Can OPEC cap production and prop up oil prices?

The latest jolt to the always volatile oil markets: Talk coming out of OPEC about a possible move to tighten supplies, which has set off a bit of a rally in crude prices. But does the talk add up to much? And are there any other reasons to bet on (or against) a longer-term upward move in oil?

An OPEC Production Cap. Maybe.

One of the biggest subplots to the recent swoon in oil prices has been OPEC’s seeming inability to prop up prices by getting excess supply under control. Historically, the group would act to rein in its production when global oil markets were oversupplied, and open the taps when world oil demand was climbing. But when OPEC announced in November 2014 that it wouldn’t curb output in response to falling prices, the decline became a rout. Since then, the cartel has seemed either unwilling or unable to cut output, probably out of fear that producers in the U.S. and elsewhere would take advantage by pumping more and stealing OPEC’s market share.

Last week brought a glimmer of hope for oil bulls looking for OPEC to act. Member nations Saudi Arabia, Venezuela and Qatar joined nonmember Russia in a proposal to collectively cap production at current levels. So, not a cut, but a possible first step toward one later, right?

But the proposal to cap output comes with key caveats. First, the Saudis and their colleagues said the plan depends on other big exporters, such as Iraq and Iran, getting on board. Winning over Iran seems to be a tough proposition. The recent end to Western oil sanctions against the country has allowed Iranian oil to flow more freely again, and Iran has announced its intention to ramp up exports to take advantage.

Reaching an agreement and sticking to it will be hard. Will Iran do an about-face and agree to hold exports in check after enduring years of punishing sanctions that are finally gone? Especially when doing so requires cooperation with archrival Saudi Arabia? We’re skeptical, and we’re not alone. OPEC “will freeze [oil output] when I see icebergs floating in the River Styx,” says Stephen Schork, editor of energy market newsletter The Schork Report.

What’s more, even if OPEC does cap production, that’s a far cry from what’s needed to really bolster oil prices. Capping output at today’s booming levels would ensure that supply continues to exceed demand for months to come. At current supply and demand levels, the International Energy Agency expects global stockpiles of stored crude to increase by 285 million barrels over the course of 2016, on top of the billion barrels added during 2014 and 2015. That calculation suggests that the world’s daily oil output needs to fall by close to 1 million barrels to stop adding to already swollen stockpiles.

A Silver Lining for Bulls

Color us skeptical that OPEC is ready to ride to the oil market’s rescue. We have said before that the cartel might eventually act to cut (not cap) production, but only if prices fall sharply enough to convince Saudi Arabia and Iran that joint action is preferable to even more financial pain.

But there is some reason to believe that global oil production will eventually slow. You’ll find it happening in Texas and North Dakota, not the Middle East. Precisely tracking the amount of oil produced in the U.S. every day is notoriously difficult, but the Department of Energy’s weekly reports are pointing to a downward trend. Over the last month, DOE’s tally shows daily U.S. output fell by 100,000 barrels.

Admittedly, it’s probably too soon to declare that domestic production is really starting to wane. After all, many forecasters (Kiplinger included) expected production to take a bigger hit than it did in 2015. The price slump caused a sharp drop in drilling activity, raising expectations that output would soon follow. But after hitting a peak of about 9.7 million barrels in April of last year, daily production saw only a slight decline. Even though operators were running fewer rigs, they were scrambling to pump more oil from each well they did drill. That improvement in efficiency helped keep many in business, and also prevented nationwide output from falling very much.

Perhaps the U.S. industry has reached a tipping point, in which improvements in drilling efficiency are no longer enough to compensate for so few new wells being drilled. If so, total output might decline by enough to really put a dent in the worldwide supply glut. Even if that plays out, the U.S. would remain a production powerhouse. But taking a few hundred thousand barrels of daily output off the market would do a lot more than any OPEC production freeze to boost crude prices.

Still, any price rebound is going to take time. Both around the world and in the U.S., storage tanks keep filling up with crude and refined products. Since the start of the year, crude stockpiles here have jumped by almost 22 million barrels and now stand at their highest level on record in DOE data going back to 1982. Gasoline in storage is also at a record high, suggesting that demand from motorists isn’t exactly robust at the moment.

If storage tanks get much fuller this winter, oil prices could take another step down. We tend to think such a decline would be brief, because it would almost certainly idle even more drills and cause production to shrink faster. But for an industry that’s already suffering from low prices and struggling to secure credit from lenders, even a short-term plunge would be extremely painful.

A Note on the Clean Power Plan

A number of readers have recently asked about the outlook for the Environmental Protection Agency’s Clean Power Plan, which aims to require electric utilities to cut back their emissions of carbon dioxide. The Supreme Court took the rare step of ordering a halt to the regulations while it waits for the opportunity to rule on their legality. And now, with the death of Justice Antonin Scalia, the fate of the plan is even less certain.

In our next issue, we’ll be looking at the CPP’s legal status and its odds of being implemented as written. While the gyrations in the oil market demand attention, it’s only one of many big stories playing out in the energy world so far in 2016.

 

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Guess which industries aren’t happy about cheap oil

It’s impossible to miss all the headlines these days about the crash in energy prices and the damage it is doing to the balance sheets of firms in the oil, gas and coal businesses. But the ripples from the price plunge extend beyond the coal miners and ExxonMobils of the world. A slew of industries tied to the energy world are also suffering, with little relief in sight.

Off the Rails

Few sectors of the economy benefited more from the surge in U.S. oil production than freight railroads and their suppliers. With so much new crude coming out of the ground (often in parts of the country not connected to oil pipeline systems), rail suddenly became a critical conduit for linking shale fields in the interior to the nation’s coastal refineries. Moving crude by rail costs more than moving it by pipeline, and derailments have sometimes led to catastrophic accidents. But oil trains can go where pipelines don’t, and they give refiners the flexibility to source crude from different suppliers as prices fluctuate.

Now, not so much. Slipping oil output in North Dakota means less demand for the rail tanker cars that were needed to haul crude from the Bakken Shale to market. Meanwhile, with new pipelines coming on line, less of the state’s output is traveling by rail. From a peak of more than 800,000 barrels per day hauled by rail in December 2014, producers in the Peace Garden State now rely on oil trains to haul slightly more than 500,000 barrels per day, according to statistics from the North Dakota Pipeline Authority. Nationwide, the number of railcars carrying crude and refined products has fallen from a peak of about 16,000 in mid-2014 to fewer than 13,000 today, according to the Association of American Railroads.

And it’s not just fewer tanker cars riding the rails. Less drilling means less need to haul drilling equipment, supplies and materials to job sites. Which helps explain why freight railroads in January saw a 10% year-over-year drop in shipments of crushed stone, gravel and sand, a category that includes the sand used by the oil and gas industry in hydraulic fracturing. (More on sand miners’ woes later.) Meanwhile, the huge drop in coal burned to generate electricity that we’ve noted in the past is also affecting railroads, which are moving far less coal than they did several years ago.

It all shows up on railroads’ bottom lines. Union Pacific, for instance, reported a 19% drop in operating income for the fourth quarter of 2015 compared with a year earlier. Even though UP hiked its freight rates, and even though cheap diesel fuel helped cut costs, the decline in freight volumes still dragged down earnings. Until the economy shows more pep and steams up demand for shipping of consumer goods to offset the weakness in commodities hauling, we don’t see much bounce for rail freight volumes.

Sand Storm

Low oil and gas prices spell less drilling activity. And less drilling activity means less demand for a basic ingredient in fracking: Sand. Energy firms inject many tons of round grains of sand down their wells to prop open the cracks in energy-bearing shale and other rock layers that fracking opens up. The surge in drilling activity in recent years has been a boon for companies that mine the grades of sand that energy companies favor.

But now, with rig counts dropping and sand usage falling, those miners are under intense pressure. Hi-Crush Partners, a major frac sand producer based in Texas, is shedding workers and cutting other costs to cope with falling sand prices and demand. The company, organized as a master limited partnership, has nixed its dividend to conserve cash as its unit price has slumped from $40 last spring to about $5 today. My colleague, Jeff Kosnett, who edits Kiplinger’s Investing for Income, says that investing in sand producers is far too risky given the weakness in oil and gas prices and the stress that sand miners’ customers in the energy business are under now.

There is one bright spot for frac-sand, though: Energy firms are using more of the stuff in each well they drill because doing so results in more oil and gas output per well. That’s not enough to keep demand from falling right now, but eventually, when energy prices rebound and drilling activity perks up, it should bode well for the miners that can survive the current downturn.

Construction Woes

The downturn in the price of oil, gas and many other commodities also hits makers of the machinery needed to dig the stuff out of the ground. Perhaps no company better illustrates this trend than Illinois-based Caterpillar, which saw revenues tumble by 15% in 2015 from the previous year. CEO Doug Oberhelman says that the company’s energy and transportation division, which includes the company’s sales of products to the energy industry, saw new orders drop by 90% last year.

Cat doesn’t see things turning around in 2016, either. The company projects that revenues will drop an additional 10% this year because of weak commodity prices that are weighing on its customers in the commodity world, and because of slowing growth in key emerging markets such as China. Other makers of earthmoving and mining equipment are probably sweating the same worries right now. Indeed, many emerging markets (think Brazil, Australia, South Africa, etc.) are geared heavily toward mining or energy production, or both. Don’t count on any of them to be ordering many bulldozers or backhoes anytime soon.

Will La Nina save natural gas?

Oil and natural gas prices remain in the doldrums, and the odds of an immediate turnaround look long indeed. But with these volatile markets, you can never say never. And while unlikely in the short term, there are a couple of wild card factors that could give energy markets a lift later this year.

Natural Gas: La Niña to the Rescue?

The price of benchmark natural gas futures fell to $1.75 per million British thermal units (MMBtu) in December, the lowest level since 1999. (No, that’s not a typo. The last time natural gas was that cheap, Bill Clinton was president and no one had ever heard of a smartphone.) Gas prices have been hammered by the climate phenomenon known as El Niño, a marked warming of the Pacific Ocean that often brings unseasonably mild winter weather to much of the eastern U.S.

El Niño showed up in a big way this season. Christmas Day in the nation’s capital saw temperatures flirting with 70 degrees, for instance. And that meant that demand for natural gas (which heats half of homes in the U.S.) all but disappeared. And now, even with colder weather in place and a crippling snowstorm hitting the Mid-Atlantic, gas prices haven’t rebounded much. Heating demand is up, but not enough to really dent the massive stockpiles of gas that built up during winter’s warm start.

So while we don’t expect gas prices to retest their December lows, we also don’t see much upward momentum yet. At $2.21 per MMBtu now, the benchmark gas price could creep up to about $2.50 if the latter half of the winter turns out to be chilly. That’s still painfully low for gas producers.

To mount a real rally, the gas market is going to need some help from Mother Nature, in the form of heat, not cold. Specifically, a switch from El Niño to La Niña could do the trick.

Why La Niña? The opposite effect of El Niño, La Niña involves a cooling of Pacific waters that can cause warmer-than-average summer temperatures in the U.S. For instance, the last La Niña cycle, which ran from 2010 to 2012, coincided with three consecutive scorching summers. And hot summers mean soaring electricity demand as homes and businesses across the country rev up their air conditioners.

There’s no telling what the weather will be like in six months. But some signs are starting to point toward a switch from El Niño to La Niña. Australia’s Bureau of Meteorology, for instance, says El Niño is already waning, and that there’s a 50-50 chance of La Niña taking hold later this year.

A hot summer would be sure to give gas prices a jolt. Now more than ever, U.S. power generation depends on gas as a fuel. As we’ve noted before, coal’s role in powering the grid is shrinking, and gas is filling the gap. The Department of Energy reports that, since January 1, the electric sector’s gas usage is at an all-time high, rising further from the annual record set in 2015. And unlike in previous winters, when severe cold caused power demand to rise, the temperatures this year have been fairly typical. That means demand is rising for the simple reason that coal-fired power plants are shutting down and gas-fired units are taking their place.

A summer heat wave would cause gas consumption by utilities to soar to even higher records. That would whittle down gas stockpiles and give traders a reason to bet on higher prices. At the same time, demand for U.S. gas will be heating up abroad. The DOE figures that America, long a net importer of gas, will flip to a net exporter by the middle of 2017, thanks to increasing sales to Mexico via pipeline and the beginning of shipments of liquefied gas to markets such as Europe and Asia.

With weather trends, there’s never any certainty. But if you’re looking for a scenario in which natural gas prices finally climb out of the basement, La Niña looks like your best bet.

Oil: The Geopolitical Angle

Perhaps the most remarkable aspect about crude oil’s price tumble is the fact that it took place amid tremendous chaos in the Middle East. Syria’s civil war rages on unabated, as does Libya’s. ISIS continues to control vast swaths of territory. Iran and Saudi Arabia are rattling their sabers at each other across the Persian Gulf. And yet, nothing seems to scare oil markets enough to give prices a lift.

But how long can the lull in geopolitical risk last? Every major oil exporting nation is hurting from the drop in crude prices from nearly $100 per barrel to $30 per barrel. From Russia to Brazil, the economic pain is palpable. Venezuela is facing outright economic collapse, with inflation in triple digits.

So far, OPEC and other big exporters have failed to agree on output cuts needed to bring balance to an oversupplied world oil market. We’ve noted before that such a coordinated response will be very difficult to pull off.

Perhaps the pain is finally getting bad enough to galvanize OPEC to act. The cartel’s secretary-general, Abdalla Salem el-Badri, said recently in a speech in London that the world’s oil exporters need to coordinate a production cut in order to stabilize prices and ensure sufficiently high prices to finance the drilling needed to meet future crude demand.

Ultimately, the group’s de facto leader, Saudi Arabia, would have to approve such a strategy. And the Saudis have been reluctant so far to cut unless other exporters join them. Which is why it’s noteworthy that Leonid Fedun, vice president of Russian oil giant Lukoil, said in comments to news agency Tass that Russia would be open to a coordinated supply cut. Russia is the world’s largest crude producer, so its cooperation in any such strategy would be crucial.

We wouldn’t bet on this scenario just yet. But we might if and when oil prices take their next tumble. A drop from $31 per barrel to, say $25 or $20 would probably focus a lot of minds in Riyadh, Moscow and other petro capitals.

Coal: It’s the pits for 2016

The gloomy headlines about sinking oil prices never seem to end. But crude oil isn’t the only fossil fuel caught up in a bear market these days. Coal prices have also been sinking. And the long-term outlook for coal arguably looks a lot worse than that of oil.

More Financial Pain in Coal Country

Monday brought the latest news of a U.S. coal mining company filing for bankruptcy protection: Arch Coal, a longtime giant of the industry. Arch is looking to follow the path recently taken by other coal producers, such as Walter Energy and Alpha Natural Resources, all of whom have been hurt by the roughly 50% drop in U.S. thermal coal prices that began in 2011.

The reason for the industry’s downturn is simple: Falling demand. Long the mainstay of the U.S. electric grid, coal has seen its dominance upended by a combination of tough new federal regulations on air quality and carbon dioxide emissions as well as fierce competition from cheap and abundant natural gas. Up until the Great Recession, the U.S. consistently burned about 1.1 billion tons of coal annually. And as recently as 2005, coal fueled about half of America’s electricity.

Coal’s woes snowballed in 2012. Demand dipped in 2009 as the overall economy suffered, but then staged a small rebound as GDP growth picked up and power demand recovered. It was only in 2012 that coal consumption nose-dived, with demand slumping to a bit less than 900 million tons. Utilities were gobbling up cheap natural gas and contemplating the Obama administration’s looming regulatory crackdown on power plant pollutants such as mercury. Since gas was both inexpensive and burns cleaner than coal, the shift made both economic and legal sense. (Continued below.)

Fast-forward to 2015, which will go down as coal’s worst year in about three decades. Government statistics on usage for the full year aren’t in yet. But through the first nine months of 2015, coal consumption fell by 10% from the same period of 2014. That puts 2015 on track to see the lowest level of coal use since about 1985. Ouch.

Things won’t get better for coal in 2016. Odds are they’ll get worse. Why? Utilities are still decommissioning older, coal-fired power plants as they prepare for implementation of the Environmental Protection Agency’s Clean Power Plan, which seeks to reduce carbon dioxide emissions. States, which are responsible for meeting emissions reduction targets set for them by the EPA, will have a number of options for doing so. One major strategy figures to be shifting away from coal-fired electricity because burning coal emits more carbon dioxide per unit of power produced than burning natural gas does.

Don’t count on overseas demand to bail out U.S. coal miners. Though many countries continue to depend heavily on coal for power generation, it’s not clear that their consumption will grow enough to make shipping more of America’s coal abroad cost-effective. China, the biggest coal consumer by a long shot, raises particular concerns about future coal demand. Its economy is clearly slowing (though by how much no one seems to know), and the air pollution in China’s big cities is well documented. A cooling industrial sector means less need for coal-fired power. And cleaning up the dirty skies in Beijing and elsewhere probably means burning less coal in the long run.

Indeed, the International Energy Agency has turned notably pessimistic about the outlook for coal consumption. In its 2015 global coal market report, published last month, the energy watchdog projects that total demand will edge up by an anemic 0.8% annually in coming years. The IEA even considers it possible that Chinese coal usage has already peaked and will fall over the next several years, which would cause global consumption to actually shrink slightly. Just one year ago, the IEA was predicting strong demand growth, both globally and in China.

U.S. coal exports are already skidding. We see no reason to bet on a turnaround. Through the first half of 2015, America exported 20% less coal than during the same period of 2014. And that was before Chinese financial markets started signaling a worrisome slowdown there in August. Again: Ouch.

The bottom line: Coal’s long-term future looks increasingly bleak. The oil markets are in turmoil right now, but at least global demand for oil is still growing at a modest pace. Unlike oil, which is the dominant fuel for powering all manner of vehicles, coal faces mounting competition in its chief role of generating electricity. Utilities now derive as much electricity from natural gas as they do from coal in the U.S. And it’s not hard to imagine a future where renewable power becomes more competitive with coal, both here and abroad.

A Note on Fuel Cells

An alert reader recently queried us as to why Congress opted not to extend the 30% federal tax credit for hydrogen fuel cells when lawmakers acted to extend tax breaks for solar power. We sought an answer from the Fuel Cell and Hydrogen Energy Association.

FCHEA President Morry Markowitz called the omission of fuel cells in the year-end deal an “inadvertent error,” one that his group is pushing lawmakers to rectify early in Congress’s new session. Extending the expiration of the 30% tax credit from the end of this year to the end of 2019 “will get done sooner rather than later,” he predicts.

There’s no way to know for sure what lawmakers will do. But assuming the fuel cell industry belatedly gets the same treatment that solar power did, that would be a real boost for hydrogen-based power. Of the top 100 firms that make up the Fortune 500 list, 23 use fuel cells in some capacity, for either backup or primary power generation. That’s a number we expect to see climb, especially if Congress locks in the federal tax credit for fuel cells for a few more years.

How will year-end curveballs affect the energy industry?

Congress throws the energy world some year-end curveballs. And are natural gas traders forecasting a change in the unseasonably warm weather that has been entrenched across the Eastern U.S. this season?

Energy Policy Changes

Where did that come from? In the waning days of 2015, lawmakers managed to agree on not one, but two major energy policy changes: Provisions lifting the 40-year-old ban on exporting U.S. crude oil were included in legislation to keep the federal government funded. The legislation also included an extension of the tax credit for renewable energy systems that was scheduled to expire at the end of 2016.

Nixing the ban on crude exports is a major win for the U.S. oil industry, and one that we frankly didn’t think would happen this year. Sure, the House of Representatives had passed a bill OK’ing exports this fall. But the White House was steadfastly opposed, so we figured any deal would have to wait.

Suddenly, American energy firms have unfettered access to world oil markets. Though still an importer of oil, the U.S. is producing lots of light, sweet crude that many refiners overseas prize. As production climbed in recent years, benchmark West Texas Intermediate (WTI) crude traded at a discount to Brent, the primary global crude benchmark, since WTI oil was largely trapped within the lower 48 states. In the wake of the ban being lifted, WTI and Brent have converged as markets anticipate the freer flow of oil across borders.

But the policy shift probably won’t have a major impact on U.S. energy firms in the near term. World oil markets remain oversupplied, even as Iran gears up to start exporting more oil once Western sanctions on its oil industry are lifted. So there probably isn’t an urgent need for crude from Texas or North Dakota overseas just yet. And we’ve heard that shipping out significant amounts of U.S. oil will require some new infrastructure to be built along the Gulf Coast first.

In the long run, look for the flow of oil into and out of the U.S. to increase as producers send more barrels of their light, sweet crude to refiners in Asia, Latin America or Europe, where they are designed to process that variety of oil, and as refineries here bring in more of the heavier, sour grades of crude that they can handle most efficiently. Expect net imports (imports minus exports) to keep declining over time, continuing the trend of recent years.

A Boon for Wind, Solar

Lifting the ban on crude exports wouldn’t have happened so quickly without a similar boost for the renewable energy industry. Congressional Democrats and the White House ultimately signed off on the end of the crude ban because they were winning a similarly weighty concession: Extended tax credits for wind and solar power. Originally scheduled to disappear or phase out after 2016, the 30% federal tax credit for solar projects will remain in place through 2019 and then gradually decline. The lapsed producer tax credit for wind turbines was revived and extended through the end of next year.

The new tax policy almost certainly guarantees a lengthy build-out of solar capacity. With the solar credit set to drop off after 2016, we were figuring on a huge rush of building next year as homeowners, businesses, utilities and investors scrambled to qualify for the 30% credit. That would probably have led to a dearth of new projects in 2017. Now, the pace of new installations promises to ramp up steadily, with no sharp peak and no big crash.

A Change in the Weather?

Trying to predict what this volatile winter will do next is almost impossible. But natural gas markets are signaling a cold trend. After plummeting to its lowest level in more than a decade, the benchmark gas futures contract rebounded sharply this week, from less than $2 per million British thermal units (MMBtu) to more than $2.20 per MMBtu. That’s still quite depressed, but the recent uptick suggests that traders expect heating demand to perk up. Cities in the Northeast that were basking in the 70s in recent days are now expecting temperatures that are a bit more seasonal.

We wouldn’t recommend that investors try to time the gas market, which is certain to remain extremely jumpy. This winter has already seen record warmth, heavy snow in the West and deadly floods and tornadoes in the South. There’s no telling what will come next, which will make predicting heating demand for natural gas a challenge.

Still, if the balmiest weather of the season does prove to be behind us, there’s a decent chance that the lows for natural gas prices are behind us, too.