S. gasoline inventories declined from their peak in the first quarter, yet the amount in inventory is far above its five-year average and range. Gasoline stocks have been roughly stable this quarter. The EIA reported gasoline inventories at 238.9 million barrels for the week ended July 1, 2016. Although demand has hit unexpectedly high levels, production has been strong, and imports have surged as low-cost supplies have headed to the U.S. The EIA reported that gasoline imports to the U.S. East Coast have averaged over 0.7 million barrels per day over the past twelve weeks

Gasoline Inventories: stable and in excess of 5-year average Million Barrels

Source: Energy Information Administration (EIA)

U.S. diesel inventories also exceeded the five-year average and range. However, distillate stocks were drawn down significantly in Q2, particularly in the last two weeks of the quarter. Stock drawdowns occurred in nine of the fourteen weeks in the second quarter. The EIA reported diesel inventories at 148.9 million barrels for the week ended July 1, 2016. This is 15.9 million barrels above the five-year average. For the last two weeks of the quarter, the inventory drawdowns were 4.0 and 4.8 million barrels, respectively.

Distillate Inventories: Declining yet still above 5-year average Million Barrels

Source: Energy Information Administration (EIA)

ÂŠ 2016 Mansfield Energy Corp.

Fundamentals

Conclusion: The recent stock drawdowns are a small sip from a tall glass Oil stockpiling is not regarded as an especially lively topic of discussion, but today’s market is much different than it was a year or two ago. Global oversupply has caused stockpiles to swell to record levels. Note that inventories were barely touched when Canada’s Alberta Province suffered its hugely destructive wildfire, blocking exports of synthetic crudes and other bitumen-based products. Data releases on crude and product stock movements are now eagerly awaited by analysts and traders. In the U.S., the official data is published weekly by the EIA. According to the EIA, in the past nine weeks since May 1, 2016, crude stock draws have occurred in six of the nine weeks. Diesel stock draws also have occurred in six of the nine weeks. Gasoline stock draws have occurred in five of the past nine weeks.

Each time a stock draw has occurred, it has been viewed as supportive of prices. Stock draws may indeed be a sign that supply and demand are moving into a better balance. As discussed, a certain level of oil inventory is required simply to keep the industry operating. An additional level of inventory is mandated to ensure supply security. The volume of oil needed to achieve these ends is huge. But examining the longer-term trend in U.S. crude, gasoline and diesel inventories reveals that inventory levels are at record-high levels, and they exceed their five-year seasonal averages and ranges by a sizeable margin. Four or five stock drawdowns in the past two months can be likened to taking four or five sips from a very tall glass. There is plenty left to assuage a summer thirst. •

Fundamentals

Is the price recovery restoring the rig count and U.S. production? As oil prices have crept back up this quarter, the burning issue was: How high will prices have to go before U.S. crude production bottoms out? WTI prices have been flirting with $50/b levels, yet production still sank this quarter. At the start of the year, U.S. crude production was 9,219 kbpd. It fell to 9,008 kbpd at the end of the first quarter. It now has fallen to 8,428 kbpd at the end of the second quarter. A continued decline is expected in the third quarter, but it is possible that the decline will then hit bottom, and production will begin to rise again.

U.S. Crude Production: Not yet seeing the bottom of the well

Source: Energy Information Administration (EIA)

U.S. Active Rig Count: Rigs now being tempted back into action

Source: Baker Hughes

Although the decline in production has not halted, the second quarter is showing signs that it might. At long last, the steady drop in active oil rigs appears to have reached its nadir. The U.S. active rig count dropped by over 60% in 2015. Another 214 rigs dropped out during the first quarter of 2016. According to Baker Hughes, at the beginning of January 2016, there were 664 oil and gas rigs at work in the U.S. This fell to 450 active rigs by April 1, 2016. One year prior, on April 1, 2015, there had been 1,028 rigs. Therefore, 578 rigs were shut down in just one year.

As the figure above illustrates, however, the rig count hit a low point at 404 rigs in the last two weeks of May 2016. Since then, oil rigs slowly have been tempted back into the field. The rig count has increased in four of the five weeks since the last week of May, with 27 rigs going back into operation. As of the week ended July 1, 2016, there were 431 active rigs in the U.S. Although production is not restored instantly, higher prices may tempt additional rigs back to work, eventually halting the decline in U.S. output. The rigs remaining have grown increasingly efficient and able to compete. A special focus on key U.S. shale plays is included in this quarter’s edition of FUELSNews 360°. •

Fundamentals

Rising Prices, But U.S. Gasoline and Diesel Remain a Bargain

A run-up in gasoline prices is common before the summer driving season, particularly in a year like this, when gasoline demand is growing strongly. The EIA estimates that gasoline product supplied has increased approximately 485 kbpd during the second quarter. But despite the overall increase in prices this quarter, gasoline remains a bargain. The figure following shows the drop in U.S. retail gasoline prices for the week ended July 4, 2016, relative to the week ended July 6, 2015. In all five PADDs, current prices are well below prices for the same week last year. On a national level, gasoline prices are 50.2 cents/gallon lower than they were a year ago. The Gulf Coast market has the countryâ&#x20AC;&#x2122;s lowest gasoline prices on average, and they are currently around 45 cents/gallon lower than they were last year. On the East Coast, gasoline prices are around 48 cents/gallon lower. In the Rocky Mountains, prices are 50 cents/gallon lower. In the Midwest and West Coast markets, gasoline prices are around 53 cents/gallon and 54 cents/gallon lower, respectively, than they were last year.

Crude prices remain below 5-yr averages

Source: New York Mercantile Exchange

HO prices remain below 5-yr averages

Source: New York Mercantile Exchange

Fundamentals

Gasoline is a Bargain: Drop in prices ($/gal), week ended July 4, 2016, vs. week ended July 6, 2015 ▲

Source: Energy Information Administration (EIA)

Diesel is a Bargain: Drop in prices ($/gal), week ended July 4, 2016, vs. week ended July 6, 2015

Diesel prices had been rising strongly until the post-Brexit pullback, but diesel also remains a bargain relative to last year. The EIA’s estimate of diesel demand increased 389 kbpd during the second quarter. At the national level, diesel retail prices were 40.9 cents/gallon lower for the week ended July 4, 2016, than they were for the week ended July 6 in 2015. The figure below shows the drop in diesel prices for the U.S. and for the five PADDs. In the Midwest, Rocky Mountains and West Coast, diesel prices are around 34 to 36 cents/gallon lower than they were one year ago. Gulf Coast prices are 43 cents/gallon lower. Prices on the East Coast are 50 cents/gallon lower. • Source: Energy Information Administration (EIA)

Regional Views PADD 1

East Coast PADD1A Northeast

BULL

Evan’s Estimation I

Evan Smiles, Supply Manager See his bio, page 54

Looking forward to the third quarter of 2016, the main driving factors for the Northeast prices will continue to be the glut of supply we are currently seeing and any natural disasters that may occur (mainly tropical disturbances). The heightened demand for gasoline during the summertime can’t overpower the amount of product we have in the market. The last time the New York Harbor market traded at a premium to the NYMEX for ULSD was over two months ago and over six months ago for CBOB/RBOB. Even with this oversupply of product, I am predicting a bullish market for all refined products in the Northeast for the third quarter. With the peak of hurricane season in September and predictions calling for a more active season, I can see the East Coast being hit with at least a tropical storm. This will bolster basis numbers due to larger demand and lower supply. •

“Even with this

oversupply of product, I am predicting a bullish market for all refined products in the Northeast for the third quarter.“

Pennsylvania Heating Oil Sulfur Cuts On Hold The Commonwealth of Pennsylvania was slated to make the jump over to low sulfur heating oil starting July 1, 2016; however, this has since been delayed due to elevated high sulfur heating oil inventories throughout Pennsylvania. Record warmth and lower demand during this last winter season was the main cause of this glut in supply. The Pennsylvania Department of Environmental Protection (DEP) made the decision in May to suspend the 500 parts per million (ppm) sulfur mandate until the end of calendar year 2016. This leniency is mainly for distributors and retailers, allowing them to continue selling their 2,000 – 5,000 ppm heating oil supply to customers within the state until their high sulfur heating oil supply is drawn down. This suspension does not allow suppliers to receive more high sulfur heating oil within Pennsylvania; it only allows them to sell the current high sulfur inventory they already own.

This sulfur reduction mandate suspension will offer some relief for distributors that still own a large amount of high sulfur heating oil. However, as heating oil sales slow dramatically during the summer months, many distributors may find it difficult to liquidate this high sulfur product. These challenges may result in the sale of high sulfur heating oil at a nominal discount. High sulfur product can be blended with ultra-low sulfur product to create a heating oil that meets the low sulfur spec for the new mandate. •

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

Source: Energy Information Administration (EIA)

PADD 1

East Coast PADD1B & 1C

Central & Lower Atlantic

Regional Views

BEAR

Chris’s Concepts I

Chris Carter, Supply Manager See his bio, page 54

For the next quarter I’m bearish for both gasoline and diesel products. For ULSD, I believe we are going to continue to see demand stay flat and supply continue to be plentiful. I believe Florida will still be oversupplied, as it’s currently the best outlet to move product via barge as refiners commission new vessels. Gas also will continue to lower as we come out of Low RVP season. One market watcher believes the “new” of lower prices on gasoline has worn off and is becoming the new “norm.” This will result in gas demand staying flat. •

Hurricane Season The 2016 Hurricane season started early this year with four named storms already. The official start of Hurricane Season is June 1, yet this year we have had two hurricanes before June, the first time since 2012. The first storm formed exceptionally early in January in the Northeastern Atlantic, then Bonnie formed in late May. Hurricane Colin formed on June 5, the earliest record in history of three named storms. Danielle formed later in the month on June 20. Currently experts predict that the 2016 Hurricane Season will be a little above average, predicting between 12 – 15 named storms. It is key to note that there is no direct correlation between the number of named storms and storms that make U.S.

“One market watcher

believes the “new” of lower prices on gasoline has worn off and is becoming the new “norm.” This will result in gas demand staying flat.“

landfall. In 1992, there were only six named storms; however, Hurricane Andrew made landfall in Florida resulting in severe damage. Compare that with 2010, a very active hurricane season, during which 19 storms were named and none made U.S. landfall. Some believe Florida’s “luck” may be tested this year. Florida’s last major hurricane was in 2005, and it has been even longer for the east coast of Florida and southern Georgia. Residents in these areas are always on alert during an active hurricane season. Companies with fleets in the Southeast should make sure they have reliable, contracted fuel supply during this active hurricane season. •

PADD 1

Regional Views

East Coast Cash vs. Rack Differentials

East Coast PADD1B & 1C

Central & Lower Atlantic continued

Source: Platts, OPIS

East Coast Port Terminals The past two years have been a wild ride for Gulf Coast vessel-supplied terminals for both gas and ULSD. As mentioned in previous FN360° articles, the Gulf Coast has faced several challenges in regard to supplying refined products into Florida and East Coast terminals, Jones Act vessel shortages, arbitrage opportunities into the New York Harbor, weather and crude oil values. However, the marketplace is going through a major change, and as a result, the consumer is benefiting from lower prices. As mentioned previously, in 2012, the majority of Jones Act vessels moved refined products in the Gulf; however, as the crude boom started, vessels began to convert to crude to meet the higher demand. Since crude prices have lowered over the past 8 – 10 months, vessels are returning to refined products. Also, new vessels are coming into service that are providing additional carrying capacity. For the first time in several years, the U.S. is long on Jones Act refined product capacity.

The graph above shows the spreads between GC Cash and local wholesale prices. The end users are benefiting from this as we continue to see additional products moved into traditional terminals: Tampa, Port Everglades and Jacksonville. However, new barge supply is beginning to come into Wilmington, North Carolina, Charleston, South Carolina and Savannah, Georgia. Bringing in additional product to these East Coast terminals helps relieve the stress felt at the pipeline terminals. North Augusta is a great example, in that as shipping economics become attractive to barge product into Savannah and Charleston, it will lower the demand in North Augusta, bringing relief to a market that has been tight since December 2012. It has undermined the full impact of all the changes in regard to vessel capacity, but it should benefit the end users. •

Regional Views

Colonial Line Space

Colonial Line Space Values

The second quarter of 2016 has been interesting for Colonial Line Space values. Colonial Pipeline, which runs from Texas up to New Jersey, services the majority of the Southeast, as well as pipelines in the Northeast. Colonial’s gasoline line, Line 1, has traded at a premium for the majority of the quarter. It wasn’t until the middle of June that gas values went negative; most anticipate for this to remain negative until Low RVP season is over. The Diesel line, Line 2, has traded flat to mostly negative during this time. New York Harbor continues to be heavy product, as a result of putting pressure on the NYH Basis values. As a result, it’s pushing more product to stay south of Philly. Because most of the product remains in the Southeast, the racks are discounted versus shipping costs. Expect this to depress Southeast gasoline prices as long as the trend continues. •

Source: Platts, OPIS

PADD 1B Wholesale vs. DOE Retail Diesel

(dollars per gallon)

Source: Energy Information Administration (EIA)

PADD 1C Wholesale vs. DOE Retail Diesel

(dollars per gallon)

Source: Energy Information Administration (EIA)

PADD 2 Midwest

“A relatively calm spring transitioned into a volatile May and June as refiners, who typically sell gasoline into the market, were caught buying to meet contractual demand. “

Regional Views

BEAR

Dan’s Dissertation I

Dan Luther, Senior Supply Manager See his bio, page 54

Compared to the second quarter, Midwest fuel buyers should expect lower volatility in Q3 as seasonal refinery maintenance comes to an end. While demand will remain strong, particularly for gasoline due to low pump prices and forecasted strong summer driving demand, producers will be able to meet the supply requirements as refineries return to full capacity. Buyers should expect Midwest diesel and gas prices to decrease relative to NYMEX futures, particularly in July and August.

regional gas prices up by over $0.60 per gallon in the quarter. A relatively calm spring transitioned into a volatile May and June as refiners, who typically sell gasoline into the market, were caught buying to meet contractual demand. Refineries such as Citgo Lemont (IL), Exxon Joliet (IL), Marathon Robinson (IL), Husky Lima (OH), and BP/Husky Toledo (OH) were offline at some point during the second quarter. For much of the quarter, refined product prices in Chicago, the trading hub in the Great Lakes region, were the most expensive in the country.

A combination of strong demand, led by cheap prices and the summer driving season, and short supply caused by significant refinery maintenance pushed Great Lakes

Thankfully for buyers, much of the spring refinery maintenance was completed in June, which should better balance supply and demand in the region going into the third quarter.•

Chicago UNL Gasoline Basis (Cash less Prompt Futures)

Source: Oil Price Information Administration (OPIS)

Regional Views

West Shore Pipeline Suspends Service Indefinitely on Segment to Green Bay In June, West Shore pipeline announced that they would suspend service indefinitely on the segment of their line running from Granville, Wisconsin (Milwaukee), to Green Bay, Wisconsin. The line was shut after several months of integrity checks found various anomalies that led to safety concerns. Market participants have speculated the shutdown will last at least two years as a best-case scenario, though there is a chance the line may never be recommissioned. West Shore originates in Chicago, moving products north into Wisconsin, and is the only pipeline that serves the Green Bay market. Some terminals do have barge access; however, barge deliveries typically cost several cents more per gallon and reliability will be an issue in the winter months when much of northern Lake Michigan freezes. Given the shutdown, fuel customers in Green Bay have been primarily supplied from surrounding terminals such as Waupun, Wisconsin (80 miles), Junction City, Wisconsin (110 miles), and Milwaukee (115 miles) via truck deliveries. This will continue to be the main supply method until the pipeline issues are resolved, if ever. â&#x20AC;˘

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

Source: Energy Information Administration (EIA)

ÂŠ 2016 Mansfield Energy Corp.

Regional Views

PADD 3 Gulf Coast

BULL

Dan’s Dissertation I

Dan Luther, Senior Supply Manager See his bio, page 54

During what should be a more active hurricane season in 2016, expect volatility in Gulf Coast prices. This will be particularly true in August and September when the hurricane season is typically most active. Furthermore, while Gulf Coast exports of refined products are expected to remain lower than this time last year—given economic strife in some Latin American countries—the summer Olympics in Brazil may lead to a short term spike in gasoline demand as the country buys ahead of an influx of travelers.

“Generally, Gulf Coast

prices will remain consistent with NYMEX futures throughout the quarter, but expect events that will increase volatility.“

Generally, Gulf Coast prices will remain consistent with NYMEX futures throughout the quarter, but expect events that will increase volatility. •

Magellan Pipeline Shuts Service on Texas Pipeline Due to Flooding Extreme rainfall and subsequent flooding in southern Texas caused Magellan Pipeline to shut a segment of their 16" mainline in early June. The impacted area was near Spring, Texas, just north of Houston. In Texas, Magellan’s line carries refined products from Houston north to cities like Dallas, Odessa, El Paso and Oklahoma City. While many of these markets are also supplied via other pipelines and local refineries, the shutdown of a main artery into any market has an impact on supply availability. Some cities, such as Odessa, are served only by Magellan’s line, meaning there is no other pipeline supply. Consequently, local prices increased on the back of scarce supply, as exemplified by Odessa rack prices in relation to the Gulf Coast regional cash market.

Source: Magellan LP

Magellan repaired the 2,500 ft. segment that was washed out in a little less than three weeks, resuming operations by June 17. Prices began to fall shortly after as product reached impacted markets. •

Odessa, TX Netbacks

Source: Oil Price Information Administration (OPIS)

Regional Views

Hurricane Season 2016 Hurricane season is upon us, with the Atlantic storm season running June 1 through November 30. For the 2016 period, the National Oceanic and Atmospheric Administration (NOAA) predicts the season will “most likely be near normal, but forecasts uncertainty in the climate signals that influence the formation of Atlantic storms make predicting this season particularly difficult.” Not an especially comforting forecast from the experts, and just about as close to an admission of “we don’t know” that we’ll get from meteorologists. But for what it’s worth, the scientists at the NOAA predict one to four major hurricanes (Category 3, 4 or 5; winds of 111 mph or higher) this year with a total of 10 to 16 named storms. At the time of writing, there have already been four named tropical systems this year.

Mindful fuel buyers are on alert this summer, preparing contingency plans in case a hurricane impacts Gulf Coast fuel availability. As of late, some energy buyers have treated hurricane season as an afterthought, given the low storm activity in recent memory. But even a “normal” hurricane season would bring much more activity in the Gulf relative to the past several years. Accordingly, prudent fuel buyers in Gulf Coast states ensure they understand their supplier’s plan in case a major storm impacts refined product availability.•

PADD 3 Wholesale vs. DOE Retail Diesel

(dollars per gallon)

Source: Energy Information Administration (EIA)

PADD 4

Rocky Mountain

Regional Views

BEAR

Nate’s Notion I

Nate Kovacevich, Senior Supply Manager See his bio, page 54

Refined product prices in the Rockies should find relief over the summer as refineries in both the Mountain Region and Midwest return from turnaround activity and start producing more gasoline and diesel to meet the uptick in demand. The Rockies market should also feel negative macro-economic headwinds following Britain’s vote to leave the European Union. From a seasonal perspective, as long as we don’t have any unplanned refinery events, markets should have a tough time rising above the Q2 peak, as refineries are incentivized to make as much product as possible at current crack spreads. Plus, if you look at the percentage increase in refined product prices over the first half of the year, one would think we’re due for a breather. •

Initiative 78 trying to get on November ballot A proposal to require new oil and gas wells to be at least 2,500 feet from homes and schools in Colorado, which would leave nearly 90 percent of the state off limits from hydraulic fracturing or oil and gas drilling, is in its signature-collecting phase that could end up on the November ballot. The proposal, called Initiative 78, would leave 85 percent of Weld County off limits from energy development, the state’s largest oil and gas producing county. Other counties with substantial oil and gas interests will also have the majority of their surface off limits to drilling, according to the Colorado Oil and Gas Conservation Commission, the state’s regulatory agency. The proposal doesn’t call for an outright ban of drilling and fracking activity in Colorado, but the setback requirements would end most oil and gas drilling statewide.

The chances of Initiative 78 making it to voters on the November ballot are small; backers would need more than 98,000 signatures to achieve their goal of putting the measures on the ballot. Those who sign would risk hurting an industry that has been a key contributor to economic growth over the last 5 – 10 years. A study by the University of Colorado’s Leeds School of Business said the oil and gas industry has contributed $126.5 billion in output in Colorado between 2008 and 2012. The study believes the upstream and midstream oil and gas industry supported more than 93,500 jobs for the state. •

Regional Views

PADD 4 diesel prices jump more than 30 cents in Q2 Retail diesel prices increased nearly 15 percent in the second quarter on the heels of stronger demand as well as the reduction of operations for a number of refineries for seasonal maintenance in April and May, when most of the price increase occurred. The most recent weekly DOE report showed Rocky Mountain (PADD 4) diesel prices unchanged from the week before at $2.413, but up more than 55 cents from mid-February 2016. Despite the rally in Q2, consumers and

businesses are still feeling the benefit of a nearly 40-cent drop year over year from the same period in 2015. Compared to the rest of the country, diesel prices in the Rockies are slightly lower than the national average. But the difference has tightened considerably when compared to the winter, when prices in PADD 4 were 15 – 20 cents cheaper. These discounts abated once turnaround activity began in late March. •

Padd 4 Retail Diesel Prices

Source: Energy Information Administration (EIA)

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

Source: Energy Information Administration (EIA)

31 29

PADD 5

West Coast, AK, HI

Regional Views

BEAR

Amy’s Analysis I

Amy Nguyen, Supply Optimization Supervisor See her bio, page 54

As Q2 comes to an end, the West Coast has ample fuel supply. LA Basis for ULSD surged up to over ten cents, only to fall by the end of the quarter to nearly zero. With the return of the Torrance refinery to full operations, I expect fuel prices to stabilize and then decline during Q3. Although the summer months will increase the amount of cars on the road and the need for gas, I’m predicting the increased production will be able to counteract the demand.•

Torrance and the trend in selling small refineries Over the past few months, rising crude oil prices have triggered several large oil companies to sell their small refineries. Shell has been working to sell its refinery in Martinez, California, and Chevron is doing the same with its Burnaby, British Columbia, operation. These efforts are an attempt to rid themselves of lower margin assets as refining profit margins have declined within the past year. Analysts believe small refineries would be more of an asset for smaller buyers who focus on particular regions or global storage/trading rather than oil production. A prime example of this trend is PBF Energy’s acquisition of Exxon’s refinery in Torrance. PBF Energy, a petroleum refiner based in New Jersey, acquired the refinery in hopes of expanding its West Coast footprint. The deal took place late last year while Exxon was still recovering from the refinery explosion in February 2015. The transfer of ownership was to be completed once the refinery became fully operational and would allow PBF to strengthen its refinery business nationally. Other small companies could eventually follow PBF’s lead and look into buying off the refineries from large oil companies who no longer see them as viable assets. This would allow small companies to gain shares in the refinery space and larger companies will be able to invest in other initiatives. In return, with a smaller company solely focusing on the refineries, it may allow them to operate more efficiently and focus more on the customers the refinery serves. This could eventually lead to more competitive pricing for the consumers.

The return of the Torrance refinery to full capacity should be a sign of good news to both PBF and consumers in California. The plant has a significant impact on the market, as it supplies 10% of refined gas in the state and 20% in Southern California. Last year, gas prices jumped after the refinery was running at one-fifth of its normal capacity following the explosion, and the repercussions continue to affect the gas prices today. That being said, when will the refinery be able to return to full capacity and when will users and PBF see the benefits of it? For the past year, Exxon has been working on bringing the refinery back to 100% but has been running into a number of issues. The issues continue to push back the handoff of the refinery to PBF; it was initially set for May 1, but was delayed to July 1. Even the new deadline was nearly put at risk by hydrocracker maintenance and a crane accident at the site. In June, as Torrance was delayed, gas prices rose, which was attributed to unplanned outages at other refineries in the region as well. Despite the issues and delays, Exxon and PBF were finally able to complete the handoff on July 1. With the change in ownership, I expect the spread of gas prices in southern California to shrink with the increased supply. •

Regional Views

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

Source: Energy Information Administration (EIA)

Canadian wildfires’ impact on the Pacific Northwest During this quarter, the Pacific Northwest has been impacted by the wildfires in Fort McMurray, Alberta. These fires resulted in a production cut within Canada’s oil sands. Several companies have even pulled their employees out of the area and cut or stopped production. This is significant because, despite high capital costs of operating within Canada’s oil sands, historically, companies have rarely cut or stopped production even when oil prices fell. In addition, restarting projects after a shutdown can be very expensive, since it could take several months to restore production. As a result of the production cut, some Canadian refineries were impacted and crude deliveries have been reduced in a few pipelines, including Kinder Morgan’s pipeline in the Pacific Northwest. It has been reported that exploration companies are looking at a collective loss of more than $1.4 billion. However, many companies have returned to the oil sands and have started pumping crude oil again. Even though these companies have resumed, I don’t expect supply and prices in the Pacific Northwest to normalize for another few weeks or months. •

Regional Views

Canada

Canadian oil industry struggles to build pipeline The Canadian Association of Petroleum Producers (CAPP) is trying to get at least one pipeline built by 2020, but opponents have been successful in recent years to prevent the oil and gas industry from expanding its pipeline network. Currently, there are a number of pipeline proposals on the table to handle expected output growth in the country. According to CAPP, without a new pipeline, for every new barrel of oil that is produced in Canada, one barrel will need to be moved to customers via rail. Their argument is that a pipeline is far safer and cleaner, from an emissions standpoint, than having to ship those barrels by rail.

Plus, Canada’s biggest customer (the U.S.) has now become the country’s biggest competitor. CAPP’s vice-president of communications put it simply by stating that Alberta needs to get its product to overseas markets or else it will remain a “lemonade stand with one customer.” The need to diversify its customer base and increase its pipeline takeaway capacity has become more apparent with the recent surge in U.S. oil production stemming from shale development. •

Wildfires hit Fort McMurray crude oil production Wildfires near Fort McMurray in Alberta reduced Canada’s oil sands production by nearly 800,000 barrels per day in May, with a daily peak of more than 1.1 million barrels per day. The wildfires forced the evacuation of the entire population of Fort McMurray and destroyed more than 1,600 homes and buildings in the area. The majority of oil companies operating in the region completely shut down operations or ran at significantly reduced rates. Oil pipelines in the area were also shut down due to the wildfires, which impacted takeaway capacity to refineries.

The prolonged duration of the wildfires as well as the refinery outages left local Canadian suppliers scrambling to meet customers’ needs. By midJune, however, the refinery returned to its operations and was close to replenishing inventory levels. The company was bringing extra supplies by truck and rail into Western Canada to help offset the shortages and relieve some of the stress in the marketplace as prices spiked in parts of the Western provinces.

In addition, the Suncor refinery in Edmonton had an unplanned issue on May 27, which, along with the Fort McMurray wildfires, caused diesel and gasoline shortages in Alberta, Saskatchewan, Manitoba and British Columbia in early June.

Suncor is expected to ramp up crude production in the Fort McMurray area and return to normal rates by the end of June. •

Alternative Fuels

Renewable Fuels “As the food versus fuel

outcries lessen, acreage for corn crops and soybeans are increasing and giving way to increased ethanol, biodiesel and renewable diesel production.“

BULL

Jessica’s Judgement I

Back on the renewable fuels bandwagon? You’re not the only one; greenhouse gas emission reduction is all the rage when biofuels are at a discount to petroleum products and are readily available. As the food versus fuel outcries lessen, acreage for corn crops and soybeans are increasing and giving way to increased ethanol, biodiesel and renewable diesel production. Government legislation is a driving factor in encouraging increased production and consumption—with the EPA raising the 2017 RVO, states such as California, Oregon, and Washington adopting, or in California’s case, readopting, Low Carbon Fuel Standards, and an active federal tax credit that is incentivizing producers and consumers alike. Feedstocks also play a role: the heating oil to (soy)bean oil

Jessica Phillips, Supply Support Manager See her bio, page 54

(HOBO) spread gained $0.08 on June 29, which was a sevenmonth high, arriving to -$0.78/USG; and corn crush values, the spread between the cost of corn and the price that producers can get for their ethanol, are gaining. With all of this being said, Q3 renewables are on the up and up, especially based on the expectation that crude will experience slight gains. Hold on to your hats though: it’s a Presidential election year—in case you had not heard—and Washington is distracted by our presumptive presidential nominees and thereby potentially less focused on renewable fuels. Let’s just hope that while the nominees are making headlines, they’re also formulating a coherent Energy Policy. •

RINs & RVOs FWIW Renewable Identification Numbers (RINs) were more interesting this quarter than the previous - primarily due to the Environmental Protection Agency’s May 18 release of the proposed 2017 Renewable Volume Obligation (RVO). RINS popped on 5/19, sending 2016 D4 Biodiesel up $0.06 to $0.8550 per RIN and 2016 D6 Ethanol RINs climbed $0.08 to $0.8175 per RIN. The EPA’s proposal for the 2017 Renewable Volume Obligations under the Renewable Fuel Standard is seeking a 700 million-gallon year-on-year increase of the total amount of biofuels to be blended into U.S. transportation fuels. Advanced renewable fuel is slated for just shy of a 400 million gallon bump from the 2016 obligation; conventional ethanol would account for 14.8 billion gallons of the 2017 total, a 300 million-gallon year-on-year increase; and cellulosic biofuel would grow by 82 million gallons. Although the EPA’s conventional renewable fuels proposal falls short of the 15 billion gallon statute, the increase shows the continued commitment (and apprehension) to breaking down the E10 “blend wall.” The public comment period on the proposal closed July 11. The Clean Air Act requires the EPA to issue the finalized RVOs under the RFS by November 30 each year for the following year in which the standards would apply. The good news is that the EPA is on track to meet the deadline, which will help provide some market certainty and stability for 2017.

Q2 2016 D4 & 2016 D6 RIN Values

2016 D4 Biodiesel RINs last traded at $0.9575/RIN and 2016 D6 Ethanol RINs last traded at $0.92/RIN due to continued concerns over 2017 RIN supply liquidity. With the 2017 RFS proposal raising the compliance bar, it is expected to be more difficult for refiners and importers to comply; therefore, RIN prices are predicted to stay elevated, and potentially move even higher in the coming months. •

Source: Oil Price Information Administration (OPIS)

Alternative Fuels

This article is brought to you by the letters “C” and “I” The California Air Resource Board’s (CARB) Low Carbon Fuel Standard (LCFS) credits are going down. In both April and May LCFS credits traded on average at $119 per ton in carbon intensity (CI). What a difference one year makes –in May 2015, credits traded at $22 per ton on average. Values are trending down relatively rapidly as of late, wrapping up June at $81/MT. Sellers are outnumbering buyers in the market place and thereby driving prices down. Month to month transfers are also weakening; there was a 19.1% decline in total credit volume transferred in May versus April, and June transfers are expected to be slightly down from May.

CARB’s reports estimate that through May 2016, program participants have transferred a total of 7.051 million metric tons of LCFS credits since the start of the program in 2010, which is 120.5% greater than 2015 reports. This is largely due to the re-adoption of the LCFS regulation at the start of 2016, which made the program more manageable. Procedures, carbon intensity calculation, the fuel pathway process, provisions and carbon intensity reduction requirements have been modified to better align with the goal of reducing the carbon intensity of California transportation fuels by 10% by 2020. In 2016, the required reduction is 2% from the 2010 baseline, which is double from the 2015 requirement and expected to increase gradually until 2020.

Gasoline Standards (gCO2/MJ)

Diesel Standards (gCO2/MJ)

2010 Baseline 98.47

2010 Baseline 102.01

2016 96.50

2016 99.97

2017 95.02

2017 98.44

2018 93.55

2018 96.91

2019 91.08

2019 94.36

2020 and subsequent years 88.62 2020 and subsequent years 91.81

CARB finished off Q2 by releasing updated CI pathways for biodiesel and renewable diesel. The greatest impact comes from the revised score for biodiesel with corn oil feedstock. The current CI of 4 is anticipated to experience an 8 to 12 point increase. This would, in turn, reduce biofuels produced from corn and potentially send producers to consider used cooking oil (UCO) as it is seeing a CI rating improvement. Along with UCO, soybean oil is expected to gain popularity with a reduced CI score. Previously, most pathways for soybean oil

biodiesel and renewable diesel production came in around 80 CI, which hindered soybean oils usage in production for LCFS credit generating purposes. However, recent certified scores received an average value of 50.82. Soybean Oil makes up nearly half of biodiesel production nationwide, but only accounted for 4,200 credits being generated in 2015, which is less than .20% of biodiesel and renewable diesel credits generated under CARB. The recent developments in the carbon intensity rating should turn the tables for soy methyl ester (SME) biofuels. •

Alternative Fuels

Trending Now: Renewable Diesel Renewable diesel is the new leader in the renewable fuels popularity contest. It has become a viable drop-in substitute to ultra-low sulfur diesel as it is an ASTM D975 compliant product with superior fuel properties that can be used to upgrade the diesel pool. Its feedstocks are primarily triglycerides, or fats and greases, such as: soybean oil, beef tallow, used cooking oil, etc. Revered for not only its low carbon footprint, as renewable diesel can reduce greenhouse gas emissions by up to 80 percent, the cost of fuel is typically several cents cheaper than petroleum diesel, thanks to feedstock and production costs coupled with renewable fuels incentives. Renewable diesel can be used in existing diesel infrastructure and, due to its exceptional storage stability, there is no expiration date. The chart below illustrates how renewable diesel stacks up against ULSD and biodiesel:

Fuel Properties Comparison

According to Energy Information Administration (EIA) data, renewable diesel imports climbed nearly 20 percent from February to March and continued to rise as Neste Oil USA’s product from Singapore finds its way to California and the Northeast. Domestically, Renewable Energy Group’s Geismar, Louisiana, plant is operating at nearly nameplate capacity, adding renewable diesel supply to the U.S. marketplace, along with the Darling Ingredients/Valero Energy joint-venture production facility, Diamond Green, in Norco, Louisiana. Due to the rising demand of renewable diesel, Diamond Green is planning to expand its annual capacity to 275 million gallons from the current 160 million gallons. The expansion project is on track to be completed in Q4 2017, with production beginning to increase in Q1 2018. As investments in renewable diesel production and distribution develop, so will accessibility and familiarity for consumers. •

All values are approximations and samples may vary slightly

Alternative Fuels

Natural Gas “I remain cautiously

pessimistic, however, as storage inventories enter Q3 above previous and 5-year averages.“

BEAR

Martin’s Measure I

Martin Trotter, Pricing & Structuring Analyst See his bio, page 54

Natural gas in Q2 was a wild ride. With natural disasters cutting consumption in some areas and high summer temperatures increasing demand in others, prices varied substantially by location. As the dust settles, it appears that natural gas prices found footing in late May to begin an upward climb. I remain cautiously pessimistic, however, as storage inventories enter Q3 above previous and 5-year averages. The glut of inventory will contribute to continued price suppression, which will also hurt chances of a full return to production. Based on the current outlook, I am bearish about prices in Q3. •

Domestic Natural Gas Prices

Cash Prices The year’s second quarter see-sawed away from Q1 trends as cash prices traded at a discount against those in the prompt month. After hitting calendar year lows to close out the first quarter, natural gas prices have rebounded dramatically—trading nearly $3.00/decatherm to close June, mirroring the same time last year. Average hub cash prices spiked nearly $0.50 between May and June driven by the return of warmer weather, with average recorded temperatures in Houston spiking and eight consecutive days above 90 degrees F. •

Forward Prices Prompt contracts led the rest of the curve higher, gaining nearly $0.70 throughout the quarter ahead of what some are predicting to be warmer-than-average summer temperatures. Calendar 2017 opened the quarter at a $0.10 discount to the outer years before rallying throughout May and closing June at a premium to calendar year 2018 – 2020. These atypical trends in the outer years could be attributed to recent sustained strength in the prompt settles. •

Q2 NYMEX NG – Cal Strips Weekly Settles

Source: New York Mercantile Exchange

Alternative Fuels

Natural Gas

Natural Gas Supply/Demand Fundamentals

Supply

U.S. Production Cuts Though seasonal temperatures are rising and some analysts are calling for a warmer-thanaverage summer season, natural gas production in the United States and Canada continues to fall. In the United States, rig counts remain 60% lower than last year. Associated gas—natural gas production as a byproduct of oil exploration— continued its Q1 trend into Q2, making for six straight months of declines after traditionally giving producers additional supply with attractive margins. These factors culminated in a drop in U.S. natural gas production to 68 billion cubic feet per day and continued fears that consistently lower natural gas prices will hinder a return to full-fledged production during the remainder of 2016.•

U.S. Natural Gas Production and Imports

Demand

Alberta Wildfires On May 1st, a fire broke out near Fort McMurray in Alberta, Canada that burned well into mid-June before firefighters could contain it. Dubbed the “Horse River Fire,” the incident is being hailed as the worst disaster in Canadian history. In addition to decimating 1.5 million acres, dangerous conditions and evacuations caused a complete shutdown of Shell Canada’s Albian Sands mining operation, as well as significant capacity reduction at Syncrude Canada and Suncor Energy mines. These production halts resulted in a 900 mmcf/day (near 25%) reduction in natural gas consumption related to power and bitumen generation, resulting in the lowest ever prices in the AECO pricing index. With fallout from the fires still underway, ultimate price stability and normalization remains uncertain.•

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

U.S. and Canada Natural Gas Prices

Source: Energy Information Administration (EIA), based on Bloomberg

Natural Gas Industrial and Power Sectors Consistently low prices in natural gas continue to make it an attractive option for use in the industrial and power generation sectors. While the industrial market leans on natural gas as a primary component to cultivate bulk chemicals, much of the projected demand in the power generation sector falls on the feet of compliance standards. In order to reach carbon dioxide emissions reduction goals, electricity generators will turn to natural gas-fired production, which burns cleaner than traditional coal-fired generation methods. Recent low natural gas prices also make the play more economically attractive than coal, which has led to expedited closures of many coal-fired generation facilities.•

U.S. Natural Gas Consumption by End-use Sector (2005-2040)

Natural Gas Storage Inventory Rounding out Q2, total natural gas storage stands just below 3.2 trillion cubic feet. While these levels are nearly 23% above the 5-year average for this time frame, the most current storage injection report indicates falling week over week builds, demonstrating a growth in demand that would be expected heading into warmer months. The future of natural gas storage facilities and their operations, however, face an uncertain future. The Aliso Canyon storage leak, where 97,000 tons of methane was unintentionally released into the atmosphere, has prompted a magnified look at storage infrastructure. Just before the close of Q2, President Obama signed a billed aimed at renewed pipeline safety measures. The aptly abbreviated PIPES (Protecting our Infrastructure of Pipelines and Enhancing Safety) Act contains new standards, touting enhancements in integrity, operations and environmental protection specifically for underground natural gas storage facilities.

Source: Energy Information Administration (EIA)

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

Having access to storage infrastructure allows suppliers to store gas during the cheaper summer months to sell during the winter, giving stability to their customers’ gas prices year round and lowering overall cost. Spreads between summer and winter months can be more than $0.50/dth, so having access to storage is crucial for suppliers to provide secure, affordable supply year round. •

Source: Energy Information Administration (EIA)

Alternative Fuels

Electrical Power Power Prices

BEAR

Keith’s Conjecture I

Keith Crunk, Wholesale Gas Supply Manager See his bio, page 54

Expectations for electricity demand through Q3 of this year are expected to be lower than the same time period in 2015, which should continue to keep prices mild. While the outlook for the C&I and transportation sectors should remain the same year-over-year, decreased usage in the residential sector is projected to drive an estimated 1.6 percent decrease in electricity sales. This is a result of expected cooler summer temperatures as compared to the summer of 2015. I continue to expect low volatility over the next few months. •

“ While the outlook for the

C&I and transportation sectors should remain the same year-over-year, decreased usage in the residential sector is projected to drive an estimated 1.6 percent decrease in electricity sales.“

Cash

U.S. Electricity Consumption

Cash power prices throughout Q2 followed the pattern shown in Q1 in the sense that, once again, there was little to no volatility. Though natural gas prices did rise during the quarter, it was gradual, and because of that, power prices saw little movement. Although prices at PJM West Hub moved up as temperatures supported cooling demand, highs in the upper 80s (during late May / early June) could not drive On-Peak power north of the $30 – $35/MWh range. There were only a handful of days where peak power prices cleared at a level higher than $40/MWh. At this price point, coal and gas peaking generation are supplying incremental MWh to the grid. •

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

Cal 2017 Wholesale Peak Power Prices

Forward/Term For the most part, the forward power curves continued the trend of low volatility from Q1 into Q2. While Cal 2017 forward prices in the Midwest, West, and Texas moved up only slightly throughout the quarter, prices in New York City actually followed a different course. Just one month into the quarter, Cal 2017 prices in NYISO Zone J jumped 15 percent and maintained this level through the balance of the quarter. This step change can be attributed to anticipated transmission constraints and resultant basis changes across New York as prices in the western part of the state moved lower over the same period. • Source: Platts

Alternative Fuels

Power Supply

Power Fundamentals

First New U.S. Nuclear Reactor in 20 Years Connected to Grid

Watts Bar Unit 2, within the Tennessee Valley Authority’s footprint, came online in early June 2016 and is the first nuclear generator to come online in the United States since 1996. Commercial operation is expected to begin in Q3, adding 1,150 MW of capacity to the grid. Following the Watts addition, there will be four other nuclear reactors on track to begin operation by 2020. •

Image courtesy Tennessee Valley Authority

Clean Power Plan—Rise of Natural Gas-Fired and Renewables Generation

U.S. Net Electricity Generation by Fuel (1990-2040)

The Clean Power Plan, rolled out by the U.S. Environmental Protection Agency in 2015, is expected to help expedite the growth of both natural gas-fired and renewable generation between now and 2030. Though the recent coal-fired generator retirements have caused the electricity supplied by natural gas-fired generators to exceed that of coal in 2016, the expectation is for that to decline temporarily until 2022 before again rising above coal and staying that way through 2040 and beyond. Moreover, projections of generation from renewables (e.g., wind and solar) are expected to rise in the stack, above coal, by 2029. •

Source: Energy Information Administration (EIA), Annual Energy Outlook, 2016

Viewpoints Seven Shales instead of Seven Sisters

The Seven Shales, part one

BAKKEN NIOBRARA PERMIAN HAYNESVILLE EAGLE FORD UTICA MARCELLUS

By Dr. Nancy Yamaguchi In the 1950s, Italy’s Enrico Mattei was credited with coining the term “Sette Sorelle,” or “Seven Sisters” to refer to what he viewed as the incestuously close association between seven major international oil companies: Exxon (Jersey), Mobil (Socony-Vacuum), Chevron (Standard Oil of California), Texaco, British Petroleum, Royal Dutch Shell and Gulf. At the time, they controlled the majority of global oil reserves. As the decades marched on, a dizzying succession of breakups, mergers and acquisitions changed all of the Seven Sisters. New players have entered the market in waves, including independents and national oil companies.

The Shale Revolution in the United States caused a major shift in the global market. As an interesting parallel, there are seven major shale play areas in the U.S. The author coined the term “The Seven Shales” to express the importance of these areas. The rebound in U.S. production has catapulted it above all other producers, and the U.S. is now the largest producer in the world. The Seven Shales are responsible for essentially all of the new oil and gas production in the country. Far too often, however, shale formations and hydraulic fracking operations are lumped into one phenomenon, when instead they have had dramatically different impacts on their regional markets.

Viewpoints Figure 1 provides the U.S. Energy Information Administration’s (EIA) map showing seven main shale play areas: Bakken, Niobrara, Eagle Ford, Permian, Haynesville, Marcellus and Utica. The Utica deposits are located alongside and partly underlying the Marcellus formation, and although this makes the Utica appear small, it is actually much larger than the Marcellus. While all of the deposits produce both oil and natural gas, the Bakken, Eagle Ford, and Permian developments are more oilbased while the Marcellus, Utica and Haynesville deposits are more gas-prone, and the Niobrara is in between. The Bakken formation is situated along the border of Montana and North Dakota, extending into Canada’s Saskatchewan Province. Canada also produces light tight oil (LTO) from this formation. The Niobrara region is mainly in Wyoming and Colorado, with extensions into Nebraska and Kansas. The Permian area covers a large swathe of West Texas plus the southeastern corner of New Mexico. The Eagle Ford region stretches south by southwest in the southern part of Texas, and the geologic structure extends into Mexico. To the northeast of Eagle Ford is the Haynesville area, which is located at the juncture of eastern Texas, northwestern Louisiana, and southwestern Arkansas. The Marcellus and Utica formations cover a large portion of Pennsylvania, New York, Ohio and West Virginia. Utica is a deeper formation, underlying much of Marcellus.

Figure 1: Key tight oil and shale gas regions BAKKEN

Now that prices have remained low for two years, many producers lack the cash to wait out the market—much less invest in any additional production. The following Figure 2 compares the trend in WTI crude spot prices, in $/barrel, with U.S. crude production, in thousand barrels per day (kbpd,) with a two-week lag. That is to say, the crude production trend is shifted over two weeks to allow a brief time for producers to respond. The two trend lines have tracked one another. The drop in U.S. production during the current quarter has been considered a bullish factor for crude prices, which have rallied and hit the $50/barrel mark in June. Ramping up U.S. production is not instantaneous, but it would not be surprising to see U.S. output rally in response to the current price rally seen in the chart. And naturally, in the current situation of oversupply, this would end the price rally, and rigs will go inactive again. And so forth.

UTICA MARCELLUS PERMIAN HAYNESVILLE Source: Energy Information Administration (EIA)

EAGLE FORD

Figure 2: WTI spot prices and U.S. crude production, two-week delay

Dollars per Barrel

It is difficult to overstate the importance of The Seven Shales. According to the U.S. Energy Information Administration, these seven regions were responsible for 92% of domestic oil production growth and all domestic natural gas production growth during 2011 – 14. If we reflect back to the oil price spike in 2008 and the dire economic recession that followed, the high oil prices were a financial burden on the country, yet they also created a boom time for the domestic oil industry. This helped ameliorate the recession by creating jobs and reducing dependence on oil imports. But the oil industry is famous for boombust cycles, and many of the new producing companies may become victims of their own success. There is little doubt that the spectacular rise in U.S. output was a prime force behind the collapse in global prices, because other producers had lost so much market share that the only solution at hand seemed to be cutting prices. The continued low prices are shutting in U.S. production. The EIA prepares weekly production estimates, and these estimates indicate that crude production fell by approximately 503 thousand barrels per day (kbpd) during the first five and one half months of 2016.

kbpd

NIOBRARA

Source: Energy Information Administration (EIA)

Viewpoints The crude price rally does appear to be revitalizing interest in drilling. According to Baker Hughes, the number of active rigs in the U.S. has dropped precipitously, but as the following Figure 3 shows, the pace at which rigs were shut slowed in April and May. It is possible that the rig count bottomed out at 404 rigs in late May, since the number rebounded to 408 in the first week of June, 414 in the second week of June, and 424 in the third week of June.

Figure 3: Has the U.S. rig count hit bottom? Rig Count

Clearly, the more efficient wells are the ones that remain in production. Just as clearly, having even one of them close makes a more significant dent in production. We will offer the 1980s overcapacity in U.S. refining as an analogy. In 1980, there were 319 refineries in the U.S., with an average size of 56.4 kbpd. The 1980s were a time of global refinery overcapacity, and refineries around the world were closed. In numerical terms, half of the refineries in the U.S. closed between 1980 and 2000. In 2000, there were 158 refineries remaining, but the average size had increased to 105.6 kbpd. The refining industry became stronger and more competitive, but the process was a painful one, as many people lost their livelihoods. Many U.S. producing companies are now fighting to remain standing in this type of a highly competitive environment.

Figure 4: Active rig count has plummeted, but productivity has risen, June 2015 vs. June 2016

Source: Baker Hughes

The idea that our market is coming more into balance is supported by the growing importance of the active drilling rig count. Even one or two rigs going from active to inactive, or the reverse, can spark a market reaction. Why? Figure 4 below sheds some light. In mid-June 2015, Baker Hughes reported that there were 859 active rigs in the United States. The EIA created a weighted average production-per-rig figure of 404 barrels per day. In mid-June 2016, the active rig count was 414 rigs (up from 404 rigs in late May.) The average oil production per rig, however, increased to 575 barrels per day. Source: Production per EIA, active rigs per Baker Hughes

ÂŠ 2016 Mansfield Energy Corp.

Viewpoints

Bakken The Famous Bakken Name

Fracking was far more prevalent in North Dakota. North Dakota’s crude production had reached approximately 140 kbpd in the mid-1980s before falling below 100 kbpd by the 1990s. The “fracking frenzy” caused production to skyrocket, surpassing the million-barrel-per-day mark by 2014. The shape of this production curve has been called a “hockey stick.” Despite low prices in 2014 and 2015, production continued to climb, reaching 1,174 kbpd in 2015. But certainly the steepness of the upward trajectory leveled off in 2015.

Figure 5: North Dakota and Montana Crude Production

The next Figure 6 shows the number of drilling rigs at work in the Bakken area along with the average oil production per rig. The number of active rigs peaked at 205 in 2012. By the end of 2013, oil prices were starting to fall, and the number of active rigs fell with them. The active rig count fell to 182 in 2013 and 183 in 2014 before dropping precipitously to 84 in 2015 and just 36 in the first half of 2016—the smallest number since 2007. Production per rig, however, has soared. In 2007, average production per rig was 116 barrels per day. The rigs now remaining are producing 792 bpd each.

Figure 6: Bakken Rigs and Production per Rig

When the terms shale oil, light tight oil, and hydrofracking are mentioned, the Bakken region often is the one that springs first to mind. Its development literally transformed communities in Montana and North Dakota into the modern-day equivalent of frontier towns. North Dakota was the site of what National Geographic called the “fracking frenzy,” in its March 2013 special feature, “America Strikes Oil: The Promise and Risk of Fracking.” Although the Bakken made it into the popular press, the general public often does not realize that there are actually seven shale play areas, nor that the ones in Texas are actually more prolific than the Bakken. But Texas was already the largest oil producing state in the country, while North Dakota (and Montana) had very little by way of an oil industry and an oil infrastructure, and oil production had been gently declining for years. As Figure 5 illustrates, Montana’s crude production had been in the vicinity of 80 kbpd in the 1980s before falling to 42 kbpd in 2000. Production rose to nearly 100 kbpd in 2006 before declining again to 78 kbpd in 2015.

Source: Production per EIA, active rigs per Baker Hughes

Impact on North Dakota and Montana Demand The impact of Bakken development came not only on the side of production. It also caused a surge in petroleum product consumption, as droves of people entered the area to work on the developments. The following two figures (Figures 7 and 8) show the trend in petroleum product demand in Montana and North Dakota. Both of these states were relatively small markets, where petroleum product demand was expected to gradually decline. According to the EIA, Montana’s demand was around 60 kbpd until the shale boom years in the mid2000s. Demand peaked at over 80 kbpd in 2007. Diesel sales in particular showed enormous growth. As the figure, shows, Montana’s diesel demand was approximately 20 – 22 kbpd during the 1990s. During the decade of the 2000s, it increased to a peak of 38 kbpd in 2007 before subsiding to 29 kbpd in 2013. Demand for liquefied petroleum gas (LPG) and ethanol also grew significantly.

during the 1990 – 2002 period, and it rose to 23 – 33 kbpd thereafter. LPG demand shot up to 15 kbpd in 2005, also responding to the influx of people and the rise in economic activity.

Figure 8: North Dakota Consumption of Key Liquid Fuels

Figure 7: Has the U.S. rig count hit bottom?

Source: Energy Information Administration (EIA)

North Dakota’s petroleum product consumption declined modestly in the 1990s, falling from 54 kbpd in 1990 to 52 kbpd in 1999. The development of the Bakken shale region reversed this, and demand hit a peak of 65 kbpd in 2005. Demand varied since then, but it remained in the range of 57 kbpd to 68 kbpd during the 2005 – 2013 period. Diesel demand had been roughly flat at around 20 kbpd

The boom time of exploration and development not only increased crude production, it also caused localized growth in petroleum product demand. This demand growth occurred largely heedless of price. In remoter areas of North Dakota and Montana, diesel markets showed especially rapid growth, since truck transit rose so dramatically. Now, on a national basis, low fuel prices are stimulating demand. But in some of the shale basin areas, economic activity has slowed, and people are drifting away. With the current low prices, it is economically rational to leave the higher-cost domestic resources in the ground. As noted, however, the oil industry is famous for boom and bust cycles, and if prices suddenly surge in a year or two, restoring domestic output will take time. Given that many of the producing areas in the Bakken shale region are in remote areas that faced infrastructure and human resources challenges to begin with, restoring output from the Famous Bakken may be slower than in other areas.

Viewpoints

Niobrara The Niobrara Shale Play Area and Crude Production Growth

averaged 858 kbpd during the first half of 2016. As the remaining, highly productive wells begin to play out without replacements, the drop in output may be steep.

The Niobrara shale play straddles Wyoming, Colorado, Kansas and Nebraska. All four states produce crude oil, but Nebraskan output is small at 8 kbpd in 2015. Figure 9 below shows the crude production trend according to the EIA.

Figure 10: Niobrara Rigs and Production per Rig

Wyoming and Kansas had the largest crude production in the 1980s, but as the figure illustrates, production was entering into a period of decline. Wyoming’s crude production peaked at around 350 kbpd in the mid-1980s before falling to 142 kbpd in 2004. New developments then reversed the production decline, and production rose to 240 kbpd in 2015. Wyoming’s geology is rich in fossil energy, and it is a significant producer of coal, natural gas and oil, which are the mainstays of the local economy.

Figure 9: Crude production, Niobrara Area States Source: Production per EIA, active rigs per Baker Hughes

Demand for Key Petroleum Fuels in the Niobrara States

Source: Energy Information Administration (EIA)

Crude production in Kansas peaked at 207 kbpd in 1985, and leveled off at around 90 – 94 kbpd from 2000 to 2005 before production began to grow again. Production reached 136 kbpd in 2014 before tailing off to 122 kbpd in 2015. Colorado’s production curve had the most noticeable “hockey stick” shape. Production was in the range of 80 – 88 kbpd in the 1980s before declining to 50 kbpd in 2000. LTO developments allowed Colorado’s crude output to grow sevenfold between 2000 and 2015. In 2015, Colorado’s crude output was 327 kbpd. Wyoming also achieved a major turnaround in production. Crude output fell from around 350 kbpd in the early 1980s to around 150 kbpd in the earlyand mid-2000s. It reversed its downward trend and rose to 240 kbpd in 2015.

The figure following (Figure 11) provides a look at consumption of key petroleum fuels in the four Niobrara states. Colorado and Kansas have the largest markets, according to the EIA. Colorado and Kansas are gasolinedominated markets. The Nebraska market is slightly weighted toward gasoline, but the diesel market is close in size. The Wyoming demand pattern is more reliant on diesel. Demand growth is fairly sedate, with demand for key fuels growing at an average rate of 0.58%/year over the 2004 – 2013 period for the four states. It is possible that the additional oilfield activity and increased demand for transport stimulated diesel demand, because the diesel market grew at rates of 1.62% per year from 2004 to 2013, a significantly higher rate

Figure 11: Consumption of Key Fuels in the Four Niobrara Area States

Loss of Active Rigs, and Gain in Drilling Productivity in Niobrara The next Figure 10 shows the number of drilling rigs at work in the Niobrara area along with the average oil production per rig. The rig count has shown considerable variability. It peaked at 116 rigs in 2008, then fell sharply to 52 active rigs in 2009. The rig count then rose to 100 in 2014. Global crude prices remained low throughout 2014 and 2015, and the rig count dropped sharply to 51 rigs in 2015 and 21 rigs in the first half of 2016. Production per rig, however, has soared. In 2007, average production per rig was 34 barrels per day. This climbed to 382 kbpd in 2014. As additional rigs closed, production per rig rose higher. It

Viewpoints of demand growth than for the other fuels. Excluding diesel, demand for key fuels grew at a rate of only 0.12% per year from 2004 through 2013. Wyoming is one of the largest coal-producing states, accounting for 39% of the coal mined in 2013. In 2014, approximately 88% of Wyoming’s electricity generation came from coal, and 11% came from renewables, chiefly wind.

Haynesville Oil and Gas Output in the Haynesville Shale Area The Haynesville shale play underlies portions of northeastern Texas, northwestern Louisiana, and southwestern Arkansas. Texas and Louisiana have such a massive oil and gas industry that the Haynesville output plays a less noticeable role, but its development and output has been important at the local level. The Haynesville area is natural gas-oriented. Texas is by far the largest crude producer in the country, and Louisiana has a significant output level as well. Arkansas has a small industry. Figure 12 below shows the crude production trend according to the EIA.

Crude production in Louisiana was 547 kbpd 1981, and it has been on a downward trend, falling below 200 kbpd in 2008. As was the case in Arkansas, production stabilized during the peak years of Haynesville output, then declined once again. Output averaged 173 kbpd in 2015. Texas is well known for the spectacular reversal of its crude production decline. Production of 2,554 kbpd in 1981 declined to 1,073 kbpd in 2004, before the shale boom hit. Production then soared to 3,547 kbpd by 2015. Haynesville’s output was very small, however, compared to the output from Eagle Ford and Permian.

Figure 12: Crude Production, Haynesville Area States

Arkansas produced 50 kbpd of crude in 1981, and this gently declined to 16 kbpd in 2006. There was a slight recovery and leveling off at 16 – 19 kbpd thereafter, consistent with the increased natural gas production in the Haynesville play.

Viewpoints Unlike the Permian and Eagle Ford plays, Haynesville was developed mainly for its natural gas output. Production began to ramp up in 2007 – 2009 and it reached a peak of 9,840 billion cubic feet per day (bcf/d) in 2011. In Figure 13 following, Haynesville’s oil production can be seen to be a mere fraction of the natural gas production, when it is converted to natural gas-equivalent terms. The figure also shows how quickly some developments can peak. Without a steady stream of investment in replacement wells, production is not sustained for long. The economics in Haynesville did not warrant a steady stream of investment in recent years.

Figure 13: Haynesville Production: Gas-oriented with an Early Peak

Demand for Key Petroleum Fuels in the Haynesville States Figure 15 provides a look at consumption of key liquid fuels (gasoline, jet fuel, diesel, LPG and ethanol) in the three Haynesville states. Texas has by far the largest market, with demand for key fuels of over 3 million barrels per day in 2013. Key fuels demand in Arkansas was 170 kbpd in 2013, and demand in Louisiana was 504 kbpd. Arkansas demand is mainly gasoline and diesel, but the market has been shrinking in recent years. Louisiana’s fuel demand had been growing very slowly, with only LPG showing significant demand growth. Texas was the only state showing significant growth in demand for all key fuels except for jet fuel. According to the data published by the EIA, Texas fuel demand grew at a rate averaging 2.29% per year from 1990 to 2013. These states have relatively large LPG markets, with a number of natural gas processing plants in the Haynesville area. •

Figure 15: Haynesville States Consumption of Key Fuels

Loss of Active Rigs, and Gain in Drilling Productivity in Haynesville The next Figure 14 shows the number of drilling rigs at work in the Haynesville area along with the average oil production per rig. The rig count peaked at 224 rigs in 2010, then fell to 149 active rigs in 2011. The rig count then dropped sharply to 45 rigs in 2013, bounced back to 51 rigs in 2014, and fell to 25 rigs in the first quarter of 2016. Production per rig jumped from 4 bpd in 2011 to 23 bpd in 2013 and 2014 and 28 bpd during the first quarter of 2016.

Editor’s Note: This is the first installment of a two-part article. Look for the second part to run in the FUELSNews 360° Third Quarter 2016 issue. Author’s note: This article has been updated and revised to consolidate individual chapters that appeared in Mansfield Oil Corporation’s FUELSNews daily publication between March and May, 2016. Unless otherwise noted, the sources of data for the charts are the U.S. Energy Information Administration (EIA) and Baker Hughes for rig counts. The data are estimates for the first half of 2016.

Figure 14: Haynesville Rigs and Production per Rig

Nancy Yamaguchi, Ph.D. Contributing Editor

Source: Production per EIA, active rigs per Baker Hughes

Nancy Yamaguchi is Contributing Editor for Mansfield Oil’s FUELSNews daily newsletter and the FUELSNews 360° Quarterly. She works closely with the Mansfield team to cover a wide range of topics influencing North American fuel markets. Dr. Yamaguchi has over 20 years of industry experience, and has spoken at numerous industry conferences and events nationwide.

Viewpoints

Smart Truck: The Future is Now

Pete Drucker, the founder of modern management, once said “the best way to predict the future is to create it.” In today’s transportation marketplace, the focus is on Federal Motor Carrier Safety Administration (FMCSA) reform and the electronic logging device (ELD) mandate, both of which focus on creating a safer working environment for drivers, improving road safety, and making it easier to track, manage, and share records of duty status (RODS) data. But these changes barely keep up with today’s progress and we need better solutions to plan for tomorrow. Today, many trucking companies are linked to their vehicles in some manner, but these solutions are typically inadequate. The most commonly adopted module is vehicle-to-infrastructure, which includes connectivity between the vehicle and an OEM, thirdparty telematics provider, a server, and then to the fleet. This is the kind of connectivity that occurs when a dispatcher looks at a map on a desktop displaying the location and status of the vehicles. However, this is not enough to move logistics into the future. Connected trucks are the future of transportation logistics and will revolutionize the functionality and safety of today’s heavy-duty trucks. Completely connected trucks profoundly change the logistical and transport process and will make road goods traffic more effective and efficient. The connected fleet has moved beyond mapping tools to encompass a wide range of vehicle systems and sensors, from engine results to driver-centric data and information from onboard safety systems. This will benefit the drivers, haulers, shippers, vehicle manufacturers, customers and society as a whole.

By Nikki A. Booth

OEMs like Daimler Trucks and Volvo are leading the charge to bring this to fruition. Their smart trucks have the potential to radically change road goods transport in the coming years. The plan is to fully connect trucks with their environment, becoming part of the Internet and continuously sending and receiving information. Wirelessly connected machines, devices, sensors and systems enable the exchange of important data and information. All those involved in the logistical process can then use these real-time data for their needs. This will greatly improve customer service by reducing paperwork, decreasing wait times while loading and unloading, and getting freight faster by avoiding traffic jams. Additionally, the connected truck will enhance the customer’s performance to operate their business more safely and in an even more environmentally friendly manner. According to Daimler’s website, with the availability and exchange of traffic data in real time, trucks with intelligent sensors will in the future be able to prevent rear-end collisions and circumvent traffic jams. At the same time, the downtimes of trucks can be reduced if the truck itself reports a fault at an early stage, and the hauler can schedule a service during the already planned downtime between two transport assignments. The worldwide transport of goods is a prerequisite for economic growth. OEMs are contributing to this growth and directing the future of transport with the connected truck—bringing a nearly 100 year old industry into a new age of innovation, safety and efficiency. The benefits of connected truck technology are endless for customers that depend upon trucking

logistics to support their business in some way. Whether it’s with their own truck fleet or with common carriers, this technology will help diagnose and solve potential problems before they impact operations. It pays to invest in systems that enable you to run your business more efficiently, with smarter, faster and safer equipment. •

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

Viewpoints

Electronic Stability Control

By Dan Kemeny While the ESC requirement is new to the trucking industry, it has been standard on passenger vehicles under 10,000 pounds for years. The regulation was phased-in starting in 2008 when 55% of model year 2009 vehicles were required to have ESC, a number that gradually built up to 100% for 2012 models and newer. According to United States Transportation Secretary Anthony Foxx, “ESC is a remarkable safety success story, a technology innovation that is already saving lives in passenger cars and light trucks. Requiring ESC on heavy trucks and large buses will bring that safety innovation to the largest vehicles on our highways, increasing safety for drivers and passengers of these vehicles and for all road users.” On its most basic level, ESC helps prevent rollovers and loss of control from over or understeering by utilizing select braking across all wheels while reducing engine power. With a price tag estimated to be at $600 per new tractor, there are few safety devices able to deliver such lifesaving capability at such an affordable price.

In a move that has been supported by many as a step forward in safety on our roadways, the National Highway Traffic Safety Administration (NHTSA) in 2015 announced that it would require new commercial trucks over 26,000 pounds to be equipped with electronic stability control systems (ESC) beginning in 2017. It is estimated that this could prevent 40 – 56% of untripped (when cornering causes the destabilization) rollover crashes, 14% of loss-of-control crashes, more than 1,800 crashes, 650 injuries and 50 fatalities annually. Both the National Tank Truck Carriers (NTTC) and American Trucking Association (ATA) welcome the change. Dan Furth, Vice President at NTTC was quoted as saying, “…this is an excellent outcome that will beget legitimate safety improvements to our industry and the motoring public at large.” ATA Executive Vice President Dave Osiecki said, “In 2015, NHSTA reported to Congress that truck rollover and passenger ejection were the greatest threats to truck driver safety. ESC technology can prevent rollovers and save lives. Many fleets have already begun voluntarily utilizing this technology and this new requirement will only speed up that process.”

Over the years, few mandates seem to have had such an overwhelming level of support from the industry as a whole, but in putting this requirement in place beginning in 2017, the NHTSA seems to have accomplished just that. •

Fuel Quality: Testing and Treatments If a company operates its own diesel storage tank and has never tested the fuel quality and cleanliness of that tank, they will likely be surprised when they do. Unless they are consistently treating fuel with additives and biocides, monitoring contaminants, and performing routine tank cleaning and maintenance, the fuel and the tank itself are likely dirtier than one would expect— much dirtier. Contamination issues with diesel begin with the inadequacies of ASTM D975, the standard specification for ultra-low sulfur diesel fuel (ULSD), which compounds problems in diesel storage tanks. If not remediated, the problems in the bulk fuel eventually make their way into fleet vehicles. This can result in expensive repairs, greater unscheduled maintenance and costly downtime.

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

By Clint Hamlin

Consider the following causes of poor fuel quality and their effects on storage tanks, dispensers and vehicle fuel systems: Impacts of Reduced Sulfur Content In 2006, the regulated sulfur content of U.S. diesel fuel dropped from 500 parts per million to 15 parts per million, a decision which has had several significant ramifications on diesel fuel’s operability. Sulfur is a natural lubricant, so reducing sulfur content in fuel leads to additional wear and tear on critical engine parts. Fuel economy has also been adversely affected by desulfurization, causing a 1% – 2% loss in efficiency. Importantly, sulfur impedes microbial growth in diesel fuel. So, ULSD does not have protection from

microbial growth that sulfur once provided. Consider the use of sulfur dioxide (SO2) in winemaking. SO2 is added as an anti-microbial agent and antioxidant to prevent undesirable yeast and bacteria growth. Sulfur in diesel fuel had similar benefits. With the removal of sulfur, today’s ULSD is more susceptible to microbial growth and diminished performance. Impacts of Water Accumulation ASTM D975 allows for up to 500ppm water in diesel fuel. That means that for every one million gallons of fuel that passes through a bulk fuel tank, 500 gallons of water can also pass through that tank. Water breeds particulates and microorganisms, such as algae, yeast and many other aerobic and anaerobic bugs, which then feed on diesel fuel and discharge gasses and acids that corrode tank walls and systems.

Moreover, the entrained water in diesel fuel usually contains sodium residue from salt dryers used in the refining process. Sodium can form deposits on injectors, create rust in storage tanks, and lead to blockages in fuel filters. The introduction of water into the fuel system leads to performance challenges for both the storage tank and the vehicle fuel tank. Impacts of Rising Biodiesel Production Biodiesel is another important factor in the performance issues plaguing bulk storage tanks and modern high-pressure common rail (HPCR) diesel engines. Biodiesel issues center on feedstock and quality. Few regulations govern biodiesel quality and production resulting in inconsistent biodiesel blend stocks, with unpredictable stability. While diesel engine manufacturers and fleet operators are responding by adding ever finer filtering to both storage tanks and diesel power units (down to 2 microns in some engines), these filters are more prone to filter plugging, especially from biodiesel blends. Waxy molecules in biodiesel can be less stable and prematurely fall out of solution, causing cold weather fuel gelling at higher temperatures than straight ULSD without bio blends. What’s the impact? The costs associated with poor fuel quality can quickly accumulate. Tank repairs can cost thousands of dollars and tank replacements can cost tens of thousands, depending on the extent of the damage. Replacing submersible pumps can cost several thousand dollars apiece, and tank cleanings typically cost a few thousand dollars for a thorough and complete cleaning. Engine damage can be even more costly, especially when amplified by the number of power units affected. Replacing fuel injectors can cost anywhere from $5,000 – $15,000; one major heavy duty engine manufacturer has indicated that on average 1+ injectors are failing within the typical warranty cycle of an HPCR engine. Couple that with power unit down time, and the cost of an injector

repair can be significant. Then there’s the reduced fuel economy that accompanies engine deposits. Fuel economy drops of 2% – 3% are not uncommon. Without a comprehensive fuel management program in place, fuel quality can decline, increasing the likelihood of these costly repairs. What can we do to protect against these issues? Improved Fuel Quality Requires a Comprehensive Program, Including Fuel Testing, Tank Maintenance and Fuel Treatment Addressing fuel quality concerns requires a comprehensive program made up of three important components: fuel testing, tank maintenance and cleaning, and fuel treatment. Fuel tests conducted on tank bottom and nozzle samples assess contamination issues related to sediment, water and microbial growth. Visual tank inspections provide real time assessment of tank conditions and potential tank integrity breaches. Filter inspections and testing enable site managers to determine what’s passing through the fuel tank and dispenser systems. With gross contaminations, remediation may require additional services. Certified service technicians have varying levels of procedures—from a bottom sweep to pump-out and polishing—that can be applied, depending on the severity of contamination. Using a combination of physical cleaning and additives can help restore a tank to clean operating condition and keep the fuel inside clean and clear of contamination. Additives not only play a role in engine cleanliness and performance restoration, but also in storage tank maintenance. Once considered a premium luxury for vehicles, additives are now a necessary heavy-duty truck measure to prevent tank and engine damage. Additives can aid in cleaning fuel, reducing water, and exterminating microorganisms in bulk fuel environments. The administration of a year-round additive program can restore the operability of diesel

fuel, protect the fuel from future contamination and optimize fuel performance on a continual basis. Diesel engines are built with tighter tolerances and increasingly sensitive technology that requires a more sophisticated fuel. Additives can help restore and maintain an engine manufacture’s original performance claims. While the industry waits for the diesel fuel spec to catch up to the demands of today’s modern engine and storage tank technology, expensive problems associated with diesel fuel quality will continue to plague commercial fueling operations. A proactive fuel quality program that encompasses testing, cleaning and ongoing preventative maintenance is an important step in mitigating these challenges and ensuring optimal diesel engine operability. •

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

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

Evan Smiles

Andy Milton

Supply Manager

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

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

Amy Nguyen

Supply Optimization Supervisor

Dan Luther

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

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

Jessica Phillips Supply Support Manager

Nate Kovacevich Senior Supply Manager

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

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

Keith Crunk

Wholesale Gas Supply Manager

Chris Carter Supply Manager

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

Keith Crunk is responsible for managing supply purchases for contracted customers in various markets, long-term physical and financial hedging, pipeline and storage asset management, and pipeline scheduling. Keith has over a decade of experience with analytics and forecasting in the power and gas industry. •

Martin Trotter

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

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