FUELSNews 360° - Q3 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 Q3 2016 FUELSNews 360°, published four times annually by Mansfield Energy Corp., analyzes and summarizes the prior quarter’s activity in the oil, natural gas, and refined products industries. The purpose of this report is to provide industry market data, trends, and reporting both domestically and globally as well as provide insight into upcoming challenges facing the energy supply chain.

Executive Summary

Overview

July through September 2016

3rd Quarter Summary

Economic Outlook 8

Global Economic Outlook

U.S. Economic Outlook

Regional Views continued 29 31 32

Oil Transport: Modes and Safety Issues

Development of U.S. Crude, Gasoline, and Diesel Stocks

Is U.S. Crude Production Ready for a Resurgence?

Retail Prices Remained Below Last Year’s Levels

Canada

Alternative Fuels 32

Renewable Fuels Commentary: Sara Bonario

Natural Gas Commentary: Martin Trotter

Fundamentals 12

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

Power Commentary: Keith Crunk

Viewpoints 38

The Seven Shales, Part Two by Dr. Nancy Yamaguchi

Transportation and Logistics by Dan Kemeny

Regional Views

Situational Awareness: If You See Something, Say Something

by Nikki A. Booth

PADD 1A, Northeast Commentary: Evan Smiles

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

PADD 2, Midwest 52

PADD 3, Gulf Coast PADD 4, Rocky Mountain Commentary: Nate Kovacevich

The Best Cure for Low Prices by Alan Apthorp

Commentary: Dan Luther

Winter Diesel Operability: Expect the Unexpected by Clint Hamlin

Commentary: Dan Luther

Why Renewables? by Sara Bonario

FUELSNews 360˚ Supply Team

Q3 2016 Executive Summary The third quarter was a bumpy ride for crude prices, but prices eventually found their footing in the mid to high $40/barrel range as the bulls and bears slugged it out. Common wisdom had been that crude prices would languish during Q3, rise to the $50/barrel range in Q4, and solidify in 2017 and beyond. As the third quarter marched on, industry analysts began retreating from their more bullish supply/demand forecasts, indicating that low prices would extend until late 2016 or early 2017. This seemed reasonably likely until OPEC stepped in, signaled potential output freezes, and drove crude prices back to the $50/barrel trajectory. Due to several downstream supply interruptions, Q3 proved more bullish for refined products prices in several regions of the U.S. The Colonial Pipeline, which supplies much of the East with Gulf Coast refined products, experienced a pipeline break on Line 1 (the gasoline line) and was shut down for a week. Other less significant, but important, events, including refinery outages and turn arounds, also occurred during Q3 in the Gulf Coast, Midwest, and West Coast. All of these events drove refined products prices up in the Southeast, Northeast, and Midwest. Most significantly, gasoline and distillate supply was severely hampered along the East Coast, causing 10 – 20 cent gasoline price increases from Alabama to Maryland. Q4 is setting up to be an interesting quarter for crude prices. There are several important short-term bullish signs. Analysts believe that OPEC will likely agree to some form of production freeze by the end of 2016, lending support for crude prices; however, this is certainly not a slam dunk. U.S. elections will be over in November, putting the associated economic uncertainty, and its requisite fuel demand dampening sentiment, behind us. The bears also have a strong case in Q4. While we have seen U.S. crude inventories decline more than expected in September, U.S. and worldwide crude inventories remain near all-time highs. In addition, there is a good chance that the Federal Reserve will hike interest rates in December, which historically has been a bearish indicator for crude. So, what will be the net effect of these bullish and bearish trends in Q4? Absent any major unexpected global economic or geopolitical shocks, we anticipate oil prices will remain range-bound in the mid-$40s to mid-$50s. It is unlikely that we will see a significant decline or run-up in crude prices. But as we move into 2017, the momentum is on the side of the bulls, and we expect crude prices to firm up as we move through the year. We have a lot in store for you in this quarter’s issue of FUELSNews 360°. We continue our two-part series intended to enhance your understanding of domestic crude supply and demand dynamics. In part two of the article “The Seven Shales,” Dr. Nancy Yamaguchi gives insight into the shale reserves that drive American production of oil and gas. Please visit www.fuelsnews.com to read part one of “The Seven Shales” and further your understanding of this important dynamic in North America’s energy evolution. We hope you enjoy this quarter’s issue of FUELSNews 360°. Please feel free to email us at fuelsnews@mansfieldoil.com with feedback, questions, or simply to request additional copies. Thanks for reading! •

Overview July 2016 through September 2016 WTI Crude Oil Futures

The world oil market in the third quarter of 2016 took a few steps back from the path to global supply and demand balance. It had been widely accepted that a rough balance would be achieved by the fourth quarter of this year, and that WTI crude prices would reach the $50/b level and remain at least in this neighborhood. WTI did surpass the $50/b mark in June, but it was unable to do this in Q3. On the demand side, a number of global demand forecasts have been revised downward, causing prices to sag. Relative to Q1, the average prices of WTI, distillate, and gasoline (RBOB) all increased significantly in Q2. However, in Q3, the average price of WTI declined slightly, falling from $1.09/gal ($45.61/b) in Q2 to $1.07/gal ($44.94/b) in Q3. The average price of gasoline fell even further in Q3, dropping from $1.54/gal in Q2 to $1.40/gal in Q3. Only distillate prices showed a modest increase from Q2 to Q3, rising from $1.39/gal in Q2 to $1.42/gal in Q3.

Quarterly NYMEX Price Averages

Source: New York Mercantile Exchange (NYMEX)

How did the supply glut reach a point of potential widening, when the “schedule” called for end-of-year balance?

This may or may not continue since the Niger Delta Avengers group has recently announced another attack on a Bonny crude pipeline, but such attacks have decreased greatly.

First, the return to a supply and demand balance was predicated on a decline in U.S. production. U.S. crude production fell from 9.6 MMbpd during the first week of July in 2015 to 8.43 MMbpd during the first week of July in 2016. But even with relatively weak prices, U.S. crude production pulled out of decline. Some idled rigs have returned to work. Drilling productivity has risen. At the beginning of Q3, crude production was 8.43 MMbpd, and by the end of Q3, it had rebounded slightly to 8.5 MMbpd.

Third, Russia and Saudi Arabia have been pumping ever-growing volumes. Iranian output has been growing at what appears to be the fastest rate that the country can manage. In a way, however, these factors made it easier to reach the end-of-quarter production cut promised by the Algiers agreement. By overproducing to such a large degree, Saudi Arabia will be able to reduce output in Q4 and still retain a higher level of output than it had at the outset of the price war. The September 28 Algiers meeting repeatedly raised and dashed expectations as participants interacted and made pronouncements. Although the agreement is more of an outline to make an agreement, it is a historic achievement nonetheless, since at long last the group is formulating a plan to reduce production. The target production level is reportedly between 32.5 and 33.0 MMbpd, to be achieved in approximately two months. A committee will be established to chart a path to this production level. OPEC’s Monthly Oil Report listed output, based on secondary sources, at 33.237 MMbpd in August. This would translate into a production cut of between 0.237 MMbpd and 0.735 MMbpd. The deal was brokered by the meeting hosts in Algeria. It appeared that Saudi Arabia made most of the concessions, finally convincing Iran to participate. •

Second, some of the market support last quarter came in the form of unplanned supply outages: the raging wildfires in Canada, militant violence in Nigeria, and chronic instability and violence in Libya. The market fully expected a restoration of Canadian output, but the situations in Libya and Nigeria were unpredictable. In Q3, Libya’s Ras Lanuf port has reopened for the first time since 2014. Nigeria reported to OPEC that its crude production rose from 1,272 kbpd in July to 1,456 kbpd in August, and its Energy Minister just announced that production has risen to approximately 1,750 kbpd in September.

Overview Third Quarter Summary Summary, Third Quarter, 2016 $1.538 $1.463

$48.24

18,308

Source: New York Mercantile Exchange (NYMEX)

Crude and product prices trended down for most of July and into August. WTI prices dipped below $40/b in early August. OPEC countries and Russia began to plan an informal meeting in Algiers to discuss a market stabilization agreement. This pulled oil prices out of their downward slide, though the endof-quarter rally did not place WTI prices back on track for $50/b. The market has grown wary of believing that OPEC meetings will result in any serious limits on production. Nonetheless, the Algiers agreement was a historic event. Futures prices for RBOB had slumped as low as $1.27/gallon in early September. This was the lowest price since late February. The recovery of crude prices helped reverse this, and more support to gasoline prices came from Hurricane Hermine, the Colonial Pipeline outage, various refinery outages, and the overall price increase after the Algiers agreement. RBOB prices bounced back above $1.40/gallon in mid-September and strengthened to $1.46/gallon by the end of the quarter. Diesel prices began the quarter at around $1.45 â&#x20AC;&#x201C; $1.50/gallon. Prices declined to around $1.40/gallon in midSeptember before rising to $1.54/gallon at the end of the quarter.

At the retail level, gasoline prices at the beginning of Q3 averaged $2.381/gallon. Average retail gasoline prices declined to $2.224 by the end of the quarter. This price was $0.098/gallon less than it was at the end of the third quarter in 2015. Retail diesel prices averaged $2.423/gallon at the beginning of Q3, declining to $2.382/gallon by the end of the quarter. This price was $0.094/gallon less than it was at the same time the previous year. Like crude inventories, product inventories remained above seasonal and five-year averages. Gasoline stockpiles started the quarter at 239 million barrels. This declined to 227 million barrels for the end of the quarter. Distillate inventories began to climb once again, rising from 149 million barrels at the start of the quarter to 163 million barrels at the end of the quarter. â&#x20AC;˘

ÂŠ 2016 Mansfield Energy Corp.

IIIII II

Global Economic Outlook

IIII II I

In September 2016, the World Bank and the Institute for Health Metrics and Evaluation (IHME) released their joint study, “The Cost of Air Pollution: Strengthening the Economic Case for Action.” Because the costs of air pollution are sometimes hidden, this study sought to quantify the costs to the global economy as a call to action for public policy. The study concludes that air pollution is the deadliest form of pollution. It is the fourth leading risk factor for premature deaths worldwide. The study found that these deaths cost the global economy about US$225 billion in lost labor income in 2013. An estimated 5.5 million lives were lost in 2013 to diseases associated with outdoor and household air pollution, causing human suffering and reducing economic development. As the World Bank and other international agencies have noted, emerging markets and developing economies (EMDEs) are the main drivers of global economic growth. In the World Bank’s Global Economic Prospects report, the forecast of economic growth in the advanced economies was 1.7%. In contrast, economic growth in the EMDEs was forecasted to be 3.5%.

determined that the annual labor income losses were equivalent to 0.83% of gross domestic product (GDP) in South Asia. In East Asia and the Pacific, where the population is aging, labor income losses represent 0.25% of GDP, while in SubSaharan Africa, where air pollution impairs the earning potential of younger populations, annual labor income losses represent the equivalent of 0.61% of GDP.

Welfare Losses Due to Air Pollution by Region 2013

Air pollution poses a particular danger in low- and middle-income economies. Approximately 90% of the population in these countries is exposed to levels of ambient air pollution that exceed the air quality guidelines set by the World Health Organization (WHO). Young children and the elderly are at the greatest risk, yet premature deaths also result in lost labor income for working-age people. The WB/IHME study

Percentage of Attributable Deaths by Risk Factor: Globally, 2013

Source: World Bank and IHME. Note: Total air pollution damages include ambient PM 2.5, household PM 2.5 , and ozone. GDP=gross domestic product.

According to the study team: When looking at fatalities across all age groups through the lens of “welfare losses,” an approach commonly used to evaluate the costs and benefits of environmental regulations in a given country context, the aggregate cost of premature deaths was more than US$5 trillion worldwide in 2013. In East and South Asia, welfare losses related to air pollution were the equivalent of about 7.5% of GDP. To place the costs in perspective, the study’s authors noted that US$5.11 trillion in welfare losses were equivalent to the combined GDP of India, Canada, and Mexico, “a sobering wake-up call.” •

Source: World Bank and IHME, using data from IHME, GBD 2013

IIIII II

U.S. Economic Outlook

Consumer Sentiment Index

IIII II I

Consumer Sentiment Index Q3 2016

JULY 90

AUGUST 89.8

SEPT 91.2

It is almost impossible to speak of U.S. economic policy without referring to “the Fed.” The Federal Reserve sets U.S. monetary policy, and its decisions determine the course of the U.S. Dollar. Because global crude trade is denominated in U.S. Dollars, the actions of the Fed have immediate consequences for the international oil market. The complexity of the U.S. economic outlook is underscored by the diverging opinions among voting members of the Fed Board of Governors. Under Dr. Janet Yellen, the Fed has continued to shepherd the economy to recovery and expansion. The Fed evaluates a myriad of economic indicators as a matter of course, analyzing the inter-relationships to judge the health of the economy and the proper monetary policy strategy. The current Fed has had a generally “dovish” stance, and it has been cautious about interest rate hikes in the aftermath of the recession. Quantifying the exact cost of the recession is impossible, but most analyses and estimates place the cost in the trillions, not billions, of dollars. The Fed has been cautious about taking any actions that might work against the slow grinding recovery that is underway. In December 2015, the Fed raised its key interest rate for the first time since 2006. This indicated that the U.S. economy was greatly strengthened. At the March 2016 meeting, two additional rate increases were planned for 2016. These have been postponed again and again because economic indicators have not been uniformly positive. At the most recent Fed meeting in September, a rate increase was once again foregone, but the sentiment on the Board had grown more divided with three members dissenting.

Source: University of Michigan

The fact that the hawkish position is strengthening indicates that there are positive signs from the U.S. economy, but the fact that the dovish position holds the majority suggests the economy is not considered as robust as desired. The Fed’s actions in the upcoming December meeting could significantly impact crude prices. If the Federal Reserve raises interest rates, as many expect, the U.S. Dollar will strengthen. The U.S. Dollar and oil prices have historically been inversely correlated. Therefore, if the Fed raises interest rates in December, the market will likely reflect a bearish impact on oil prices. Most expect an interest rate hike come December; should the Fed choose not to raise rates, the U.S. Dollar could weaken, putting upward pressure on fuel prices. There are several factors the Fed is considering as it decides whether to hike or hold, including consumer sentiment, unemployment, and inflation. The Consumer Sentiment Index improved considerably during Q2. It had dropped to 89 in April, but it rose to 94.7 in May before tapering off to 93.5 in June. In Q3, however, it declined to 90 in July and 89.8 in August before bouncing back to 91.2 in September.

The August Beige Book, an economic commentary from the Federal Reserve bank released prior to Federal Open Market Committee (FOMC) meetings, stated that reports from the 12 Federal Reserve Districts indicated national economic activity “continued to expand at a modest pace,” but that activity had remained unchanged in Kansas City, Missouri, and New York, and that activity had slowed in Philadelphia and Richmond, Virginia.

The third quarter also brought a leveling off of oil prices as the supply overhang began to grow rather than shrink. Prices dropped in late July and early August before OPEC and other producers began to speak of the Algiers meeting in September. The U.S. Dollar also began to rise during this period. As oil prices recovered in the second half of September, the U.S. Dollar has stabilized as well.

As the following figure illustrates, unemployment rates have fallen significantly in 2016. They remained stubbornly high from 2009 – 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 dropped to 4.7%, partly reflecting a large number of unemployed persons exiting the labor force. In Q3, unemployment rates have stabilized at 4.9%.

Average Unemployment Rate, 16YO+

Source: Bureau of Labor Statistics

Inflation remained flat at approximately 1.7% during Q3, and in fact has been roughly unchanged all year. The Fed has a 2% target. Historically, policymakers have relied on a relationship between unemployment and inflation known as the Phillips curve, which implies that, as the economy reaches full employment, inflation will also rise. Recently, however, employment has improved without a corresponding upward inflationary pressure. The Fed is assessing whether the flattening of the Phillips curve is part of the “new normal” in the economy.

WTI Crude and U.S. Dollar Move Contraflow

Trimmed Personal Consumption Expenditures (PCE) Percentage of Change

Source: NYMEX, Intercontinental Exchange

The Algiers agreement at the end of Q3 prompted a crude price rally that corresponded with a slight decline in the U.S. Dollar. The coming quarter will require close attention to how the deal translates into action. Alongside this, there will be close attention paid to the actions of the Fed. Will a strong dollar moderate oil prices? Or will rising oil prices put pressure on the U.S. Dollar? •

Fundamentals Oil Transport: Modes and Safety Issues

The Key Role of Pipelines

The Key Role of Pipelines in Deliverying Crude to U.S. Refineries

The U.S. has the largest refining industry in the world, spread from coast to coast and including two non-contiguous states: Alaska and Hawaii. Delivering crude to these refineries is a massive logistical exercise. The shale boom added another layer of complexity, since many of the new shale plays were not connected to existing oil transport infrastructure. New production areas created a need for additional transport infrastructure and the use of alternative transportation modes. This special feature discusses how oil gets to refineries, with emphasis on pipelines and railcars. Both modes are considered safe, yet both have been in the news because of accidents. Although accidents are infrequent, petroleum is classified as a hazardous liquid, and any accidental release is cause for concern. In the early 1980s, pipelines delivered nearly two-thirds of crude receipts to refineries. This began to slowly decline during the late 1980s until 2005, when pipeline deliveries fell to around 48%. After 2005, however, a resurgence in pipeline deliveries began, and in 2015, pipelines were responsible for nearly 61% of crude deliveries. In 2015, U.S. refineries received 16,452 kbpd of crude oil, 10,026 kbpd of which was delivered by pipeline.

Source: Energy Information Administration (EIA)

ÂŠ 2016 Mansfield Energy Corp.

Fundamentals

Changes in Domestic and Foreign Crude Transport Modes The reason for the changing percentage carried by pipelines becomes clear if we separate domestic crude from foreign crude, as the next two charts do. Looking first at deliveries of foreign crude, tankers are, as might be expected, the most important transport mode. As U.S. domestic crude production declined, foreign crude imports rose. The percentage share of tanker deliveries rose from 26% in 1985 to 47.8% in 2005. In 2005, tankers had nearly caught up with pipelines, delivering 7,319 kbpd of crude versus pipeline deliveries of 7,387 kbpd. After 2005, however, tanker deliveries of foreign crude steadily slid down. In 2004, foreign crude deliveries by tanker had been 6,535 kbpd. This dropped by an incredible 2,612 kbpd, plummeting to 3,923 kbpd in 2015.

Domestic crude deliveries began to fall because U.S. crude production fell. Pipeline deliveries peaked at 6,804 kbpd in 1985. They declined for the next two decades, hitting the nadir at 4,325 kbpd in 2005. The ensuing decade from 2005 â&#x20AC;&#x201C; 2015 witnessed a major resurgence in pipeline deliveries, which soared to 7,168 kbpd in 2015 as production from shale plays began to crowd into the system, seeking refineries.

U.S. Refinery Receipts of Domestic Crude by Transport Mode, kbpd

The explanation can be summarized in two words: shale boom.

U.S. Refinery Receipts of Foreign Crude by Transport Mode, kbpd

Source: Energy Information Administration (EIA)

In the early days of the shale boom, the inability of pipeline capacity and connections to cope with the influx of new crudes led to a scramble for new transportation methods. Pipelines are usually regarded as the cheapest and safest oil transport mode, but building and expanding pipelines take time. As the figure shows, there was growth in all other modes as well.

ÂŠ 2016 Mansfield Energy Corp.

Fundamentals Because pipelines and tankers are such dominant modes, the next figure presents the data for barges, tank cars, and trucks only. The use of these modes surged in recent years, growing from 604 kbpd in 2004 to 1,779 kbpd in 2014. But the total fell to 1,602 kbpd in 2015, corresponding with the decline in U.S. production and the completion of new pipelines.

U.S. Refinery Receipts of Crude by Mode, Excluding Pipeline and Tanker

Source: Energy Information Administration (EIA)

The transport modes used to deliver crude to U.S. refineries have changed enormously over the past decade. Before the shale boom, it was accepted that foreign crude receipts would continue to grow, and that the common modes would be tanker deliveries and pipeline deliveries. The increase in U.S. crude production over the past decade strained the transport infrastructure, and refineries began to receive more crude via barge, tank car, and truck. Tank cars were needed, for example, to deliver crude to refineries on the East Coast and West Coast that were not connected by pipeline to the main crude-producing areas in the center of the country. But the use of these modes has tailed off somewhat. First, pipeline capacities and connections have been expanded. Second, U.S. production has fallen. Many forecasts suspect the production decline has not yet ended. If this turns out to be true, it is logical to expect there will be continued easing of domestic crude transport capability, which will reduce reliance on the more expensive modes of barges, tank cars, and trucks.

Crude Oil Transport by Rail: The Ups and Downs

As light tight oil (LTO) production from shale plays began to surge, U.S. crude transport infrastructure was strained to deliver the new crudes to refineries. This was particularly the case in frontier producing areas such as the Williston Basin and the Rocky Mountains. As noted, many pipelines were either full or did not connect with the new output. Crude by rail was looked to as an alternative mode of transportation. The expression “rolling pipeline” came into use. Rail offered flexibility that some pipelines could not. For example, there are no crude oil pipelines that connect the Bakken crudes with refineries in California. Building a 1,500-mile pipeline from North Dakota to Los Angeles would be extraordinarily expensive, and it would take a feat of engineering to get it across the Rocky Mountains. There are many railroad connections, however.

Crude transported via railcar grew quickly. According to the U.S. Department of Transportation, 9,344 carloads terminated on U.S. Class I railroads in 2008. In 2014, this had soared to 540,383 carloads. As the following figure shows, U.S. refinery crude receipts by tank car jumped from 18 kbpd in 2011, to 94 kbpd in 2012, to 239 kbpd in 2013, and to 431 kbpd in 2014. In 2015, however, crude by tank car declined to 343 kbpd. There was less demand for rail transport, with one reason being that additional pipeline connections had been completed.

Fundamentals

U.S. Refinery Receipts of Crude Oil by Tank Car, kbpd

Source: Energy Information Administration (EIA)

It is also possible that safety concerns are turning shippers away from railcars. The rapid increase in crude by rail resulted in a number of accidents, including a catastrophic one involving rail transport from the U.S. to Canada. This was the tragic Lac-Mégantic derailment in Canada’s Quebec province, in July 2013. The train was carrying Bakken crude to the Irving Oil refinery in New Brunswick. The derailment and explosion killed 47 people and spilled 1.5 million gallons of crude oil. Another derailment occurred in November 2013 at Aliceville, Alabama. This was a derailment of 25 Bakken crude oil tank cars, causing a fire and a spill. Another Bakken crude train derailment occurred in December 2013 near Casselton, North Dakota, causing an explosion and a fire that necessitated the evacuation of thousands of people. Light tight oils (LTOs) are, as the name suggests, lighter than conventional heavy oils. Crude oils are complex mixtures of hydrocarbons, and LTOs contain a higher percentage of lighter compounds that, if fractionated out of the LTO, would be considered similar to natural gas liquids or condensates. Stabilizing a light crude prior to transport involves reducing the volatility and vapor pressure of the oil by removing the gaseous fractions. This has not been done with Bakken LTOs, and the issue remains contentious. Some believe that since Bakken LTOs have been the culprit in a variety of accidents, it stands to reason that the crude should be stabilized prior to shipment. Others point out that all crudes are flammable, and their opinion is that LTOs are no different from other light crude oils. An interesting hybrid view is that, yes, the LTOs contain more volatile fractions, but since North Dakota has no capability to handle the light ends, it would have to export them by rail, and that this would be even more dangerous than leaving them in the LTO. The matter is not at all clear, but it does serve to illustrate the point that people have widely ranging opinions on the matter. The U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) investigated the derailments, and in January 2014, the agency issued a safety alert that Bakken crudes might be more flammable than traditional heavy crude. A number of regulatory measures followed, covering proper classification, reporting, inspections, training, retirement of some railcars and retrofitting of others, and other safety measures. In 2014, there were derailments in New Brunswick, Pennsylvania, and Virginia. In 2015, there were derailments in Pennsylvania, West Virginia, Ontario, Illinois, and North Dakota.

In June 2016, a 16-car derailment spilled Bakken crude in Washington state. Several states have proposed or enacted additional safety measures, including Illinois, Nebraska, Minnesota, New Jersey, California, Oregon, and Washington. Many of these measures are pending. Some residents would like to ban crude by rail entirely. The regulatory horizon is far from certain, and some rail terminal proposals have been delayed. Now, after two years of low oil prices, some of the risk is being reduced for an entirely different reason: the drop in U.S. crude production. U.S. crude production has fallen by approximately 722 kbpd so far this year. Foreign crude imports have risen in response, carried chiefly by pipeline and tanker. The huge surge in crude by rail brought a number of tragic accidents. The goal is always to have zero incidents, but there is little agreement on how to get there, and on who should pay. Shall LTOs be stabilized prior to shipping, and if so, what should be done with the recovered light ends? Pulling out this material reduces the volume of LTO that can be sold as LTO, and forces it to be sold at a lower price. Shall railcar specifications be tightened? Do the railways themselves need repair? Shall there be speed limits? Additional personnel requirements and training? Specific labeling and notifications? Thorough emergency response plans along railcar routes? Specific operational rules and procedures depending on weather? Where should the time and money be spent to get the best results? The solution will likely require attention to all elements: the cargo, the railcars, the infrastructure, and the way the trains are operated. A number of safety measures have now been proposed and/or are being enacted, but many states are dissatisfied and planning measures of their own. How will costs rise if the U.S. becomes a patchwork of varying regulation? There is as yet no clear consensus on what actions will be the most effective in reducing risk. But the last two years of low prices were unforeseen, and they have cut into LTO production and, consequently, the need for rail transport. The combination of increased experience, safety regulations, and reduced oil in transit is almost certain to reduce derailments in the future, and to reduce the damage and potential loss of life when they do occur. But if there is any resurgence in U.S. crude production as prices rise, demand for oil transport by rail will likely rise once again, and the public will demand that safety issues be addressed first.

Fundamentals

Pipeline Age and Safety Record

The majority of U.S. pipelines were built prior to 1970. When installed and maintained properly, steel pipelines can last for many decades, though welds and connection points can eventually become compromised. In 2011, after serious incidents with natural gas pipelines, the U.S. Department of Transportation (DOT) and its Pipeline and Hazardous Materials Safety Administration (PHMSA) issued a call to action to accelerate the repair, rehabilitation, and replacement of the highest-risk pipelines. The highest risk factors were age and material, since many of the oldest pipelines were built of cast and wrought iron rather than steel. The biggest threats to these lines is earth movement, usually caused by digging, seasonal frost heave, or changes in ground water levels. PHMSA now reports on pipeline miles by decade installed.

Pipeline Miles by Decade Installed, Crude and Petroleum Products

As the figure to the right illustrates, the majority of refined product pipelines were built during the 1940s, 1950s, 1960s, and 1970s. A large percentage of crude oil pipelines were also built during that time period, but there was a significant increase in construction of new crude pipelines during the decades 1990 – 1999, 2000 – 2009, and now completed or planned for 2010 – 2019. Much of this investment came about because of the need to transport crude from shale plays. The increase in oil transported by pipeline, combined with the risk factors of age and construction material, has contributed to an increase in serious incidents over the past decade. Serious incidents rose from 107 in 2006 to 179 in 2015. However, the barrels spilled have declined. In 1996, PHMSA reported 160,188 barrels spilled. This declined to 137,052 barrels spilled in 2005. In spite of the increase in incidents over the past decade, barrels of oil spilled dropped to 102,424 in 2015.

Pipeline Incidents Have Risen, but Barrels Spilled Have Declined

Public concern over pipeline safety has increased. PHMSA recently received authority to issue industry-wide emergency orders. Previously, PHMSA was allowed to issue corrective orders to only a single operator at a time, but in June, Congress granted the agency broader emergency powers. The U.S. midstream industry opposed this. Pipeline safety came back into the limelight with the Colonial Pipeline failure in a remote area of Shelby County, Alabama, which spilled an estimated 6,000 barrels (250,000 gallons) of gasoline. The company responded quickly, sequestering the spilled gasoline in mine water retention ponds. It reported no threat to public health or safety. •

Source: PHMSA

Fundamentals

Development of U.S. Crude, Gasoline, and Diesel Stocks Global overproduction has continued to feed stockpiles. In the U.S., crude oil inventories in July and August remained stable, and it was not until September that five successive weekly drawdowns made a dent in inventories. Q3 began with crude inventories at 524.4 million barrels, and Q3 ended with inventories at 499.7 million barrels. It was the first time since January that non-SPR inventories had fallen below 500 million barrels. 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 SPR stockpile contains an additional 695.1 million barrels.

Crude Oil Stockpiles Decline at Last

U.S. gasoline inventories trended down significantly in Q3, falling from 238.9 million barrels at the beginning of July to 227.4 million barrels at the end of September. September, however, brought an increase in stockpiles, and the amount in inventory remains above its five-year average and range. Source: Energy Information Administration (EIA)

Gasoline Inventories Stabilizing Above 5-Year Average

Source: Energy Information Administration (EIA)

U.S. diesel inventories had been drawn down in the second quarter, but stockpiles grew in Q3, elevating inventories once again above the five-year average and range. The EIA reported diesel inventories at 148.9 million barrels for the week ended July 1, 2016. By the end of September, 11.8 million barrels had flown back into distillate inventories. •

Distillate Inventories Rise Again

Source: Energy Information Administration (EIA)

Fundamentals

Is U.S. Crude Production Ready for a Resurgence? In spite of relatively weak oil prices in Q3, the steep decline in U.S. crude production levelled off. This came as a surprise to many forecasting agencies that had expected a continued decline. At the start of the year, crude production was 9,219 kbpd. It fell to 9,008 kbpd at the end of the first quarter. It fell to 8,428 kbpd at the end of the second quarter. Yet the decline slowed in Q3, and at the end of the quarter, production had actually recovered slightly to 8,467 kbpd. The potential reduction in OPEC output, announced at the end of the quarter, is now raising speculation as to whether U.S. crude production has hit bottom and is ready to rebound. The third quarter brought a resurgence in the U.S. active rig count. The active rig count had fallen by over 60 percent 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. The declining rig count bottomed out at 404 active rigs at the end of May.

U.S. Crude Production: Was July 1 a Turning Point?

Source: Energy Information Administration (EIA)

U.S. Active Rig Count: Q3 Brings a Resurgence

Since May, oil rigs have slowly been tempted back into the field. As of the week ended July 1, 2016, there were 431 active rigs in the U.S. As of the week ended September 30, there were 522 active rigs. Thus, even though crude prices have remained well below the $50/b target price, 91 rigs have re-entered the field. Moreover, 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 issue of FUELSNews 360°. •

Source: Baker Hughes

Fundamentals

Retail Prices Remained Below Last Year’s Levels Retail gasoline and diesel prices showed a general increase over the quarter, yet prices on the whole remained below their previous year levels. The following figure shows the change in U.S. retail gasoline prices for the week ended October 3, 2016, relative to the week ended October 5, 2015. In all PADDs outside of PADD 1 (the East Coast), current prices remained below prices for the same week last year. On a national level, gasoline prices were 7.3 cents/gallon lower than they were a year ago. Prices in PADD 2 and PADD 4 were significantly lower: 17.9 cents/gallon and 23.5 cents/gallon lower, respectively. The Gulf Coast market has the country’s lowest gasoline prices on average, and they are currently 2.8 cents/gallon lower than they were last year. In the PADD 5 West Coast market, gasoline prices are 10.6 cents/gallon lower. In PADD 1, prices were 3.4 cents/gallon higher than they were one year ago, due to temporarily higher prices caused by the Colonial Pipeline outage.

Retail Gasoline Prices Remained Below 2015 Prices: Change in End of Week Prices for Oct 3, 2016 vs. Oct 5, 2015 ($/gal)

Source: Energy Information Administration (EIA)

At the national level, diesel retail prices were 10.3 cents/gallon lower for the week ended October 3, 2016, than they were for the week ended October 5 in 2015. The figure below shows the drop in diesel prices for the U.S. and for the five PADDs. Prices were significantly lower in the East Coast PADD 1 and the Midwest PADD 2, where prices were 12.6 cents/gallon and 13.3 cents/gallon lower, respectively. Gulf Coast PADD 3 prices were 7.3 cents/gallon lower. Rocky Mountain PADD 4 prices were 3.4 cents/gallon lower. In the West Coast PADD 5 market, diesel prices were 3.6 cents/gallon lower than they were one year ago. •

2016 Diesel Retail Prices Remained Below 2015 Prices: Change in End of Week Prices for Oct 3, 2016 vs. Oct 5, 2015 ($/gal)

Source: Energy Information Administration (EIA)

Regional Views PADD 1

East Coast PADD1A Northeast

BEAR

Evan’s Estimation I

Evan Smiles, Supply Manager See his bio, page 54

The third quarter of 2016 has come and gone with minimal supply issues in the Northeast. ULSD basis remained relatively steady in the negative territory, indicating that the region is long in product. Gasoline, both RBOB and CBOB, at New York Harbor did find some strength, however, as we approached the end of the RVP season. The primary reason for the elevated gas basis was the Colonial Pipeline leak in Alabama in mid-September. Many gasoline suppliers diverted product south to the affected areas. For the fourth quarter of 2016, I am predicting that distillate supplies will remain long, which will drive ULSD basis even lower, especially if this winter begins with the same moderate temperatures as last year. I am bearish on gasoline basis as well, and expect basis numbers to retreat back to the negative side now that the 2016 driving season is over. During the end of the fourth quarter, keep an eye on ULSD supplies in PADD 1A, as additional northeastern states no longer allow high-sulfur heating oil to be used within their boundaries.•

PADD 1A Wholesale vs. DOE Retail Diesel (dollars per gallon) “During the end of the

fourth quarter, keep an eye on ULSD supplies in PADD 1A, as additional northeastern states no longer allow high-sulfur heating oil to be used within their boundaries.“

Source: Energy Information Administration (EIA)

High Sulfur Heating Oil Record high levels of distillate fuel oil remain in the Northeast. The overall distillate supply for the third quarter in PADD 1 surpassed the January 2016 mark of 65.06 million barrels. For ultralow sulfur distillate supply, the third quarter of 2016 showed an increase of over 7% from the previous quarter and nearly a 17% increase from the same time last year. The larger distillate supply has pushed heating oil prices below the $1.50 mark and kept New York Harbor ULSD basis values in the negative territory for the entire quarter.

This distillate supply glut is not expected to slow down through the fourth quarter. Historically, as we enter into the last few months of the year, many refineries push refined products aggressively into the southeastern markets. This will increase distillate inventories even higher than third quarter levels. Wintertime can change distillate inventories, however. If the predictions are correct and a colder-than-normal winter occurs, distillate inventories could be slashed due to refinery struggles and a higher consumer demand. •

PADD 1 Diesel Stocks vs. NY Harbor Barge ULSD Price

Source: EIA, NYMEX

Regional Views

PADD 1

East Coast PADD1B & 1C

Central & Lower Atlantic

BULL

Chris’s Concepts I

Chris Carter, Supply Manager See his bio, page 54

I’m bullish for the Gulf Coast region for both diesel and gasoline during the fourth quarter of 2016. Current projections show the arbitrage between New York Harbor and GC beginning to open over the upcoming months. In addition, several GC refineries are going into turnaround (doing scheduled maintenance), which will also have an impact on prices. Chicago and Group 3 production could also put upward pressure on Gulf Coast prices. If northern refineries have any issues or delays during their turnaround season, or if the Midwest experiences a strong harvest season, Gulf Coast products will continue to trend upward. •

Gulf Coast—NY Harbor Spread, Q3 2016

Did You Know?

There are five PADD regions throughout the United States. PADD 1 extends from Florida all the way up the East Coast to Maine, and PADD 5 includes much of the West Coast (including Alaska and Hawaii). PADD 1 is split into three segments: PADD 1A (New England), PADD 1B (Mid-Atlantic) and PADD 1C (Lower Atlantic).

“ If northern refineries have

any issues or delays during their turnaround season, or if the Midwest experiences a strong harvest season, Gulf Coast products will continue to trend upward.“

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

Source: Energy Information Administration (EIA)

PADD 1

East Coast PADD1B & 1C

Regional Views

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

Central & Lower Atlantic continued

Source: Energy Information Administration (EIA)

Hurricane Hermine Impacts Florida and the Gulf Coast The National Weather Service began watching Invest 99L on August 18; 15 days later, Florida’s streak of 3,965 days without a hurricane (nearly 11 years) was broken. Invest 99L became Hurricane Hermine, which slowly made its way across the Atlantic and over Cuba. Hermine’s path seemed to shift daily as it moved closer to Florida. Originally, Hermine was projected to be a tropical storm, making landfall near Miami. As the storm moved westward, it faced wind shear and dry air that prevented the storm from developing a center, or “eye.” Eventually, the storm developed into the first hurricane to make landfall in Florida since 2005, just near St. Marks, Florida. After bringing heavy rain, winds, and storm surge to Florida, Hermine moved up the East Coast, bringing heavy rains to Georgia, South Carolina, and North Carolina before moving off the Northeast coast during Labor Day weekend.

Leading up to Hermine’s landfall, Florida saw an uptick in demand for both gas and diesel. Over the majority of the third quarter, Florida had ample fuel supply. Gulf refining capacity was high, and Florida inventories were high from a low-demand winter in Florida and a warmer northern winter. However, slight outages and supply shortages were experienced the week before Labor Day. Several vessels had to anchor offshore, waiting on Hermine to pass. Storm surge damage was limited in the Tampa Bay area. One week after the storm landed on shore, the supply had returned to normal in Florida. •

Regional Views

Colonial ULSD Line Space Values

Colonial Pipeline Line 2 Space Value

Colonial line space values during the third quarter of 2016 were significantly lower than the previous year. Line 2, the diesel line for Colonial, traded 2 cents/gal less than 2016. This is a result of New York Harbor trading -2/-2.5 cents below the NYMEX. Also, Gulf Coast basis felt the upward pressure from the challenges of Chicago and Group 3 ULSD basis. Gulf Coast saw an increase in demand for barrels to be shipped into the Magellan system this year compared to 2015, which played an impact on the difference between Gulf and Harbor. •

Source: Oil Price Information Administration (OPIS)

Colonial Line 1 Shutdown On a Friday afternoon, September 9, the Colonial pipeline, which supplies fuel from Texas all the way to Maryland, announced that it was shutting down its diesel and gasoline pipelines due to a leak on Line 1, its gasoline line. When suppliers returned to the office the next Monday morning, they realized the issue was much larger than they had realized. The leak in Shelby County, Alabama, was determined to be over 250,000 gallons, requiring a complete shutdown of Line 1. As normal inventory began to run thin in the days following the outage, prices in the Southeast jumped nearly 30 cents. Even after the pipeline was restarted, supply in the region did not return to comfortable levels for another week, since fuel moves at only five mph on average through a pipeline.

Source: Colonial Pipeline Company

Atlanta was disproportionately impacted by the event due to its summer 7.8 RVP requirement, a gasoline emissions standard meant to limit pollution within the city. Because the requirement did not expire until September 16, traditional unleaded gasoline could not be used within Atlanta limits. On September 13, the Governor of Georgia announced waivers for truck driver transportation hour restrictions to ensure the continued supply of fuel into Atlanta. Other areas that were hit hard by the outage include Nashville, Tennessee, and Selma, North Carolina, which both receive product from spur lines off the Colonial Pipeline. The outage was rectified quickly thanks to a bypass segment rapidly constructed and installed around the leak. Colonial completed the bypass and restarted shipping on September 21, nearly two weeks after the outage began. •

Regional Views

PADD 2 Midwest

“Expect tight supply and

relatively high regional prices for diesel in October and even through mid-November. Following that, into December, prices should subside with a drop in demand and production coming back online. “

BULL

Dan’s Dissertation I

As the fourth quarter begins, fuel consumers in the Midwest will see rising diesel values relative to NYMEX futures as refiners take production offline for seasonal maintenance. At the same time, diesel demand will rise given the fall agricultural harvest. Expect tight supply and relatively high regional prices for diesel in October and even through mid-November. Following that, into December, prices should subside with a drop in demand and production coming back online. For gasoline, refinery disruptions related to maintenance could cause short-term spikes, but the regional price trend will be downward relative to NYMEX futures. Diesel buyers in Chicago looking for low summer prices in the third quarter were rudely interrupted by a deluge of simultaneous supply issues in late July and early August. The disruptions kicked off with a lightning strike at Citgo’s 163,000 bpd Lemont, Illinois, refinery in late

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

July that completely halted production of ULSD for more than two weeks. Next, on July 29, the wastewater treatment plant at BP’s 430,000 bpd Whiting, Indiana, refinery experienced an upset. There was no leak or discharge of any hydrocarbons into Lake Michigan, but the refinery’s wastewater treatment plant malfunctioned. As a result, production was slowed, with industry analysts estimating the plant was running at 75 percent of normal capacity. Full operations at the refinery reportedly returned around August 22. Last but not least, on August 5, another regional refiner halted diesel sales at all Chicago-area terminals due to diesel product quality concerns. While one terminal was opened a couple days later, two other key terminals were not brought back online for nearly five days. Given the coinciding issues, ULSD prices strengthened during the outages resulting in some of the highest diesel prices in the country during that time. •

Chicago Diesel—Impact of Production Issues

Source: Platts & OPIS

Regional Views

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

Source: Energy Information Administration (EIA)

Startup of Massive Crude Oil Pipeline Delayed North Dakota oil producers expecting new markets for their crude supply at the end of this year face delays from Native American and environmentalist protests as well as a subsequent U.S. Justice Department intervention. Shippers on the Dakota Access Project—an enormous 1,100-mile, 30-inch diameter, $3.7 billion pipeline—were set to begin delivering 470,000 bpd of crude oil from North Dakota to Illinois later this year before a September injunction. The Dakota Access pipeline terminates in Patoka, Illinois, but offers connection to other pipelines that travel south to Sunoco Partner’s Nederland, Texas, crude facility and a variety of Gulf Coast refiners. Traders had already been buying crude oil for initial line fill shipments when the Justice Department asked the company to halt construction, shortly after a U.S. District Court said construction could resume. The full impact of the delay is unknown until both sides come to an agreement on the pipeline route and construction can resume.

Dakota Access Pipeline

This is tough news for North Dakota crude producers. Bakken crude delivery by rail to the coasts has suffered this year since the spread between U.S.priced crude oil and global crude oil has declined, making crude imports more competitive than the domestic Bakken alternative. The cheaper pipeline shipping economics on the Dakota line to the Midwest and Gulf Coast were expected to make domestic supply a more viable option. •

PADD 3 Gulf Coast

Regional Views

BEAR

Dan’s Dissertation I

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

Fourth quarter refined products prices in PADD 3 will be lower than the higher values seen in the third quarter. Unexpected refinery issues plagued the Gulf Coast over the summer, including unexpected downtime at Exxon’s 584,000 bpd plant in Baytown, Texas, LyondellBasell’s 275,000 bpd plant in Houston, Texas, and Shell’s 340,000 bpd plant in Deer Park, Texas. Valero also undertook planned maintenance at their 310,000 bpd Port Arthur, Texas, refinery that is expected to last through late October. When this production comes back online as expected during the fall, buyers in PADD 3 should notice lower gasoline and diesel prices in the fourth quarter relative to NYMEX futures. •

“When this production

comes back online as expected during the fall, buyers in PADD 3 should notice lower gasoline and diesel prices in the fourth quarter relative to NYMEX futures.“

PADD 3 Wholesale vs. DOE Retail Diesel

(dollars per gallon)

Source: Energy Information Administration (EIA)

Houston Ship Channel Closes on Oil Spill The Houston Ship Channel, home to the nation’s largest petrochemical complex and export ports, was closed on two separate incidents during the third quarter. In early September, a fire on an Aframax tanker and resulting spill of bunker fuel closed a critical 1-mile stretch of the Houston Ship Channel in both directions. The incident occurred near the intersection of the San Jacinto River and the Channel, impacting many major refined products terminals including Kinder Morgan, Enterprise, Magellan, LyondellBassell and Houston Refining. The Channel was closed for over one day due to spill remediation. A separate sulfur dioxide leak at Pasadena Refining’s 122,000-bpd plant in late July also closed the ship channel for several hours. The Houston Ship Channel allows tankers to sail to and from Texas City, Galveston, and Houston; the combined refining capacity dependent on the ship channel is 2.1 million bpd. When the Channel closes, inbound crude delays and outbound refined products stuck at terminals disrupt the fuel supply chain. An average day on the channel in 2013 saw 38 tankers, 22 freighters, one cruise ship, 345 tows, six public vessels, 297 ferries, 25 other transits and 75 ships in port. •

Regional Views

Magellan Opens Pipeline Connecting Central System to North Little Rock In August, Magellan Pipeline commemorated the completion of their $200 million project connecting their Midwest pipeline network to North Little Rock, Arkansas. The new expansion will bring up to 75,000 bpd of gasoline, diesel, and jet fuel to central Arkansas.

Ft. Smith to Little Rock Pipeline Project

To complete the project, Magellan used mostly existing infrastructure via a 160-mile line leased from Ozark Gas Transmission, though they ultimately laid about 50 miles of new pipeline: 12 miles in the Fort Smith, Arkansas, area and 38 miles going into North Little Rock. The new line will open up supply into North Little Rock from midcontinent refiners. Up to this point, the only pipeline supply into central Arkansas has been from Enterprise’s Teppco line, which originates in the Gulf Coast and is severely constrained and often unreliable. Access to refineries in Oklahoma and Kansas should provide greater flexibility and security of supply for area fuel buyers. Magellan has plans to expand their central system farther east. In August, they signed an agreement to connect this central Arkansas expansion to an existing pipeline that will transport fuel to the Memphis area. The work is estimated to take about a year and nine months. •

Source: Magellan

PADD 4

Rocky Mountain

“ I anticipate prices to show some strength in October and early November, but then drop off as winter comes along and demand starts to fall off.“

Regional Views

BEAR

Nate’s Notion I

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

Refined product prices, especially in Wyoming and Montana, performed the opposite of expectations last quarter as the majority of terminal markets outpaced the rest of the nation and moved higher during the summer. However, the major terminal markets in Salt Lake City and Denver stayed relatively connected to the rest of the nation as prices oscillated for most of the third quarter. I anticipate prices to show some strength in October and early November, but then drop off as winter comes along and demand starts to fall off. If we can get through turnaround season without any major hiccups in PADD 4, prices should follow their normal seasonal trajectory and head south for the winter. •

PADD 4 Wholesale vs. DOE Retail Diesel

(dollars per gallon)

Source: Energy Information Administration (EIA)

Colorado’s Anti-Fracking Ban Measures Fall Short Initiatives 75 and 78, two anti-fracking measures, failed to make the November ballot by failing to reach the minimum number of signatures required. Colorado’s Initiative 78 would have forced mandatory setbacks of 2,500 feet from inhabited structures and other public areas for oil and gas development in the state. This requirement would have disqualified roughly 95 percent of the producing surface area in the state and would have made an oil and gas rich area in Weld County, which currently has 17,000 wells on it, mostly off limits for further development. Initiative 75 would have given local governments the authority to prohibit, limit, or impose moratoriums on possible detrimental impacts (including oil and gas development). The oil industry in the state can breathe a sigh of relief for now. This includes refiners and other downstream entities in the region who’ve made significant capital investments over the last few years to increase capacity in lieu of strengthening diesel demand. However, the debate and battle over fracking in the state wages on. Environmental groups have already filed lawsuits regarding oil and gas development on public lands and more challenges and legal actions are likely on the horizon. •

Diesel Prices in Montana and Wyoming Higher Relative to National Average After dropping below the national average at the end of the second quarter, the average Rocky Mountain No. 2 Diesel Retail price is now 9 cents higher than the Weekly DOE National Average. The move comes on the heels of stronger Montana and Wyoming diesel prices. The price for diesel out of the Billings terminal is roughly 30 cents higher than the national average and Cheyenne diesel prices are 20 cents higher. Last year around the same time, prices were pretty much in line with the national average. We are hearing rumblings of a refinery in Billings having some unplanned issues, but those rumors have yet to be confirmed. The price discrepancy with the rest of the country suggests supply issues in Billings that have impacted the northern Rocky Mountain region. However, the price increases haven’t hit Denver, which has stayed relatively flat compared to the national index. •

PADD 5

West Coast, AK, HI

“All of these events

resulted in a lower production rate which in turn shot up the price of gasoline within the region. A number of other refineries throughout California also ran into issues or required maintenance that only added to the price increase brought on by concerns at Torrance.“

Regional Views

BEAR

Amy’s Analysis I

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

The start of the third quarter marked the beginning of PBF’s takeover of the Torrance refinery. PBF, the first new owner of the refinery since 1966, is new to the California market and finally completed the deal with Exxon once the refinery returned to full capacity after 10 months. Following the return of the refinery, it was anticipated that gas prices would be reduced within the state; however, that was not the case as the plant ran into multiple issues within the first several months. Within the first month, PBF ran into flaring issues, followed by boiler maintenance in August and insufficient crude supply in September. All of these events resulted in a lower production rate which in turn shot up the price of gasoline within the region. A number of other refineries throughout California also ran into issues or required maintenance that only added to the price increase brought on by concerns at Torrance. This caused companies such as Chevron, Tesoro, and Conoco Phillips to buy gasoline heavily in the quarter. Going into the last quarter, I expect issues to be resolved and refineries to start producing more, which should result in a steady decrease in gas prices toward the end of the year.•

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

Source: Energy Information Administration (EIA)

The California Climate Change Laws In early September, California Governor Jerry Brown signed the climate and clean energy bill into law. The bill, Senate Bill 32, further addressed efforts to reduce greenhouse gas pollution and extends the Global Warming Solutions Act of 2006 to 2030. The Global Warming Solutions Act of 2006 required California to reduce greenhouse gas emissions to 1990 levels by 2020, and the new bill aims to further lower emissions to 40% below 1990 levels by 2030. This initiative further solidifies California as one of the nation’s leaders in fighting to protect the environment. The state has already been increasing solar power generation, encouraging drivers to buy electric vehicles with subsidies, and urging developers to create more communities connected to mass transit. All of these initiatives have allowed California to significantly reduce its emission levels and the state is on track to meet emission levels set for 2020.

31 29

Despite all of the positive effects of the environmental bills and acts, there are a number of concerns that it will have an adverse effect on oil and gas companies. Last year, in an effort to reduce greenhouse gas emissions, California Legislature was looking to pass a bill (Senate Bill 350) that would cut oil use by 50% by 2030 within the state. As expected, oil and gas companies lobbied and fought hard against the bill and the bill was eventually dropped. It has been reported that the oil industry has spent $38 million lobbying in California since the beginning of last year. They have argued the passing of some of these bills will cut oil and gas jobs and cause shutdowns and closures. These were also arguments against Senate Bill 32, but despite strong opposition and lobbying against the bill, it passed. These are signs that California legislators are putting more focus on the environment and are looking to restrict the way oil and gas companies operate in order to address pollution and climate change issues. As a result, California may eventually move to an economy less dependent on oil and may look to renewable fuels as a larger source of revenue. •

Regional Views

Canada

BULL

Canadian Economy Hit Hard by Wildfires in Second Quarter, Q3 Looks Much Brighter The Canadian economy fell by an annualized rate of 1.6% in the second quarter, due in large part to the wildfires that destroyed parts of Fort McMurray and caused oil sands production to drop nearly 800,000 barrels per day in May. Canada’s GDP grew at a 2.5% clip in the first quarter, marking the biggest quarterly decline since the financial crisis in 2009. The economy has been struggling over the past year as declines in crude oil prices have hit oil producers and brought down rig counts significantly. The evacuation of Fort McMurray and a shutdown of several oil sands operations was a particularly significant blow to the energy sector. In fact, energy

product exports fell 7.5%, with crude and bitumen exports dropping 9.6% and refined product exports falling a staggering 19.6%. However, the economy started to show strength in June, and Canada is positioned well for a stronger-than-expected recovery in the third quarter. The Bank of Canada estimates growth gaining steam in the July – September quarter to an annual pace of 3.5% on the heels of increased oil activity and as rebuilding efforts at Fort McMurray begin. •

Enbridge Buys Natural Gas Pipeline Company Spectra Energy for $28 Billion Enbridge has found out firsthand how difficult it is to get a new pipeline approved and built in North America. The company has spent billions of dollars trying to get approval for its stalled Northern Gateway project that would create a West Coast outlet for oil sands producers. The oil and gas industry in Canada is facing significant environmental headwinds as climate change politics and tougher regulatory requirements are making it harder for oil and gas producers to make the necessary investments for future growth opportunities. In turn, as a company that makes a profit moving crude oil from Point A to Point B, Enbridge has decided to diversify its portfolio by purchasing Spectra Energy, a major player in the U.S. natural gas space with over $5 billion in revenue. The move makes the combined company the largest energy infrastructure company in North America. Earlier this year, TransCanada Corp. agreed to purchase Columbia Pipeline Group for $10.2 billion after being rejected on the Keystone XL pipeline. The two companies have found it difficult over the last few years to build new pipelines in North America, so both have gone the acquisition route outside of Canada to gain market share in a sector that appears to be on the path to further consolidation. •

Alternative Fuels

Renewable Fuels “Many smaller producers

cannot operate economically without the credit and may be forced to slow or shut down production facilities if the credit is not extended, limiting domestic supply to some extent.“

BULL

Sara’s Sentiments I

Look for the fourth quarter of 2016 to continue to provide economically-advantaged biodiesel blending opportunities across the nation. Fuel markets near barged terminals are well supplied, with multiple market participants offering waterborne delivered gallons at significant discounts to the nearby heating oil contract. Ample supply is expected to continue throughout the quarter as producers and blenders alike push product sales while the Blender’s Tax Credit (BTC) of $1.00 per gallon provided by the federal government is in place. The northern and inland markets are also finding biodiesel offers to be plentiful and well-discounted to ULSD No. 2 and NYMEX heating oil. Demand for biodiesel blending in these regions is expected to decrease as colder weather arrives, with discounts remaining at current levels or even weakening.

The federal government has not yet instated a tax credit for 2017. This is causing uncertain production economics. Many smaller producers cannot operate economically without the credit and may be forced to slow or shut down production facilities if the credit is not extended, limiting domestic supply to some extent. The outlook for reinstatement of the credit does not appear to be as certain as it has been in the past and there is a possibility that the credit program will be changed to a producer’s credit. If this were to occur, domestic production would be supported relative to the influx of imports we have experienced this year. Look for the value of RINs to continue to meander higher throughout the fourth quarter. There seems to be significant refinery buyer support around 85 cents with resistance at $1.05. The ceiling of this range is expected to be exceeded in 2017. •

2016 Bio RINs Prices

ABCs of Renewable Fuels EISA GHG RFS LCFS RVO RIN K Code D Code ASTM D975 ASTM D6751 REG AB32 CARB CI gCO2/MJ CNG LNG RNG ADF NTDE VMT OEM RD Cap and Trade ERUs QAP VB CCA MRR BFSM

Sara Bonario, Director of Supply, West See her bio, page 54

Energy Independence & Security Act Green House Gas Renewable Fuels Standard Low Carbon Fuel Standard Renewable Volume Obligation Renewable Identification Number Separated or attached RIN Renewable type RIN Diesel specification Biodiesel specification Renewable Energy Group California mandate to reduce GHG California Air Resource Board Carbon Intensity Grams of Carbon Dioxide by Mega Joule Compressed Natural Gas Liquified Natural Gas Renewable Natural Gas Alternative Diesel Fuel New Technology Diesel Engine Vehicle Miles Traveled Original Equipment Manufacturer Renewable Diesel California statewide limit on GHG emissions Emission Reduction Units Quality Assurance Program Verification Body California Carbon Allowance GHG Emissions Mandatory Reporting Rule Biofuel Supply Module

Source: Oil Price Information Administration (OPIS)

Alternative Fuels

California Clean Air Policies and Politics Then California Governor Arnold Schwarzenegger signed into law the Global Warming Solutions Act of 2006 on September 27, 2006. This piece of legislation is known as AB-32 and mandated the reduction of greenhouse gas (GHG) emissions to pre-1990 levels by 2020. However, no strategies or methods for meeting the mandate were presented. The California Air Resource Board (CARB) was appointed as the agency to effect change. The Low Carbon Fuel Standard (LCFS), Cap-and-Trade and Alternative Diesel Fuel Regulations (ADF) are all programs that evolved from this legislation. CARB officially launched the Cap-and-Trade Program in 2012, with mandatory compliance obligations beginning in 2013. The program established an annual cap on California GHG emissions. Parties obligated under the program are required to submit an allowance to CARB for each equivalent metric ton of CO2 that they emit. The number of allowances available each year is equal to the number of metric tons of emissions that is allowed under that year’s cap. Covered entities who do not receive allowances from the state or whose emissions exceed the allowances they are issued must buy allowances in the market. Entities without compliance obligations may also participate in the program by voluntarily reducing their own emissions or by trading allowances as a liquidity provider.

LCFS Carbon Credit ($/MT)

Now

Source: Oil Price Information Administration (OPIS)

California Governor Jerry Brown recently signed legislation that sets an even more ambitious target for what were already the toughest greenhouse gas reduction goals in the nation. On Tuesday, August 23, 2016, the California State Assembly passed SB-32, which extends the existing Cap-and-Trade Program to 2030 while requiring the state to reduce greenhouse gas emissions to 40 percent below 1990 levels. This came as a relief to some industry participants who worried LCFS was in danger of being sacrificed as a political bargaining chip. There is a lawsuit currently before the U.S. appeals court in California that challenges the validity of the Cap-and-Trade Program. The plaintiff contends that the program is a tax and not a regulatory fee. A tax increase requires a two-thirds majority from the state legislature, however, Cap-and-Trade was originally passed by a simple majority. Questions asked by the court in April have led some to believe that the court is considering siding with the plaintiff, thus invalidating the program and rendering existing California greenhouse gas allowances valueless. Participants required to purchase carbon allowances and GHG credits have responded to uncertainty in these programs by staying on the sidelines in the usually active carbon markets, thus causing prices to fall. Traders quickly responded to the passage of SB-32, a second measure AB-197 and the survival of an intact LCFS program. •

Alternative Fuels

Natural Gas “ Dwindling week over week,

storage inventory injections suggest that the surplus carryover from winter 2015 is dissipating and is currently being helped along by historic demand for gas-fired power, further normalizing the supply-demand balance.“

BULL

Martin’s Measure I

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

Q4 Outlook The latter third of Q3 saw natural gas settle at its highest price since 2015 on two separate occasions. Dwindling week over week, storage inventory injections suggest that the surplus carryover from winter 2015 is dissipating and is currently being helped along by historic demand for gas-fired power, further normalizing the supply-demand balance. I expect prices to rise gradually as we approach calendar year 2017. •

Cash Prices During the months of July and August 2016, typically the warmest time of the year, we saw cash prices trade at a discount to the prompt month. The cash discount averaged approximately 3 cents under in July and nearly 10 cents under through August. In an unusual twist, this trend reversed in September, such that cash prices were as high as 10 cents higher than the prompt month and averaged 5 cents over the entire month. The trend of EIA storage injections coming in lower than predicted, coupled with anticipated peak storage topping out just over 3,900 bcf (compared to 4,000 bcf last year), provided the catalyst for the September cash premium. •

Forward Prices Prompt month opened Q3 at $2.987, jumping 6 cents from the close of the Q2 and over 70 cents higher than Q2 averages. Prices have now stabilized around $3.00 as a mixture of uncertainty surrounding inventory levels and looming cold weather approaches. Calendar year 2017 has seen its fair share of volatility in a range-bound area between $3.00 and $3.25 as seen in the graph below. The ability of producers to tap DUCs (more on this to follow) has made the market leery of pushing 2017 futures too much higher, and the stalemate continues. Calendar years 2018 through 2020 hover between $2.90 and $3.05, an area that has sparked little interest and trading volume. •

NYMEX Natural Gas—Calendar Year Strips Weekly Settle

Source: New York Mercantile Exchange

Alternative Fuels

Natural Gas

Natural Gas Supply/Demand Fundamentals

Demand Mid-September saw natural gas prices rise to their highest settlement since opening the third quarter. This appears to be from a somewhat balanced attack. Higher-than-average nationwide heat has caused record gas-fired power to run air conditioners more than normal through the end of September, a trend supported by the 90-day temperature departure forecast chart here. In addition, whenever we see a dip in gas prices toward the mid $2.00s, power producers are incentivized to favor natural gas generation over coal. In the short term, this trend seems to continue as the EIA expects natural gas usage by the electrical power sector to increase nearly 5.5% by the end of 2016. Additionally, the industrial sector is forecasted to see 2.3% growth by year’s end, attributed mostly to new production in fertilizer and chemical projects.•

Supply

Source: Intellicast

Drilled but Uncompleted Wells (DUCs) In September, the EIA began publishing what may become a new barometer for natural gas market upstream activity. A new supplement to the Drilling Productivity Report will estimate drilled but uncompleted wells (DUCs) in the three major natural gas producing regions of Haynesville, Marcellus, and Utica through the previous month. DUCs are new well heads that have completed the drilling process, but have not received the proper finishing treatments (casing, cementing, perforating, etc.) necessary to start producing natural gas. Reducing the number of DUCs is a quick way to increase production in the face of increasing prices, as the majority of work and infrastructure is already completed. Natural Gas DUCs have been declining since late 2013, and saw another reduction at the end of Q3, with another 21 wells being completed.•

DUCs in Crude Oil and Natural Gas Regions

U.S. Natural Gas Consumption

Source: EIA Short-Term Energy Outlook, September 2016

Storage After beginning Q2 at record levels of nearly 2,480 bcf, working gas in underground storage settled Q3 at 3,499 bcf. Despite gaining nearly 1,000 bcf over the quarter, injections came in at a slower-than-normal rate. Some of this is to be expected with the above average beginning inventory; while injections are nearly half of what they were last year, current storage inventories surpassed last year by 5.6% and the five-year average by 9.3%. As previously mentioned, the steady decline in year over year storage surplus has provided support to the prompt market—a trend we expect to continue until market fundamentals shift bearish, or winter greets us with milder-than-expected temperatures.•

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

Source: Energy Information Administration (EIA) Source: Energy Information Administration (EIA)

Alternative Fuels

Power “ The summer heat,

combined with the rise in natural gas prices, brought back some volatility to cash power that had been missing in Q1 and Q2.“

BEAR

Keith’s Conjecture I

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

Power Prices

Cash

As the calendar changed to summer, the trends in cash power prices seen in the first two quarters of 2016 changed as well. Temperatures rose to the mid-to-upper 80s in early July, a level that held until mid-September, with the occasional spike into the 90s. The summer heat, combined with the rise in natural gas prices, brought back some volatility to cash power that had been missing in Q1 and Q2. Through PJM West Hub, peak prices generally remained near $40/MWh throughout Q3; sporadic temperature spikes to the 90s did drive a handful of peak clearing prices north of $50/MWh, topping out at the $60/MWh mark in late July. The punch line is that in PJM, the largest ISO/RTO in the country, demand-side management held power prices in check with few “spike” days; this theme held true for the rest of the country as well. •

Note: Colored areas denote Regional Transmission Organizations (RTO) Independent System Operators (ISO)

Source: Energy Information Administration (EIA) based on Ventyx Energy Velocity Suite

Calendar Year 2017 Wholesale Peak Power Prices

Forward/Term Outlook Forward power curves that showed a gradual increase throughout Q2 turned in the opposite direction in Q3, as calendar year 2017 forward prices in the Midwest, West and ERCOT (Texas) generally showed a gradual decrease throughout Q3. Similarly, the NYISO Zone J (New York City) forward curve, which showed a steeper increase in Q2 than the rest of the country, showed a steeper decrease in Q3 than the rest of the country. During the month of July alone, the 2017 forward curve for Zone J dropped by nearly 15 percent, then maintained that position through the end of Q3. •

Source: NYMEX

Alternative Fuels

Power Supply

Power Fundamentals

California Independent System Operator (CAISO)—Natural Gas and Renewables Generation In California, various sources of electricity supply are used, particularly during the summer, in order to meet demand that usually peaks in late afternoon. While hydroelectric and nuclear generators typically generate a constant output, CAISO must rely on electricity generated by renewables and natural gas (thermal) to ensure that supply meets demand.

Hourly Average CAISO Electricity Production (Summer 2016)

Thermal generation accounts for the largest portion of power supply in CAISO and also accounts for the widest range of generation. Its load profile fluctuates from a low of 2.6 GW generated on a June morning to as high as 25.6 GW on a peak evening in July. Similarly, renewables account for a significant portion of summer power supply and can exhibit a wide range of production, particularly solar generation. This is not surprising considering such generators are limited to the daylight hours, but can contribute over 7 GW to the grid in a given peak hour. Fortunately, the peak time for renewable power generation matches the peak time for electricity demand, which helps maintain grid stability. Fluctuation in electricity demand in California, which spans a large geographical area and has a wide array of landscape and terrain, should not be surprising. Thus, it is necessary to have the presence of “peaking” power generation, which can be cycled on a day-to-day basis and available during peak demand hours to maintain grid stability. •

2016 U.S. Renewable Electricity Generation Higher than Average

Source: Energy Information Administration (EIA)

U.S. Renewable Electricity Generation (Jan 2010 – June 2016)

Despite the decrease in capacity additions for renewables in 2016 as compared to recent years, renewable electricity generation in 2016 has been higher than 2015 and remained above five-year averages from 2010 – 2014. While it is true that renewable capacity additions have slowed in 2016, the end of a West Coast drought has enabled hydroelectric generation to begin returning to historical levels, while non-hydroelectric renewable generation has grown more than in recent years. •

Source: Energy Information Administration (EIA)

Power Demand—the U.S. and Beyond

Long-Term Increased Sales in Air Conditioning Units to Drive Demand for Inefficient Generation, Thermal Energy Storage

Between now and 2050, an estimated 1.6 billion new air conditioners will be installed worldwide. Since many of these new air conditioners will be installed in parts of the world that do not currently have air conditioning, demand on the electric grid in some areas will grow more rapidly than in the past. Because these units are projected to use most of their electricity during peak hours, the use of expensive and inefficient peaking generators could be necessary in order to meet increased demand, driving prices upward. A possible solution to this problem for the end user is to invest in thermal energy storage. During nighttime hours, when the utility is in a state of excess capacity, cooling can be created and stored for use the next day. Cooling is created by thermal energy in the form of cold water or ice. Ice can be stored for use the next day, when it can act as the cooling agent for the occupants of a facility. This can combat potential stress on the grid, usage of inefficient generators, and, ultimately, the end user’s problem of excessive prices by enabling a customer to cool their residence or place of business for an extended period of time using the cool energy that was stored the previous night. •

Viewpoints Seven Shales Instead of Seven Sisters

By Dr. Nancy Yamaguchi Our title “The Seven Shales” refers to the seven major shale plays in the United States. The author coined this name to evoke a memory of “The Seven Sisters,” the large multinational oil companies who historically dominated the global market. In a reversal that was almost entirely unforeseen, the shale boom transformed the U.S. into the world’s largest oil producer. This boom reversed the decades-long decline in crude production and helped create the global oversupply that caused oil prices to collapse. U.S. production has begun to decline again, as hundreds of oil rigs have idled. At the time of this writing, Saudi Arabia has once again overtaken the U.S. to become the global leader in crude production. The U.S. rigs that remain, however, are much more efficient, and the gradual rise in prices has tempted others to re-enter the field. Will this halt the decline in U.S. crude production? Many forecasts of global crude oil supply and demand assume that balance will be reached largely because of declines in U.S. production. What will happen if the U.S. production decline comes to an early halt, or even reverses?

The Seven Shales, part two

Seven Key Tight Oil and Shale Gas Regions BAKKEN

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

EAGLE FORD

Viewpoints

Permian Permian Crude Production Growth The Permian Basin is the most important and prolific oil basin in the United States. The Greater Permian Basin contains three main basins: the Midland Basin, the Delaware Basin, and the Marfa Basin. The majority of the Permian Basin underlies the western part of Texas, with a portion extending into New Mexico. Historically, most of the crude produced came from the more permeable portions of the formations, but the advances in horizontal fracturing and horizontal drilling opened up vast areas of less permeable formations. Production has risen dramatically. According to the Energy Information Administration (EIA), Permian Basin oil production was 850 kbpd in 2007, and it rose to 1,350 kbpd in 2013, an increase of 60 percent. The main contributors have been six low-permeability formations: Spraberry, Wolfcamp, Bone Spring, Glorieta, Yeso and Delaware. Spraberry is part of the Midland Basin in Texas, while Bone Spring is part of the Delaware Basin that extends into New Mexico. Abo-Yeso and Glorieta-Yeso also extend into New Mexico.

Figure 1 shows the crude production trend according to the EIA. Texas output (statewide, not just the Permian Basin) of 2,554 kbpd in 1981 slid to 1,073 kbpd in 2004 before levelling-off and preparing to take off once again. Production more than tripled to 3,457 kbpd in 2015. New Mexico’s output was 196 kbpd in 1981, and although the increase in output was not as spectacular as that seen in Texas, production rose significantly from 162 kbpd in 2007 to 410 kbpd in 2015.

Looking more closely at the monthly production data in Texas shows that production peaked at 3,599 kbpd in May 2015. It slowly declined to 3,348 kbpd in December 2015, and dipped to 3,295 in March 2016. However, just as the trend in active rigs has varied, the production trend has not plummeted in a straight line. This suggests that some Texan production is relatively low-cost, though it remains to be seen how much production can be sustained in coming months if prices do not remain above $45/b – $48/b. Most forecasts anticipate higher prices by the fourth quarter, but there is a wide range of opinion on the matter.

Figure 1: Permian States New Mexico and Texas Crude Production, kbpd

Figure 2: Texas Field Production of Crude Oil, Monthly kbpd, January 2013 – March 2016

Viewpoints

Loss of Active Rigs, and Gain in Drilling Productivity in Permian

Demand for Key Petroleum Fuels in the Permian States

Figure 3 shows the number of drilling rigs at work in the Permian Basin along with the average oil production per rig. The rig count has shown considerable variability, growing to 287 in 2008, falling to 92 in 2009, jumping to 517 in 2012, falling to 446 in 2013, then rising again to a peak of 565 in 2014. Global crude prices remained low throughout 2014 and 2015, however, and the rig count dropped sharply to 276 rigs in 2015 and 145 rigs in the first half of 2016. Production per rig has soared. In 2007, average production per rig was 61 barrels per day. This rose to 212 bpd in 2014. As additional rigs closed, production per rig rose to 539 bpd during the first three quarters of 2016.

The two Figures 4 and 5 present consumption of key petroleum fuels in Texas and New Mexico, according to the EIA. Gasoline and diesel account for around three-quarters of New Mexico’s demand for key fuels, in a market size of 132 kbpd in 2013. The Texas market is much larger, with demand for 3,055 kbpd of key fuels in 2013. Texas’s pattern of demand includes a large share of liquefied petroleum gas (LPG) as well. In both states, fuel consumption showed noticeable growth during the shale boom years, consistent with a greater level of economic development and activity. For the U.S. as a whole, demand was essentially flat between 2003 and 2013. In contrast, New Mexico’s demand grew at 1.49% per year that decade, while Texan demand grew at 1.98% per year.

Figure 3: Permian Rigs and Production per Rig

Figure 4: Texas Demand for Key Fuels, kbpd

Viewpoints

Figure 5: New Mexico Demand for Key Fuels, kbpd According to the EIA, Eagle Ford oil production was 54.6 kbpd in 2007, and skyrocketed to an incredible 1,708 kbpd in 2015—averaging to a rate of growth of 52.1% per year. Natural gas production rose as well, expanding at an average rate of 20.2% per year during that period, growing from 1,645.3 MMcf/d in 2007 to 7,189.9 MMcf/d in 2015. Figure 6 shows the rapid increase in output. By the first half of 2016, however, production was beginning to fall. Gas production fell to 6,732 MMcf/d, and oil production fell to 1,351.6 kbpd.

Figure 6: Eagle Ford Shale Oil and Gas Production, 2007 – 2016*

Eagle Ford While the Permian Basin is widely considered the most important oil basin in the United States, the Texas Eagle Ford name is closely associated with shale development. Among the Seven Shales, Eagle Ford is the second-largest oil producer (after Permian) and the second-largest natural gas producer (after Marcellus). The play dates to the Cretaceous age, a sedimentary basin stretching across the Texas-Mexico border and extending east by northeast across southern Texas. The southern margin of the play is the deepest, around 12,000 – 14,000 feet deep, and it is dry gas prone. The middle band is wet gas and condensate prone, approximately 8,000 – 12,000 feet deep. The northern band is oil prone, and it is the shallowest, at around 4,000 – 8,000 feet deep. Farther to the north, there are outcroppings of Austin Chalk visible, helping to identify the top layer and the extent of the structure. The shale has a high carbonate content. The higher carbonate-to-clay ratio makes the Eagle Ford more brittle and easier to stimulate through hydrofracking.

Eagle Ford Crude Production Growth The Eagle Ford formation reportedly was first targeted by Lewis Energy in 2002, but in 2008, Petrohawk Energy was credited as being the first company to drill a productive oil and gas well. The well was in LaSalle County, which is southwest of San Antonio. This remains a highly productive area. By 2010, the Eagle Ford was one of the most active drilling sites in the country.

Loss of Active Rigs, and Gain in Drilling Productivity in Eagle Ford Figure 7 shows the number of drilling rigs at work in the Eagle Ford Shale, along with the average oil production per rig. In 2007, there were 57 active rigs in the area, rising to 64 rigs in 2008, then falling to 41 in 2009. By 2010, however, drilling activity began to take off, and the rig count reached a peak of 264 in 2012. By 2015, however, the low prices began to take a toll, and the rig count fell to 127 in 2015 and 56 during the first half of 2016. Production per rig has grown steadily. In 2007, average production per rig was 35 barrels per day. This rose to 569 bpd in 2014. As additional rigs closed, production per rig rose to 715 bpd in 2015 and 938 bpd during the first half of 2016.

Figure 7: Eagle Ford Rigs and Production per Rig

Viewpoints As noted, Eagle Ford is the second-largest oil producer among the Seven Shales areas, following Permian, and the second-largest natural gas producer, following Marcellus. Eagle Ford is also one of the most productive in terms of drilling efficiency, producing the highest volume of oil per active drilling rig during the first half of 2016. The success of early hydraulic fracturing projects in the Eagle Ford Shale play transformed the area into one of the hottest drilling areas in the country. It is said that the Eagle Ford Shale is the single largest economic development in the state of Texas, and reportedly it is the largest oil and gas development in the world when based upon the amount of capital invested. Oil production in 2015 was an incredible 28.68 times as large as it was in 2007. Natural gas production rose by a factor of 4.37 during those same years.

Figure 8: Seven Shales Regions: Crude Production per Rig, First Half 2016

Marcellus and Utica Natural Gas and Crude Production Growth

The Seven Shales: Marcellus and Utica Marcellus and Utica are unique among the Seven Shales because of their proximity to one another and their natural gas orientation. Their location near denselypopulated eastern states helps create a market for their gas output. The full extent of the reserves is not yet known, particularly since the Utica has not been extensively developed. The Marcellus has been highly prolific, and it is shallower, so for the time being it has overshadowed the Utica.

According to the EIA, Marcellus oil production was 10.1 kbpd in 2007, and it more than quadrupled to 45.5 kbpd in 2015. Oil production declined to 37 kbpd in the third quarter of 2016. Utica oil production was 9 kbpd in 2007. It grew sevenfold to 79 kbpd in late 2015, and the EIA estimates that production tapered down to 69 kbpd in the first three quarters of 2016. This is a notable amount of oil, but for the sake of comparison, oil output from the Permian area was estimated at 2,026 kbpd in the first half of 2016. Marcellus and Utica oil production accounted for approximately 2% of U.S. shale oil output last year. Figure 9 shows the crude production trend according to the EIA.

Figure 9: Marcellus and Utica Oil Production, kbpd

The Marcellus shale play extends in a northeasterly direction from the juncture of Ohio, West Virginia, and Pennsylvania, across Pennsylvania and into New York. The Utica formation underlies the Marcellus formation, and it is larger. At the western margin, it starts in the middle of Ohio; at the southwestern edge, it underlies most of West Virginia and crosses into Virginia. It underlies most of Pennsylvania, the southwest part of New York and part of Lake Ontario. The Marcellus Formation is Devonian Age, between 359 and 416 million years ago. The Utica Shale is Ordovician Age, between 443 and 488 million years ago.

The next chart, Figure 10, shows Marcellus and Utica natural gas production. In 2007, Marcellus gas production was 1,221.6 MMcf/d. Production in 2015 rose to 13.5 times the 2007 level, 16,569.5 MMcf/d. The EIA estimates that production continued to increase during the first half of 2016, to 18,222 MMcf/d.

Viewpoints Utica gas production was 156.1 MMcf/d in 2007. This rose by a factor of 17 by 2015, when it reached 2,670.6 MMcf/d. The EIA estimates that Utica gas production continued to rise in 2016, averaging 3,654.1 MMcf/d. These two shale plays accounted for 42% of the Seven Shales natural gas production in 2015, whereas they accounted for only 2% of the oil output.

Figure 10: Marcellus and Utica Natural Gas Production, Mcf/d

Loss of Active Rigs, and Gain in Drilling Productivity in Marcellus and Utica Figure 11 shows the number of drilling rigs at work in the Marcellus area, along with the average oil production and natural gas production per rig. The rig count grew from 48 in 2007 to a peak of 138 in 2011. It has declined steadily since then, falling to 60 in 2015, and estimated at 30 rigs after the first three quarters of 2016. Production per rig has risen significantly. In 2007, average oil production per rig was seven barrels of oil per day. This rose to 28 bpd of oil in 2014, and an estimated 69 bpd of oil in the third quarter of 2016.

Figure 12 shows the number of active rigs in the Utica play, along with average oil and natural gas production per rig. The rig count grew from eight in 2007 to a peak of 46 in 2014. It fell to 25 in 2015, and it was estimated at 14 rigs in the third quarter of 2016. Oil production per rig rose from 20 b/d in 2007 â&#x20AC;&#x201C; 2012 to 207 b/d in 2015, and it was estimated at 277 b/d in the first half of 2016.

Marcellus natural gas output per rig rose from 499 Mcf/d in 2007 to 8,786 Mcf/d in 2015, and it is estimated to have risen to 10,406 Mcf/d in the first half of 2016.

Natural gas production per rig rose from 170 Mcf/d in 2007 to 5,581 Mcf/d in 2015. It is estimated to have risen to 6,485 Mcf/d during the first half of 2016.

Figure 11: Marcellus Rig Count and Oil and Gas Production per Rig

Figure 12: Utica Active Rigs and Oil and Gas Production per Rig

ÂŠ 2016 Mansfield Energy Corp.

Viewpoints

Conclusion: The Seven Shales Revivify the U.S. Upstream Sector The advances in hydrofracking and horizontal drilling over the past decade have allowed the Seven Shales to achieve unforeseen levels of oil and gas production. This output has revivified the U.S. upstream industry and transformed the U.S. into the world’s largest oil producer. U.S. crude production was on a steady downhill slide until it bottomed out at 5.0 MMbpd in 2008. The shale boom reversed this, causing production to rise to 9.4 MMbpd in 2015. Low prices since late 2014 caused production to slide once again. For the first half of 2016, it is estimated that U.S. crude production will average just under 9.0 MMbpd. Because the trend is sloping down, the most recent weekly estimates for June 2016 show production at 8.7 MMbpd.

Changes in Electricity Generation by Fuel Type The shale boom has added enormously to U.S. oil and natural gas production, but the end uses of oil are very different from the end uses of natural gas. Oil is easily transportable, and the new supply mainly supplanted foreign crude oil imports. Natural gas is more difficult to store and transport, and exports in the form of LNG have only recently commenced. Much of the new gas output has been used in power generation. The new natural gas output has made a huge impact on the electric power fuel mix, as shown in Figure 13, according to data published by the EIA. This figure uses 2004 as the starting year and then tracks how the fuel mix changed over the next 10 years. The use of oil fell sharply, and by 2014, it was one quarter of what it had been in 2004. The use of coal also fell significantly, falling to 80% of what it had been in 2004. Nuclear generation was roughly stable. But by 2014, the use of natural gas and other gas rose to 1.57 times its 2004 level. The use of other sources including renewables (solar, wind, hydro, geothermal and biomass) also rose significantly, reaching 4.22 times its 2004 level. In 2004, 50% of U.S. net electricity generation was powered by coal. Petroleum accounted for 3% of the electricity generated. In 2014, coal’s share fell to 39%, and oil’s share fell to a mere 1%. In contrast, the share of natural gas rose from 18% of the power mix in 2004 to 28% in 2014.

Figure 13: Relative Change in U.S. Electricity Generated by Fuel Type, 2004 = 1.00

Most international agencies forecast that global supply and demand will move more into balance toward the end of 2016. Crude prices appear to be in the process of strengthening, and are expected to reach the $50/b level on a consistent basis in the coming months. It is likely that this will slow the decline in U.S. production. The U.S. active rig count may have hit bottom at 404 rigs in May 2016. Recent weeks have shown several reactivations, and the Baker Hughes rotary rig count stood at 424 as of June 17, 2016. One year prior, there had been 857 active rigs; around one-half, 433 rigs, closed over the past year. Yet the loss of rigs initially had a lessened impact on actual production, because of phenomenal increases in drilling efficiency. In June 2015, the average oil production per rig was 404 bpd. As of June 2016, it is estimated to have more than doubled to 859 bpd. As prices slowly grind back to the $50/b mark, an occasional rig is being tempted back into production. Naturally there is a large variance in the production economics from well to well, from shale play to shale play, and from company to company. But the fact that the rig count now seems to be bottoming out suggests that the decline in U.S. production may slow down. The producing companies in the Seven Shales areas certainly were hurt by the collapse of oil prices, but they did not stand still over the past year and a half. Their drilling efficiency has risen dramatically, and the reduction in global oversupply will undoubtedly allow many of them to reenter the field. • Editor’s Note: This is the second installment of a two-part article. Look for the first part in the FUELSNews 360° Second Quarter issue. Author’s Note: This article has been updated and revised to consolidate individual chapters that appeared in the daily FUELSNews 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.

Nancy Yamaguchi, Ph.D. Contributing Editor 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 that influence North American fuel markets. Dr. Yamaguchi has over 20 years of industry experience, and has spoken at numerous industry conferences and events nationwide.

Viewpoints

Transportation and Logistics

By Dan Kemeny

The National Highway Traffic Safety Administration (NHTSA) and Federal Motor Carrier Safety Administration (FMCSA) recently proposed a federal mandate for speed limiters on heavy-duty trucks. The proposal would require that these devices be set to a maximum speed, which is expected to save lives as well as improve fuel efficiency. Under the proposal, new trucks with a gross vehicle weight rating of more than 26,000 pounds would come fully equipped with the speed limiting device. The rule was determined to be a necessity in part due to analyses of crashes from 2004 – 2013 showing that speed likely contributed to over 10,000 fatalities in heavy vehicle crashes. The American Trucking Association has welcomed the proposal as furthering a focus on safety. “Speed is a major contributor to truck accidents and by reducing speeds, we believe we can contribute to a reduction in accidents and fatalities on our highways,” said ATA President and CEO Chris Spear to Transport Topics. It comes as little surprise that the ATA would support the proposal. As far back as 2006, ATA supported a policy in favor of limiting maximum speeds to 68 mph, and in 2008, reduced that number to 65 mph. While no speeds have been declared within the federal proposal, the benefits of 60, 65, and 68 mph are discussed (and illustrated below). The agencies admit that their projections are less reliable at 60 mph as a result of speed differentials, which could potentially make the driving conditions less safe. Sixty-five mph seems to have the most support from the industry. What is clear is that slower vehicles cause less damage when they crash and all three speeds would result in potentially thousands of fewer injuries.

Maximum Speed (MPH)

Lives Saved

Serious Injuries Prevented

Other Injuries Prevented

Fuel Cost and Greenhouse Gas Emissions Savings

27 – 96

30 – 106

560 – 1,987

$376 million

63 – 214

70 – 236

1,299 – 4,535

$848 million

162 – 498

179 – 551

3,356 – 10,306

$848 million

Overall, the rule has been well-received by large carriers. In fact, many large trucking fleets have been using speed limiters voluntarily for years. Going back to the early 1990s, some medium to large fleet motor carriers have put limiters in place. “A slower truck is a safer truck,” said Brad Caven, Pitt Ohio Express’s Vice President of Operations, in Transport Topics. XPO Logistics Spokesman Gary Frantz is quoted by Transport Topics as saying, “In our experience, the primary benefit of having the fleet governed at 65 mph, versus a higher speed, is safety related.”

whole fleets covered at that rate. Our intent was, and still is, trucks that already have the capability be required to use them.” According to NHTSA Administrator, Mark Rosekind, quoted by Bulk Transporter, “Setting the speed limit on heavy vehicles makes sense for safety and the environment.” There is little question of whether the requirement of speed limiters on heavy duty vehicles will ultimately save lives and have a positive impact on fuel economy and the environment. There is significant support for the recent proposal, with many truck fleets already using limiting technology voluntarily. While the ultimate implementation details remain undecided, it is clear we will see requirements established and rolled out in the near future. •

Additionally—not lost on fleet owners—are the potential fuel spend savings and fuel efficiencies created by these devices. “…[Yes,] obviously there is an MPG impact from it. When you’re going millions of miles, you’re talking about significant potential fuel reductions,” says Brad Caven. Also in support of the economic benefits is Lee Long, Director of Fleet Services for Southeastern Freight Lines, who has been limiting the speeds of their 3,200-truck fleet since the early ’90s. Transport Topics quoted Long as saying, “What we find is that running the limiters at a consistent level across the board provides us the best fuel economy for the company and performance for the drivers. When we limit the speed, we also control our insurance rates.” While there is significant support for the proposal, not everyone is completely supportive. The Owner-Operator Independent Drivers Association (OOIDA) cites that the proposal would create an environment that would be dangerous for all highway users and would create speed differentials, which could lead to more crashes and potentially more road rage among drivers. “Highways are safest when all vehicles travel at the same relative speed. This wisdom has always been true and has not ever changed,” says Executive Vice President Todd Spencer to Bulk Transporter. He goes on to point out the partial removal of control, saying, “No technology can replace the safest thing to put in a truck, which is a well-trained driver.” Most trucks manufactured since 1999, and all trucks since 2003, possess technology to limit speeds; however, that technology may not necessarily be installed or designed to be read or displayed. While public opinion is still being explored, the rule in its current proposed form does not require limiters retroactively—it would only apply to vehicles manufactured after adoption. For this reason, Road Safe America, a strong proponent of speed limiting requirements, feels they do not go far enough. President Steve Owings stated in Transport Topics, “As proposed, it would only apply to future trucks. How outrageous. It will take 20 – 25 years to get

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.

Viewpoints

Situational Awareness: If You See Something, Say Something

By Nikki A. Booth provided by the advisory and/or state and local officials for information about threats in specific places, or for identifying specific types of suspicious activity. Citizens should always call local law enforcement when in doubt. If you see something suspicious, please call local law enforcement. If there is a life threatening emergency, please call 911. When reporting suspicious activity, it is helpful to give the most accurate description possible, including: • A brief description of the activity

Wednesday, April 19, 1995, a truck bomb went off outside the Alfred P. Murrah Federal Building in Oklahoma City, killing 168 people and injuring hundreds more. On a fateful Tuesday morning, September 11, 2001, a series of four coordinated attacks killed over 3,000 people and injured thousands. On April 16, 2007, a college senior shot and killed 32 people and wounded 17 others on the campus of Virginia Tech. On June 12, 2016, a shooter killed 49 people and wounded 53 others inside a nightclub in Orlando, Florida. All of these acts, within the United States, are considered acts of domestic terrorism. According to the FBI, “domestic terrorism” involves activities with the following three characteristics: acts dangerous to human life that violate federal or state law; that appear to be intended (i) to intimidate or coerce a civilian population, (ii) to influence the policy of a government by intimidation or coercion, or (iii) to affect the conduct of a government by mass destruction, assassination, or kidnapping; and occur primarily within the territorial jurisdiction of the U.S. While America is stronger and more resilient as a result of a strengthened homeland security enterprise, threats from terrorism persist and continue to evolve. Today’s threats do not come from any one individual or group, do not discriminate amongst victims, and are no longer isolated to extremist groups. What can we do to prepare ourselves for a possible event of domestic terrorism? In today’s society, terrorism affects individuals and businesses alike. And unfortunately, domestic terrorism is a very real threat in the logistics industry. Terrorists have made use of trucks as weapons or tools to perform acts of violence. Strengthening surface transportation security and global supply chain security is a necessity to protect America’s infrastructure from terroristic threat. TSA has 25 multi-modal Visible Intermodal Prevention and Response (VIPR) teams working in transportation

sectors across the country to prevent or disrupt potential terrorist planning activities. Since the VIPR program was created in 2008, there have been over 17,700 operations performed. Fulfilling a requirement of the 9/11 Act, 100% of all cargo transported on passenger aircraft that depart from U.S. airports is now screened commensurate with screening of passenger-checked baggage, and 100% of high-risk cargo on international flights bound for the United States is screened. However, fighting terrorism is not only the government’s responsibility. Americans all share responsibility for the nation’s security and should always be prepared to respond should an emergency arise. Many companies, including Mansfield Energy Corp, are providing training for employees to become more situationally aware in order to recognize, react, respond, and report suspicious activity to prevent domestic terroristic acts. Situational awareness is the perception of environmental elements and events with respect to time or space, the comprehension of their meaning, and the projection of their status after some variable has changed, such as time or a predetermined event. To put it simply, situational awareness is being aware of what is happening around you. Gary Slater, Founder and CEO of Slater Tactical Solutions, which specializes in education and training for situational awareness, states, “It is imperative that the Hazardous Materials trucking industry (leaders and managers) recognize that a substantive Situational Awareness training program is directly related to driver safety and security.” Being continually aware of one’s surroundings and identifying potential threats and dangerous situations is more of a mindset than a hard skill. The “If You See Something, Say Something™” campaign across the United States encourages the public and leaders of communities to be vigilant for indicators of potential terroristic activity, and to follow the guidance

• Date, time, and location of the activity • Physical identifiers of anyone you observed • Descriptions of vehicles • Information about where people involved in suspicious activities may have gone • Your name and contact information (optional) Protecting the nation against domestic terrorism is a shared responsibility, and everyone can contribute by staying informed and aware of the threats our country faces. •

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

Why Renewables?

By Sara Bonario, Director of Supply, West See her bio, page 54

The Environmental Protection Agency (EPA) created the Renewable Fuels Standards (RFS) program under the Energy Policy Act of 2005, which requires the use of renewable fuels in gasoline and other petroleum-based fuels. The purpose of the RFS program is to achieve a reduction in greenhouse gas emissions. According to the EPA, the most significant greenhouse gases are water vapor (H2O), carbon dioxide (CO2), methane (CH4) and nitrous oxide (N2O). While there are both natural and human sources of carbon dioxide, the use of fossil fuels is thought to contribute 87 percent of human-produced carbon dioxide emissions.1

Biodiesel The most compelling reason to support the production and consumption of biodiesel is that biodiesel produces less toxic pollutants and greenhouse gases (GHG) than petroleum diesel. Carbon dioxide released during combustion of a biodiesel is offset by the carbon dioxide pulled from the atmosphere and stored in plants, such as soybeans, utilized to produce biodiesel. Biodiesel, when compared to petroleum diesel, is also cleaner, producing less particulate matter, carbon monoxide, unburned hydrocarbons, and sulfur dioxide during combustion. Biodiesel can improve fuel lubricity at blend levels as low as one percent. This is important since diesel engines depend on the lubricity of the fuel to keep moving parts from wearing prematurely. Diesel lost much of its natural lubricity in 2007 when sulfur was reduced to just 15 ppm. Sulfur acted as a natural lubricant, preventing excessive wear on engine components. Biodiesel is now used to make up for lost lubricity. Minnesota, Pennsylvania and Oregon have mandates in place requiring the use of biodiesel. In the state of California, blenders of biodiesel are able to reduce their cap and trade costs as well as participate in carbon credit programs. 1

Biodiesel does have some limitations, however. Due to its corrosiveness, many engine manufacturers only permit partial blends of biofuel, rather than 100 percent bio usage. Biodiesel also has a lower energy content, so users see slight reductions in power and fuel efficiency with higher concentrations. Additionally, biodiesel holds water more readily than normal diesel, which can cause phase separation and microbial growth when the fuel is left to sit for long periods of time. Despite these limited drawbacks, blended biofuels have been a valuable step forward for renewable fuels, and will continue to be a useful component in the energy mix of the future.

Renewable Diesel Similar to biodiesel, renewable diesel (RD) or “green diesel” is a diesel fuel produced from biomass. Many of the same benefits discussed for biodiesel are true of renewable diesel, but there are some additional advantages. Renewable diesel meets all industry fungible diesel standards (ASTM D975) and therefore can be commingled throughout the logistics supply chain. Many renewable diesel streams provide improved cold weather properties and have higher cetane and cetane index numbers. Generally speaking, the higher the cetane index the faster the fuel will ignite and the more completely it will burn, thereby improving engine performance. Renewable diesel users can go green with little or no capital expenditure to retrofit vehicles and tanks as would be necessary with other green fuels such as compressed natural gas. Renewable diesel is a drop-in replacement fuel with no issues or problems with original equipment manufacturers. Biodiesel provides a necessary and valuable alternative to fully-refined distillate fuels and has allowed the industry to take the first steps forward in meeting climate goals, but with its superior quality, renewable diesel appears to be the alternative fuel of the future. •

Le Quéré, C. et al. (2013). The global carbon budget 1959-2011.

Viewpoints

Winter Diesel Operability: Expect the Unexpected

From an unexpected blizzard in the South, to a crippling ice storm in the Midwest, to a surprising 70˚F Christmas day in New York—last winter was unpredictable. The history books will remember it as setting the bar for the warmest winter on record for the lower 48 states, but another record for most snowfall in a single snowstorm in Philadelphia and New York. These bizarre patterns are indicative of the erratic temperature swings and weather events that fleets should prepare for every year. This year, cold temperatures across the North are expected, with the ever-present potential for heavy snowfall in those areas. Across the southern states, the outlook is predictably rainy and mild. The past few years, however, have been defined by

By Clint Hamlin

unexpected and unusual weather events. This trend of unpredictability calls into question the accuracy of any preseason forecast and makes it difficult to determine when to begin winterizing diesel fuel. Volatile weather often leads to emergency situations. Taking a reactive approach to fuel winterization can lead to costly consequences. If this year sees the same 20˚-in-24-hour temperature swings as last winter, unprepared fleets will rapidly fall victim to the cold weather operability dangers of diesel fuel.

Winter Diesel Operability Winterizing diesel fuel is a necessity in most parts of the U.S. due to the cold flow properties of ultra-low sulfur diesel. ULSD contains paraffin wax molecules that remain fully soluble at mild temperatures but crystalize and compound together to form sheets of wax as temperatures plummet.

As fuel temperatures decline, waxes coagulate and form crystals, potentially impacting performance.

These wax sheets then get drawn into the fuel filter, either at the fuel dispenser or in the fuel system of the engine. This wax buildup continues to compound until the filter is clogged and soluble fuel is unable to penetrate the filter. When this happens, it starves the nozzle or engine of fuel and shuts down operations. Challenges with winter operability are compounded by the introduction of biodiesel, which is prone to premature wax fallout and gels at a higher temperature.

Emergency Preparedness Emergency preparedness requires that fleet managers expect the unexpected. Having onsite inventory of cold flow improver, emergency reliquifier, and water dispersant additives is a simple step consumers can take toward being prepared for sudden extreme temperatures. Preparedness also requires a current knowledge of the condition inside fuel storage tanks. A fuel testing program provides the insight needed to be proactive in protecting the fuel inside the tank from the onslaught of winter.

Viewpoints

Cold Flow Improver Additive

Fuel Testing

Using a cold flow improver (CFI) ahead of an impending cold snap can greatly improve fuel performance during an extreme winter event. Ideally administered at the time of fuel delivery, CFI additives must be properly mixed into the fuel. When properly blended, CFI additives modify the structure of the waxy molecules in fuel, preventing them from glomming together and creating filter-plugging sheets.

A comprehensive fuel testing program provides necessary insight as to the interior condition of a fuel storage tank. A testing program should include two basic types of analyses: a bottom sample test and a nozzle sample test.

Wax behavior WITH cold flow improver

FILTER

Nozzle sample tests provide data on the cold flow properties of winter fuel. Taken from the dispenser, a nozzle sample provides key operational metrics such as cloud point, cold filter plug point, and water content—all of which are critical in terms of winter operability. Nozzle samples should be drawn and tested at least once a month during winter, and more frequently if operationally practical.

FILTER

Wax behavior WITHOUT cold flow improver

Large flat crystals block filter, no flow

Bottom samples are drawn using a device known as a fuel thief or bacon bomb. Fuel samples taken from the bottom of the storage tank provide data on the extent of contaminants in fuel. A bottom sample is typically tested for water content, sediment accumulation, and microbial growth and should be tested right before winter to ensure such contaminants do not compound issues around winter operability.

A Comprehensive Solution

Emulsified crystals flow through filter

Increasing the treat rate of CFIs may provide additional protection. However, anything above a double treat rate generally has significantly diminishing returns.

While winter weather continues to be notoriously unpredictable, being prepared in the short-term requires constant weather tracking. Forecasts should be monitored up to two weeks out to allow adequate time for any preventative treatments or adjustments required. As a rule of thumb, a site should winterize its fuel for protection down to the tenth percentile of historical temperatures in that region. For any temperatures beyond that, emergency blending procedures should be incorporated. An optimal blending program that leverages actionable insights gleaned from test results combined with the cold flow benefits of winter additives can achieve significant cost savings and ensure ongoing customer operability. •

Emergency Reliquifier Emergency reliquifier is a fuel additive that is administered directly into a vehicle that has already experienced—or is expected to experience—the effects of fuel gelling or icing. Reliquifier dissolves congealed fuel or ice and returns it to a liquid state, inhibiting further gelling or icing. The additive is supposed to be used as a reactive measure to ensure operability in extreme conditions and is not intended for consistent preventative treatment.

Water Dispersant Water in diesel fuel, while fostering microbial growth and corrosion, can also be detrimental to winter operability. Water quickly freezes in the fuel lines and filters, causing filter plugging, fuel starvation, and ultimately, inoperability. A water dispersant additive, properly blended into the fuel, will rid diesel of entrained water that can lead to equipment failure if left untreated.

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

Viewpoints

The Best Cure for Low Prices By Alan Apthorp, Market Intelligence Analyst See his bio, page 54 With prices at historic lows, oil producers have been suffering. In late July, as many oil majors began reporting their earnings, the drop in quarterly revenue across the oil industry was once again quite large. In response to the decline in earnings over the past two years, budget cuts have become the norm across the industry, with $370 billion in 2016 – 2017 capital expenditures cancelled and over 350,000 oil-related layoffs globally during the price slump. Along with these cuts has come one cut that does not bode well for future energy prices—oil exploration. According to a report from Wood Mackenzie Ltd, oil exploration in 2015 reached its lowest point since 1947. As budgets have been squeezed, finding new reserves of oil has been pushed to the backburner. When exploration does happen, it is done on reserves that have already been drilled; companies prefer to expand production in existing wells to reduce capital costs.

Oil Discoveries Since 1948

Source: Rystad Energy, published by Bloomberg

The effects of low exploration activity will not be felt immediately. Exploration does not translate into short-term production; it does, however, affect long-term supply. Going from exploration into production takes approximately 10 years, meaning supply markets will not notice a change until 2025 and beyond. While new supply growth in 2025 will be anemic or negative, demand will continue to grow. Currently at 94.8 mbpd, the EIA projects global fuel consumption to grow over 10 percent to 104.5 mbpd. Low supply and high demand is a recipe for disaster for consumers, who will be left responsible to pay for the difference. Investments in fuel efficiency and fuel price hedges, while currently uncommon due to the low price climate, may pay large dividends over the long term as prices are set to increase.

EIA World Liquid Petroleum Consumption

Source: Energy Information Administration (EIA)

Viewpoints The good news is that a lack of exploration does not necessarily mean drillers will not know where to begin. While exploration for new oil reserves is down, existing proved reserves are at all-time highs, running at nearly 1.7 billion barrels in 2015. And production, while largely down globally, could continue to grow in some areas despite low prices. Pioneer Natural Resources believes output from the Permian Basin could grow from 2 mbpd currently to 5 mbpd by 2025, relieving some of the pressure from growing demand. In addition, a new field named Alpine Heights, with a reported 2 billion barrels of oil equivalent in reserves, was discovered this quarter, further adding to supply options in the future. Despite this growth in some areas, most production globally has slowed down amid worries over profitability.

World Crude Oil Proved Reserves (Bn Barrels)

Source: Energy Information Administration (EIA)

One glimmer of hope through the downturn has been rig counts in the third quarter. Despite price uncertainty in oil markets, upstream companies have felt growing confidence regarding the coming supply and demand balance in 2017 and beyond. Third-quarter growth in active rig counts was in the double digits nine times out of twelve weeks, driven by shale drilling in the low-cost Permian Basin. Continuous growth in rig counts amid low prices could signal that producers are focused less on the current pricing environment and more on long-term supply-demand dynamics. With this mindset, the industry may see exploration activity resume as prices are expected to rise, staving off the worst effects of a supply shortage and limiting its impact to only a few years.

Rig Count Grows Despite NYMEX Movements

Source: NYMEX, Baker Hughes

So are we bound for a permanent state of high energy prices and low supply? Doubtful. The best cure for low prices may be low prices, but the reverse is true as well. As prices rise and drilling becomes more profitable once more, expect more producers to enter the arena, correcting supply and bringing prices down again to create a new bust cycle. If there is one thing you can count on, it’s that calls for a “new normal” will only last as long as the next boom or bust. But, with that said, be ready—the next boom is certainly on its way. •

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

Andy Milton

Amy Nguyen

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. •

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. •

Senior VP of Supply and Distribution

Supply Optimization Supervisor

Keith Crunk

Wholesale Gas Supply Manager

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. •

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

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. •

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. •

Evan Smiles Supply Manager

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. •

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. •

Sara Bonario

Director of Supply, West Sara manages the team responsible for procurement and optimization of all refined fuels for Mansfield’s Great Lakes, Central, and Western regions. She is also responsible for nationwide purchasing, hedging, and distribution of renewable fuels. Sara has an extensive supply and trading background, with over 25 years of experience in the oil industry. •

Alan Apthorp

Market Intelligence Analyst Alan Apthorp is responsible for content editing, research, and data analysis and visualization at Mansfield. He also works with Mansfield’s content marketing team to analyze market trends to generate valuable insight for Mansfield’s customers. Alan joined Mansfield as a member of their Sales Academy, where he worked with Mansfield’s Power & Gas division. •

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