Brexit and the price of oil and natural gas. Now what?

The latest worry for oil bulls: Brexit, which has already sent the price of crude tumbling. What does last week’s vote mean for energy prices on this side of the pond?

Rude Surprise

As with most financial markets, the oil market seemed to be betting that British voters would reject a referendum to leave the European Union. In the days leading up to the vote, when bookies were heavily favoring a “remain” outcome, U.S. benchmark West Texas Intermediate was on the rise. By the eve of the vote, WTI had crested $50 per barrel, having nearly doubled from its February low of $26.21 per barrel. Traders must have been figuring a remain vote would put the long-simmering issue of the U.K.’s membership in the EU to rest, allowing markets to focus on the fundamentals of supply and demand.

Some further modest price increases looked like a good bet. Prior to the vote, we were figuring that WTI could move a few dollars per barrel higher this summer. After all, this is shaping up to be one of the busiest travel seasons on record, and Americans continue to snap up new SUVs and pickup trucks instead of hybrids and other gas misers. Heavy demand at the pump normally means refineries are running nonstop and buying plenty of crude oil.

And then, suddenly, things changed. To the surprise of almost everyone, the final tally showed the Brexit campaign coming out on top with nearly 52% of the vote. Markets everywhere tanked, with the notable exceptions of safe sovereign debt, certain safe-haven currencies such as the yen, and precious metals. Oil, being a risky asset that buyers flock to when times seem good and flee when signs of trouble emerge, joined stocks in the sharp, post-Brexit sell-off. After briefly breaching the $50 mark, WTI promptly slid to $46 per barrel by the Monday after the referendum, only to soar again on Tuesday and Wednesday as financial markets rebounded.

Where do things go from here? First, an easy forecast: Oil prices will remain volatile. After prices slid to that February low of $26.21 and then rocketed to $50 four months later, investors should expect the big swings to continue, for the simple reason that there are so many forces trying to push or pull crude prices in different directions.

Supply outages from Canada to Nigeria helped fuel the big spring rally, and new cutbacks can never be ruled out in a world beset by terrorist threats and political instability. But at the same time, global stockpiles of oil and refined fuels are bulging, and big exporters such as Russia and Saudi Arabia are pumping flat-out. So supply could continue to swamp demand. Meanwhile, concerns about the health of the global economy are mounting, especially in light of the latest EU crisis. Plus, any further weakening in currencies such as the British pound and the euro means a relatively stronger dollar, which makes dollar-denominated crude oil more expensive for foreign buyers and tends to suppress consumption.

Our best guess as to the direction of oil prices in the near term: A bit lower than crude had been trading recently, followed by the possibility of a modest midsummer rally. Barring a financial crisis or a nasty slide in the global economy, $45 per barrel seems like a reasonable floor for oil prices. As the season progresses and gasoline demand heats up, a return to $50 or a bit higher wouldn’t be surprising, though we would expect any such rally to be fleeting. By the end of September, when the summer driving season is over and demand cools off, we look for WTI to trade from $40 to $45.

In the longer run, crude could push higher because of today’s relatively low prices. Drilling activity continues to weaken and oil companies are nixing the sort of big projects that are needed to keep future supply in line with demand. If investment falls further, warns Prestige Economics President Jason Schenker, “the medium-term upside risks for oil prices are significant — especially in the 18- to 24-month window.” So for long-term oil investors, the more pain they absorb now because of Brexit, the more gain they could eventually reap down the road.

Natural Gas: “Brexit? What Brexit?”

Looking for an investment that won’t be buffeted by the aftershocks of the Brexit vote? Consider natural gas, the price of which barely budged after last week’s referendum. Unlike oil, which flows freely around the world and sells for similar prices in most countries, U.S. natural gas is still largely locked within the lower 48. A trickle of liquefied natural gas is starting to reach overseas markets, and more gas reaches Mexico and Canada by pipeline. But the vast majority stays within U.S. borders, making America its own unique gas market.

Natural gas has been enjoying a sizzling rally lately. The benchmark gas futures contract fell to a multidecade low of $1.64 per million British thermal units (MMBtu) this winter because of unseasonably warm weather and weak heating demand. Even as recently as mid-May, gas traded for about $2 per MMBtu. But since then, it has soared to $2.80 as hot weather in the western U.S. has ramped up electricity demand. Gas-fired power plants, which now account for more of the nation’s electricity than any other source, are working hard to keep up.

But this looks like one rally that may be running out of steam. Stephen Schork, editor of the energy trading newsletter The Schork Report, says he was not surprised by the late-spring rally, noting that summer weather forecasts calling for continued heat are “as bullish as it gets” for natural gas. Still, he predicts that gas held in storage will grow to a new record high by the end of the autumn, which should curb further price gains. And the downturn in manufacturing means that factories and other industrial customers are burning less gas this year than they did in 2015. The bottom line: If natural gas prices haven’t peaked already, they will soon, he reckons.

Which companies will profit from the digital surge as India comes online?

In this issue: New Wi-Fi gear for the home. Hacking threats to fitness trackers. The huge market for tech products in India. Amazon stock: What’s it worth? More-detailed rules to govern the Internet. Apple’s effort to improve its apps. What Microsoft’s acquisition of LinkedIn means for business.

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Why truckers aren’t jumping for joy at $2.37 diesel

Cheaper fuel would seem like a godsend for businesses in the transportation world. But even with gasoline and diesel at multiyear lows for this time of the year, low prices are a mixed blessing. Also in this issue: An early note for propane customers who are already thinking ahead to next winter.

Elusive Savings

It takes a lot of diesel fuel to haul raw materials and finished goods around the country. So you might expect trucking companies and railroads to be jumping for joy now that diesel is averaging a mere $2.37 per gallon at fueling stations. That compares with an average of $2.87 per gallon one year ago. From 2011 until 2014, diesel averaged close to $4.

But cheap fuel isn’t necessarily a savior for the trucking industry. Bob Costello, chief economist for the American Trucking Associations, says that on average, fuel is the industry’s second-largest operating cost. But the big slide in diesel prices doesn’t herald a financial windfall, he says, since trucking companies typically pass 60% to 70% of their fuel costs on to their customers in the form of fuel surcharges. That means the average trucking firm is only “on the hook” for a relatively small share of the diesel its trucks burn, which limits the upside from cheaper diesel.

Low pump prices are a double-edged sword for truckers. Though saving on the cost of keeping their engines running, many truckers have been hit hard by the same factor that has brought down the price of diesel: The swing from boom to bust in the U.S. oil industry. Up until recently, truckers in places like North Dakota and Texas were doing a good business delivering the pipes, frack sand and other materials needed to drill and hydraulically fracture an oil well in fields such as North Dakota’s Bakken Shale. Then the frenzy of drilling unleashed enough new oil output to send prices plummeting. Now, says ATA’s Costello, the plunge in drilling has idled many truckers who are no longer needed to haul equipment and material to new wells.

Freight railroads face a similar dilemma. According to industry sources, railroads are paying 29% less for diesel this year than last year. And fuel typically represents the second- or third-largest operating expense for freight rail. But just as with trucking firms, railroads are suffering amid the decline of commodity prices in general and oil in particular. Data from the Association of American Railroads shows that trains hauled 20% less oil and petroleum products this May than in May 2015. (The massive 30% drop in coal tonnage hurts even more.)

And unfortunately for the railroads, other types of freight aren’t filling the gap left by declining commodity volumes. For instance, railroads have handled 2.1% fewer shipping containers so far in 2016, compared with the same period last year. “Most economists think the economy has picked up in the second quarter from the dismal 0.8 percent growth in the first quarter,” says AAR Senior Vice President of Policy and Economics John Gray. “But so far, railroads aren’t seeing much of it.”

Even public transit is lagging a bit. After rising briskly in recent years, total transit ridership growth slipped to just 0.35% in the first quarter of 2016, compared with Q1 of 2015. Many of the nation’s buses and commuter trains run on diesel, so they benefit from cheaper fuel costs. But with the price of gasoline down more than 40 cents per gallon from a year ago, it’s not surprising that commuters are driving more. Through the first three months of 2016, total miles driven in the U.S. was up a sizable 4.2% from the first quarter of 2015. That likely means that the clearest beneficiaries of cheaper fuel are the businesses that cater to drivers: Mechanic shops that repair the wear and tear that comes with driving more, tire makers and convenience stores with gas pumps. Their motorist customers have more cash in their pockets after fueling up and can thus afford to also grab a sandwich or a soda (which are far more profitable for the stores than gasoline is).

Propane: Less of a Bargain Next Winter?

Homeowners and businesses that heat with propane probably enjoyed last winter’s prices. At the end of the season, the average retail price paid by residential propane users hit $2.01 per gallon: 28 cents cheaper than in the previous year. The combination of low oil prices and a massive stockpile of propane in storage, plus a mild winter in the East, kept a tight lid on propane prices.

Propane stockpiles are still bulging. In fact, they ended the winter at their highest level ever for that time of year and are now on the rise. But stocks aren’t increasing nearly as rapidly as they did last spring, when the storage level grew by 25 million barrels from mid-March to early June. This season, the build has been on the order of 15 million barrels, a sign that propane output has probably slackened along with the broader slowdown in oil and gas production. The U.S. is also exporting more propane now than a year ago, which should tend to slow the rise in domestic storage levels.

There’s no question that propane will be abundant by the time chilly weather returns this fall. And that should mitigate any significant price rise. But stockpiles probably won’t return to the record amount reached last autumn. And with the shift in the global weather pattern El Niño to La Niña under way, the odds of another extremely mild winter are declining. So propane users would do well not to bank on a repeat of last winter’s bargain basement prices.

How will new battery technologies change the energy industry?

Large, powerful batteries are going to be popping up in new places in coming years. They’ll be especially prevalent in the electric industry, as utilities and other companies use huge battery banks to help stabilize the electric grid and homeowners start pairing rooftop solar systems with batteries to store excess energy from the sun for nighttime use. Meanwhile, one company is essentially betting its future on being able to produce large batteries cheaply enough to power millions of electric cars.

Powering the Grid

2015 saw a big jump in the amount of battery storage capacity connected to the electric grid as power companies and big electricity buyers looked for ways to better balance electricity supply and demand. Large banks of batteries, some the size of truck trailers, can store excess energy when demand for power is low and then discharge it back to the grid when usage jumps.

Until recently, such systems were usually too costly to make economic sense. But the combination of falling battery costs and the shutdown of many older power plants that used to provide extra electricity during periods of high demand made 2015 a banner year for new grid-connected battery capacity, according to the Energy Storage Association, an industry trade group. What’s more, ESA projects that demand for such systems will be seven times as large in 2020 as it was last year. ESA Executive Director Matt Roberts is confident that the lithium-ion batteries the industry typically relies on are now cheap enough to make such systems economically competitive in many electricity markets. Think of storage as “a service, not a technology,” he says: A service that will become increasingly valuable to the grid operators who have to constantly keep power generation and electricity demand in balance.

For an example of how the economics of storage are changing, consider the village of Minster, Ohio, where the S&C Electric Co. recently worked with renewable energy firm Half Moon Ventures (HMV) to install a battery storage system capable of holding 3 megawatt-hours of energy, roughly equivalent to the power consumed by a thousand typical homes during one hour. The batteries work in tandem with a 4.2-megawatt solar farm owned by HMV, and they allow the village of Minster to lower its annual electricity costs, says Troy Miller, director of grid solutions at S&C. The system will let Minster avoid the “fairly significant demand charge” that grid operator PJM imposes on days when power demand is especially high, according to Miller. What’s more, it helps provide voltage regulation for the grid, a service for which PJM actually pays Minster. S&C sees future demand for similar installations in New England, California, Caribbean islands and other power markets.

And it’s not just big companies or local governments that will be turning to batteries. Homeowners with solar panels on their roofs will be as well. The amount of power generated from the sun is growing rapidly. But integrating all that newfound energy onto the electric grid is challenging, since peak power output tends to occur around noon, whereas peak power demand usually arrives in the late afternoon, when folks are coming home from work, turning up the air conditioner, etc. And while many states require electric utilities to buy surplus solar power from solar-equipped customers, whether the power company wants it or not, those rules are starting to get watered down as the number of solar-powered homes grows.

Hawaii figures to lead the way on small-scale battery storage to back up solar panels. A sunny state with lots of rooftop panels and no place to send surplus power during periods of high generation, the Aloha State could be the “canary in the coal mine” for the mounting supply-demand mismatch issue, says John Berdner, director of global regulatory compliance at solar tech firm Enphase Energy. Energy regulators in Hawaii recently cut back on the state’s “net metering” program, which requires utilities to purchase residential customers’ excess solar energy. Now, says Berdner, folks who install new solar systems will have a greater financial incentive to incorporate battery storage so they can supply more of their own electric needs, rather than pay for expensive power from the electric company when the sun isn’t shining. And with the cost of home-scale storage systems likely to decline by half over the next five years, Berdner expects battery storage to become increasingly cost competitive.

States in the Southwest will also see interest in solar-plus-storage pick up. Nevada, for instance, recently curbed its net metering program, meaning that solar customers will receive less money over time for the surplus power they sell back to the grid. Again, that tilts the economics in favor of storage, since reducing the amount of power a customer buys from the utility when the sun isn’t shining is now worth more than selling that same amount of power back to the grid at a reduced price.

Eventually, battery storage could be the key to resolving the fight between electric utilities and their solar-powered customers. Utilities understandably don’t want to pay full price for solar power that they don’t necessarily need, while solar customers understandably want to put that excess generation to good use. If more states follow the lead of Hawaii and Nevada in scaling back net metering, battery storage will become a viable way to make both utilities and their solar customers happy.

Enphase Energy’s Berdner likens the current standoff to a blackjack game in which the utility is the house dealer and solar-powered customers are playing against the house: In each hand, one side wins and the other loses. With sufficient battery capacity, the game could look more like poker, where many players participate and the house dealer merely facilitates the game while collecting a portion of each hand’s winnings. In that analogy, the utility would get paid not just for generating electricity but also for allowing solar-powered homes and businesses to sell their stored power to other customers across the utility’s power lines when demand was high. Think of such an arrangement as a “virtual power plant,” in which thousands of separate solar systems store energy and then discharge it en masse when it’s needed.

On the Road

Batteries also hold the promise to bring about significant change to the auto industry. Although electric vehicles and hybrids still make up a tiny share of the market, carmakers are hard at work on them for the simple reason that fuel economy regulations are getting tougher, and electrification offers one way to meet tighter standards.

No company is betting as heavily on batteries to propel future cars as is Tesla, the California upstart founded by tech billionaire Elon Musk. Up to now, the company has earned rave reviews – but not much profit – for building pricey, luxurious electric cars for well-heeled buyers. But with the unveiling of its “mainstream” Model 3 sedan this spring, Tesla is hoping to become a mass-market brand. To do that, it’ll need lots of low-cost lithium-ion battery packs, which don’t quite exist yet. So Tesla is building them itself, at a giant battery factory in the Nevada desert. The idea: Scale up production, drive down costs and sell a snazzy electric car at a price that more folks can afford. (Oh, and turn a profit doing it.)

Will it work? Tesla certainly seems to have a long road ahead of it. With gasoline prices low these days, buyers are snapping up SUVs and pickup trucks. Saving fuel isn’t the priority it was back when gas cost $3 or $4 per gallon. And Tesla is trying to do something no one has done before: Manufacture powerful lithium-ion batteries in huge quantities. What’s more, the company has a spotty track record of delivering new products on time–not a comforting history considering that hundreds of thousands of paying customers are waiting for their new Model 3.

But the company does have at least one potent advantage: Its devoted fan base. Senior Analyst Jessica Caldwell notes that it will be at least a couple of years before many customers see their new Model 3, even though they’ve already plunked down $1,000 deposits. And yet “they don’t seem to mind,” based on her conversations with Tesla buyers. “People want to be part of the Tesla experience.”

Having loyal fans won’t help Tesla build batteries. But it probably will buy Tesla more time to build them. Caldwell believes that Model 3 production is likely to get delayed, possibly because of hiccups at Tesla’s battery plant. Still, she expects that its customers will largely remain patient and still pay up for the new car when it does come out. We’re inclined to agree. So while Tesla might take longer to drive a revolution in battery production than Musk intends, it’s still a decent bet to deliver in the long run.

Recycling: Costs and Opportunities

One aspect of the proliferation of large batteries that doesn’t get talked about much: What to do with them at the end of their lives. The recycling industry hasn’t traditionally seen many large lithium-ion cells, so it’s not geared up to reprocess them. Recycling them is complicated and potentially difficult, says Joe Acker, president of California-based Retriev Technologies. The industry has been dealing with lead-acid automotive batteries for decades and has largely perfected the process. But lithium-ion battery packs present unique challenges because they have more parts and come in many shapes and sizes.

But recycling lithium-ion batteries will pay off for some recyclers. That’s because they contain valuable materials, such as cobalt, and because many of the cells that come from, say, an electric vehicle, can be reused in other applications, such as storage for the electric grid. In eight to 10 years, says Acker, the battery packs going into today’s early electric vehicles will start showing up at recyclers, and companies such as Retriev stand to benefit from the increased business. And as users such as carmakers start to settle on standardized battery designs, the recycling process should get easier, he reckons.