Energy Alert for July 29, 2015

It may not get a lot of headlines, but the nuclear power industry is facing some stiff headwinds these days. Big changes in the utility industry mean some plants might close for financial reasons. In time, that could make the U.S. more dependent on other power sources, increasing the risk of rising rates.

Nuclear Woes

In the electricity world, nuclear power is the ultimate Steady Eddie. America’s roughly 100 nuclear plants reliably churn out enough electricity to meet about 20% of the country’s power needs. Other energy sources, by contrast, vary substantially in their output. That’s especially true of renewable sources such as wind and solar, but it also applies to hydroelectric dams (which ramp up when rain is abundant) and natural-gas-fired power plants (whose output rises and falls with seasonal power demand and the cost of gas).

That makes nuclear a key contributor to the grid’s baseload generation: the power that grid operators count on to be available night and day, whether power demand is weak or strong. And unlike coal- or gas-fired plants, nuclear plants emit no greenhouse gasses, which is an asset as Uncle Sam readies regulations that crack down on such emissions. (Of course, what to do with the radioactive spent fuel from nuclear plants remains an unsolved problem.)

And yet, some nuclear plants are struggling financially. Two plants — one in Wisconsin, another in Vermont — have already closed for financial reasons, and plant operators are warning that others could soon follow. Why? In a word, price.

In certain power markets, nuclear plants are competing with a flood of new power coming from either natural gas or wind. Today’s low gas prices mean gas-fired plants can generate electricity at a lower cost than some nuclear plants. Ditto for wind turbines, which earn a subsidy for each kilowatt-hour of electricity they produce if the facility was built before Jan. 1, 2015. In both cases, the result is the same: Rival generators are undercutting the cost at which certain nuclear plants can sell their power.

That issue is especially acute in states with unregulated power markets, says Dan Lipman, vice president of supplier and international programs at the Nuclear Energy Institute, an industry trade group. In those markets, which are mostly in the northern portion of the country, the lowest-cost source of generation tends to set the market rate for power that generators can sell. Nuclear plants competing with cheap gas and subsidized wind are at a cost disadvantage, says Lipman. And even though nuclear power is arguably more valuable, in the sense that it is highly reliable, plant owners don’t receive any compensation for that unique dependability.

That’s bad news for owners of nuclear plants in unregulated markets such as Illinois, where utility Exelon is warning it may shut down some of its nuclear facilities that can’t earn a profit. NEI’s Lipman says plants facing the most financial risk are those in unregulated power markets that consist of a single reactor. (For a quick rundown of regulated and unregulated power markets, check out this handy map.)

In regulated power markets, the story is very different. There, nuclear plant owners can more easily recoup operating costs and turn a profit, since state public utilities commissions set rates to ensure a reliable supply of power. So it’s no surprise that the handful of new nuclear plants scheduled to come on line in the near term are all in regulated markets in the Southeast: the Tennessee Valley Authority’s Watts Bar project (due in June), Southern Co.’s two new reactors at its Vogtle plant in Georgia, and the South Carolina Electric & Gas Co.’s two new reactors at its V.C. Summer facility (all expected to come on line near the end of the decade). Investors in the companies building those plants stand to gain once the power starts flowing, and don’t have to worry so much about competition from cheap gas or wind power.

Doubling Down on Gas, Renewables

The challenges for the nuclear industry are just one facet of an unprecedented shift taking place in the U.S. power sector. Coal, long the mainstay of power generation, is seeing its share of the electric market shrink. Utilities faced with tough new government air pollution rules are opting to shut down many coal-fired plants instead of upgrading them to meet the new air quality standards. Meanwhile, cheap natural gas offers a way to compensate for the lost coal capacity. And many states are requiring utilities to obtain more of their electricity from wind, solar and other renewable sources.

As a result, coal’s share of the overall electricity mix has fallen to 34% so far in 2015. That’s down from about half in 2005, and 44% as recently as 2010. In April of this year, for the first time on record, natural gas supplied more electricity than coal.

The trend will only continue as more coal plants shut down. For 2015, the Department of Energy is predicting that coal plants with a combined generating capacity of 13 gigawatts will shut down. Granted, those plants tend to be small and run less often than large coal plants, but that still means more reliance on gas and renewables to take up the slack, especially when power demand spikes. DOE sees wind as the largest source of new generation coming on line this year, with new gas-fired capacity in second place.

That means, in the long run, that electric customers will be more at the mercy of volatile fuel sources, namely gas and wind. Gas prices are cheap now, but we expect them to rebound gradually in coming years, as demand keeps rising. And of course, wind will always be an on-again, off-again energy source. With more coal plants likely to close, it’s not hard to imagine a future in which natural gas supplies an even bigger share of power generation than it already does, especially when electricity demand spikes during extremely hot or cold weather and the wind doesn’t oblige by blowing steadily. Figure on some hefty power and gas bills when that day comes.

Energy Alert for July 15, 2015

Though it’s July, it’s not too early to start thinking about this coming winter’s heating costs. Depending on how you heat your home or business, you might be able to lock in a favorable fuel price from your supplier or simply stock up at a time when prices are low.

Heating costs are difficult to forecast because the weather is erratic. You never know if you’re going to get hit by the sort of Arctic blasts that raked the Northeast over the last couple winters, or if Mother Nature is going to keep the thermostat on “warm,” as happened in many places in the drought-stricken West. Energy markets can be even more unpredictable than the weather, especially if a cold snap arrives when supplies of natural gas, heating oil or propane are stretched thin.

That was the case in the Northeast two winters ago, when a series of “polar vortices” sent temperatures plummeting when stocks of natural gas were already low and suppliers were having trouble delivering enough oil and propane to customers. (Take a glance at the history of residential propane prices; the spike in early 2014 is impossible to miss.) That resulted in hefty heating bills for plenty of folks.

So, how are things shaping up this year? The answer depends on what kind of fuel you burn for heat (or whether you rely on electricity for heating, as many homes and businesses do).

First, consider natural gas, which heats about half of American homes. Gas prices have mostly been cheap in recent years, thanks to the advent of hydraulic fracturing and horizontal drilling in gas-rich layers of shale, such as the Marcellus Shale in Pennsylvania. But prices can still jump when winter weather turns frigid, especially in markets such as Boston and New York City. The spike depends to a large extent on how much gas energy companies saved up in underground storage during the preceding summer.

This year, storage facilities aren’t exactly overflowing, but they’re not low, either. The Department of Energy reports that gas in storage is about 2% higher than average for this time of year, and well above last year’s level. So the risk of a supply squeeze and resulting price jump is somewhat remote.

How about heating oil? Users will be glad to know that stocks of distillate fuel oil — including diesel and heating oil, its close chemical cousin — are actually higher now than they’ve been during the last few summers. And the big drop in crude oil prices from last year means heating oil is far cheaper today than it was a year ago. New York state’s energy department says the fuel is a buck per gallon cheaper now than it was a year ago in the Empire State. Ditto in Massachusetts. Prices should even slip a little bit more in coming weeks, meaning that oil users who have a chance to fill their tanks to the brim before cold weather arrives should consider doing so.

Propane users are really in luck. Stocks of propane held in storage are already at the highest level on record, and they’ll only keep rising throughout the summer, when demand is low. Producers eager to find more buyers are exporting record amounts of U.S. propane, but even that won’t be enough to avoid a glut come fall. Prices are already slipping and are almost certain to head lower over the course of the summer. So again, stock up by fall and keep an eye out for long-term supply contracts sporting favorable prices. We figure the average residential cost of propane will be about $2 per gallon or less this October (down from $2.30 per gallon last March), with the lowest prices along the Gulf Coast and in the Midwest, and the highest prices in the Northeast.

For electric heat, figure on paying more for each kilowatt-hour. Electricity rates rose by roughly 3% last year over 2013, and we expect rates to nudge higher still in 2015 and 2016. The retirement of many coal-fired power plants due to tougher environmental regulations means higher costs for utilities and more reliance on natural gas. (In fact, gas provided more electricity than coal this past April, for the first time ever.) If the winter of 2015-16 proves to be another frigid one, electric rates are bound to rise as power plants compete for gas with the many homes and businesses burning gas for heat. That’s a particular concern for the gas-dependent Northeast.

Geopolitical Turmoil Kneecaps the Oil Market

A quick note on the recent tumble in oil markets, which saw the U.S. benchmark West Texas Intermediate (WTI) slide from about $60 per barrel to $52 in a matter of days. That marked a sharp reversal of the upward trend prices had been on since early spring.

Fears stemming from Greece’s seemingly interminable debt crisis certainly contributed to bearish sentiment and pushed the euro down against the dollar. (Since oil is priced in dollars, a stronger dollar weighs on the price of crude). And on Tuesday, the announcement of a deal between the U.S. and Iran over the latter’s disputed nuclear program raised the prospect of embargoed Iranian oil returning to global markets.

But don’t get too hung up on Greece or Iran. The real story is China, and its seesawing stock markets. China is a massive buyer of all industrial commodities, including crude. Any concern that a stock market swoon might ding its already slowing rate of economic growth also raises fears that the country might buy less oil. Stephen Schork, editor of energy investment newsletter The Schork Report, suspects that Chinese oil imports are poised to slow now that the country is largely done filling its emergency crude oil reserve.

We see oil prices struggling in the near term. WTI might claw its way back to $60 per barrel by the end of summer, but it’s unlikely to rise much more than that, and figures to retreat once the summer driving season ends. How much is hard to say, but we lean toward a price in the low- to mid-$50 range by late fall. That means drillers in the U.S. will have to push even harder to cut costs and make their operations more efficient as they ride out the latest geopolitical waves rocking the global oil market.

Tech Alert for July 8, 2015

Fighting off cyberthieves. Growing costs of cybersecurity. Advice from the Federal Communications Commission on new Web services. Lessons learned from the SpaceX rocket fail. The impact of the strong dollar on global information tech sales. Surprising buyers of smart-home technology. Slow-loading websites lose sales.

Continue reading “Tech Alert for July 8, 2015”

Energy Alert for July 1, 2015

Oil prices are off about 40% in just one year. And the number of rigs drilling new oil wells has likewise plummeted since last summer. But U.S. oil production is up, and promises to keep climbing.

On the fuel consumption front, new regulations are on tap for trucks, buses and other large commercial vehicles.

“Saudi America”

At about 9.6 million barrels per day, domestic crude output is nearing its all-time high set in 1970, thanks to a flood of new production in Texas, North Dakota and other states with large deposits of oil trapped in shale and other hard-to-drill rock. The combination of hydraulic fracturing and horizontal drilling has transformed the U.S. from a nation dependent on oil imports to “Saudi America” in less than a decade.

But can the surge last in the face of sharply lower prices? Many analysts have been predicting a decline, now that energy companies have cut back on drilling and started laying off rig crews. According to Baker Hughes, the large oil field services firm, the number of rigs actively drilling for oil has tumbled from 1,558 a year ago to just 628 now. And since shale oil wells are notorious for petering out pretty quickly, less drilling now must mean less oil pumped later. Right?

Maybe not. Even as drilling activity started skidding last fall when crude prices collapsed, production keeps rising. Although they’re running fewer rigs, drillers are becoming more efficient — requiring less time and cost than before to drill a new well. Meanwhile, the average amount of oil yielded by a new well is up, according to the latest data from the Department of Energy.

Recent history suggests that gains in drilling efficiency can more than make up for fewer rigs in operation. Consider the U.S. natural gas industry, which has also used fracking and horizontal drilling to unleash a production renaissance. Several years before the oil rig count started its drop, gas rigs underwent a similar decline. Note the similarity of the two trends:

Oil and Gas Drilling Rigs
Click for a larger version of this chart

Despite the huge slide in the number of rigs in operation, U.S. gas output has continued to rise each year since. Faced with a drop in gas prices even more severe than the recent oil price drop, gas drillers got smarter, focusing their efforts on the most productive deposits and drilling more-productive wells that stretched deeper into the gas-bearing rock layers. Today, oil drillers are doing many of the same things. And that makes us think oil production will keep rising.

Continued production gains mean oil prices are unlikely to rise much anytime soon. Crude at $100 per barrel, which seemed so unremarkable only a year ago, is now a distant memory. With prices at about $60 per barrel, oil companies are working harder to turn a profit, but increasingly efficient drilling means more drillers are or will be profitable at these prices, giving them the incentive to produce more. Furthermore, many firms are storing up partially finished wells for later, hoping to cash in on higher prices by delaying production. In North Dakota alone, the state’s oil and gas regulator reports a backlog of 925 uncompleted wells that should gradually come on line as prices nudge a bit higher (as we expect them to).

Uncle Sam Dials Up Tougher Mileage Rules for Heavy Trucks

Turning from crude oil to consumption of refined fuels: Note that federal regulators recently unveiled their proposed fuel economy standards for trucks, buses and other large commercial vehicles sold as 2018 models and beyond. The move follows up on the Obama administration’s first batch of fuel economy targets for the sector, which covered model years 2014 to 2018 — the first such efficiency standards ever imposed on medium- and heavy-duty trucks.

Those changes could eventually net big fuel savings for the trucking industry, since trucks consume more than 30 billion gallons of diesel fuel each year. But the savings won’t come cheap.

Truck builders will need to adopt a wide range of technologies for saving fuel, says Glen Kedzie, the American Trucking Associations’ energy and environmental counsel. Likely solutions include more-aerodynamic trucks and trailers; greater use of tires that produce less rolling resistance; automatic transmissions that let engines work at their most efficient level of revolutions per minute; and “predictive cruise control” that can anticipate approaching hills and adjust a truck’s speed to maximize fuel economy. All of that figures to be costly.

Under the government’s proposed rules, heavy-duty pickup trucks and medium-size commercial trucks would need to cut fuel consumption about 16% by the time the rules take full effect in 2027. The largest tractor trailers would have to achieve cuts of roughly 12%. Environmental groups are already lobbying the feds to set even tougher standards when the rules are finalized next year.

But, luckily for firms in the trucking industry, it appears that regulators are listening to their concerns. ATA’s Kedzie says his group has been supplying the government with reams of data on the costs and benefits of various fuel-saving technologies so that the feds don’t write overly strict rules or insist that the industry adopt unproven equipment. “It’s been a very good working relationship,” he says. And that’s critical, because trucking companies want to invest only in technologies that will really pay for themselves in reduced fuel costs.

Energy Alert for June 17, 2015

In a recent issue, we noted that the battery industry is poised for growth as both utilities and their customers look for ways to store energy for use when demand is high or the electric grid fails. Battery tech is advancing and costs are falling, but batteries are far from the only viable way to store energy or provide backup power in emergencies. Two other approaches — one novel and one traditional — are also making strides.

Hydrogen Power

Fuel cells have long held the tantalizing prospect of providing abundant and clean energy. By combining hydrogen and oxygen to produce electricity (and water as a by-product), fuel cells emit no greenhouse gases or pollutants; they run silently; and, unlike batteries, they can be “recharged” quickly by adding more hydrogen.

But logistics have long hampered fuel cells. Though hydrogen is the most abundant element, very little of it exists in pure, elemental form. So providing the fuel for fuel cells means extracting hydrogen from other molecules, such as the methane in natural gas, and then transporting pure hydrogen to where it’s needed. And with very little infrastructure in place to move the hydrogen, fuel cells can’t be used in many places.

However, fuel cell makers such as Plug Power of Latham, N.Y., are gradually starting to overcome that obstacle by improving the shipping of hydrogen to customers who like the idea of using efficient, emissions-free fuel cells but traditionally haven’t been able to procure the hydrogen to power them. Plug Power installs its fueling dispensers and other gear on-site and trucks in hydrogen as needed.

So far, that strategy is catching on with big retailers such as Walmart and Kroger, which are switching over to fuel cells from Plug Power to operate forklifts at their distribution centers. Forklifts so equipped can run almost constantly, says Plug Power president Andy Marsh, allowing for more-efficient operation than battery-powered forklifts, which have to either recharge for hours or swap out batteries to keep going. Turning to hydrogen isn’t cheap, but for large industrial sites that can fuel hundreds of forklifts from a central location, the economies of scale can pay off.

Clearly, warehouse forklifts represent a fairly small and specialized market for fuel cell adoption. But Marsh sees expansion possibilities elsewhere. One juicy market he’s targeting: Next-generation cell phone towers, coming on line in a few years, that will need a portable energy source because they won’t be connected to the electric grid.

Meanwhile, cars powered by fuel cells are quietly making some inroads in the electric car market, even as batteries get most of the attention. The basic knock on battery-powered cars — that they can’t drive very far before needing a lengthy recharge — doesn’t apply to fuel-cell-powered vehicles, or FCVs. A quick hydrogen fill-up allows for hundreds of miles of emissions-free driving.

If you can find a hydrogen fueling station, that is. Such stations are starting to pop up in California, which has led Toyota to prepare the first FCV you’ll be able to buy in America. Called the Mirai, it’s a compact sedan with a driving range of up to 300 miles, running on hydrogen in a carbon fiber tank that Toyota calls “durable” and “incredibly solid” (probably to assure potential buyers that the car won’t go the way of the hydrogen-filled Hindenburg zeppelin).

With enough hydrogen fueling stations (California is shooting to have 100 by 2020), the Mirai or a car like it could be the anti-Tesla electric car: One you can refuel in five minutes from a pump and then drive across a medium-size state without being afraid of getting stranded with a dead battery. As an added bonus, Toyota says the onboard fuel cell could even act as an emergency power source for a home during blackouts. (It’s not yet clear if that feature will be available on U.S. models.)

Backup Power, the Old-Fashioned Way

Of course, there’s a far simpler way to power your home or business during a blackout: An emergency generator. Small, portable units running on gasoline can keep the lights on in a pinch, and larger, stationary generators burning propane or natural gas can power your whole building automatically when grid power goes down.

Sales of emergency generators have been a bit soft lately, says Clement Feng of Generac, a major generator supplier. But that’s largely due to the absence of major hurricanes and associated blackouts in recent years, he adds; folks who haven’t dealt with that headache in a while tend to be less eager to invest in a generator. It takes only “one big storm” to ramp up demand, says Feng.

Meanwhile, Generac is doing brisk business selling large, trailer-mounted generators fueled by natural gas to oil drillers. Well-site equipment requires a lot of electricity, and gas-fired generators are a good solution in the many parts of the oil patch where natural gas comes up the well as a by-product of oil production. Much of that gas has traditionally been flared off as a waste product, even as drillers hauled in costly diesel to run pump jacks and other gear.

In the aftermath of Hurricane Sandy in 2012, we spoke with Jim Baugher of online power equipment retailer Power Equipment Direct to find out what folks should know if they are in the market for a generator (as many in the Northeast were when Sandy took down much of the grid).

Among his recommendations:

  • Have an electrician assess the power needs of your home or business so you can buy a generator that handles the job without going overboard. An electrician can also install the wiring needed to automatically route the generator’s power to essential equipment — your fridge or furnace, say — without having to run extension cables.
  • If buying a portable unit, you’ll want one with pneumatic wheels for easier movement; a battery for easy start-up; and a voltage regulator. If you’re interested in a large, stationary backup unit, first consult a building inspector to make sure your intended site won’t run afoul of local building codes.

Generator costs can vary substantially, depending on your power needs. Generac’s Feng says buying and installing Generac’s largest standby generator — a 22-kilowatt unit — generally runs $7,000 to $8,000. The company’s smallest standby model puts out 7 kilowatts and costs about $1,900 before installation.

Energy Alerts, June 3, 2015

The boom in shale oil and gas isn’t just unleashing a flood of new energy sources in the U.S. It’s also driving a massive build-out of the nation’s energy-carrying infrastructure, which is needed to bring that big bounty of crude oil and natural gas to market. At the same time, big changes for the electric grid mean utilities are investing heavily in new transmission lines to make sure your lights stay on.

Pipes, Tanks and Trains

The growth in oil output alone is taxing the energy industry’s carrying capacity. Though it briefly leveled off this winter when prices plummeted, crude production is on the rise again. By the end of the year, there’s a very good chance U.S. output will eclipse the record of roughly 10 million barrels per day, set in November 1970. Moreover, drillers are also tapping significant amounts of ethane, propane and other liquid petroleum.

Getting that gusher of oil from wells in N.D. and Texas to refineries on the coasts calls for more pipelines, more rail tanker cars and more storage depots. Last year, market research firm Industrial Info Resources tallied proposed pipeline projects that would be capable of moving a combined 8.2 million barrels per day — almost matching today’s 9.5 million barrels of daily output — and cost tens of billions of dollars to build. Most of that new construction figures to be in the Midwest.

IIR also identified proposed storage depot projects that would provide more than 80 million barrels of capacity, most of them in the West and Southwest. Firms such as Enterprise Products Partners and Kinder Morgan are betting on a mounting need for more storage tanks, especially after the big rise in crude oil stockpiles this winter sparked concerns that storage space would run out and helped push oil prices down.

Much of the surge in oil production isn’t getting to refineries by pipeline; it’s coming by rail. In North Dakota — the second-biggest oil-producing state (Texas is first) — rail is crucial to serving the mushrooming oil wells pumping crude from the Bakken Shale formation. But because this crude can be volatile and prone to exploding during train derailments, federal regulators are requiring the energy industry to upgrade or replace thousands of older rail tanker cars deemed unsafe for shipping crude (or ethanol, another volatile fuel).

How those regulations affect the crude-by-rail business remains to be seen. But the oil industry is clearly not happy with the mandate to overhaul or replace what a study by the Brattle Group estimates could be 30,000 rail tanker cars. American Petroleum Institute spokesman Brian Straessle said in a May 8 interview that the group, which represents oil and gas producers, was still reviewing the Department of Transportation’s new rules, but called them “very difficult” to implement. He questioned whether the rail industry has the ability to deliver so many new or upgraded tanker cars on the tight schedule regulators are requiring. Three days later, API filed a lawsuit against DOT to block the rules.

A slew of orders for new tanker cars figures to benefit manufacturers such as Trinity Industries, Union Tank Car Co. and the Greenbrier Cos. But DOT’s crude-by-rail rules pose challenges for those companies, too. In particular, car makers worry about the government’s mandate that tanker cars eventually adopt electronically controlled pneumatic brakes to prevent future derailments. The Rail Supply Institute, which represents car makers, argues that ECP is an expensive technology that does little to enhance safety.

While oil production draws near its all-time high, natural gas output is already breaking records. Gas production set a new high in December of last year and is likely to eclipse that record before long. Meanwhile, gas demand is also building (as we wrote two weeks ago). New supply and new demand spell many new gas pipelines crisscrossing the country.

The Federal Energy Regulatory Commission, which approves applications to build interstate gas pipelines, is tracking a bevy of proposed gas lines to keep up with supply and demand. All told, FERC data show enough pending pipelines to move about 15 billion cubic feet of gas per day — equal to about 20% of current gas usage. Major builders include Transcontinental Gas Pipe Line Co. and Energy Transfer Partners.

Power Lines

Meanwhile, electric utilities are pursuing more transmission capacity. Unlike for the oil and gas industries, the challenge for utilities isn’t moving more of the commodity they produce or sell; it’s rerouting power on the electric grid from new generating stations — as old coal-fired power plants close and gas-fired plants replace them — and coping with the ebbs and flows of highly variable wind and solar power.

That means more high-voltage power lines throughout the U.S. From now through 2017, electric utilities plan to spend nearly $20 billion per year on new transmission lines, according to the Edison Electric Institute, a utility trade group. Some big spenders include Entergy Corp., Southern Co. and Southern California Edison.

Many utilities will also be shelling out more for large batteries to store excess energy during periods of low demand and quickly deliver it to customers when demand jumps — good news for battery firms such as Panasonic, Toshiba and NEC Energy Solutions.

A Note on Oil Statistics

Readers sometimes ask about the best sources of information on oil production and consumption, and of other statistics. The Department of Energy’s Energy Information Administration publishes a wide variety of reports on these topics; so wide, in fact, that it can be a bit overwhelming.

Perhaps the single most informative snapshot of the U.S. oil industry appears on Wednesdays, when EIA publishes its Weekly Petroleum Status Report. The Status Reports Highlights are a handy summary that runs down total petroleum consumption for the previous week, along with the rise or fall in stockpiles of crude and gasoline; how close to full capacity the nation’s refineries are operating; and how much gasoline and diesel refiners churned out that week. The Data Overview is even more informative, with details on oil production and refinery activity by region.

But note that EIA’s weekly report of crude oil output is based on an estimation and isn’t as accurate as the monthly figures the agency puts out. This winter, the weekly updates were pegging daily U.S. oil production at 9.1 million to 9.3 million barrels. But in hindsight, the monthly report quotes output at 9.4 million barrels in January and February. EIA publishes the monthly figures with a two-month lag, but given their greater accuracy, they’re worth waiting for.