Should the US Energy Future Depend on Cheap Solar Imports?

The pending administration decision on whether to impose a tariff or other fee on US imports of solar equipment from China raises serious concerns. The right choice in this case is less obvious than suggested by the jobs and free-trade arguments from the main US solar trade association (SEIA) or the Wall St. Journal's editorial page. Solar power generates less than 2% of US electricity today. However, if it is to grow as experts forecast and advocates claim is essential, then considerations such as long-term energy security can't be ignored, while near-term job losses from a new tariff would be more than offset by subsequent growth.

Last October the US International Trade Commission issued its recommendations in favor of the complaint by two US manufacturers of solar panel components. I usually favor low tariffs and open access, especially when the markets in question are functioning smoothly and the principal impacts from trade are the result of "comparative advantage" in production or extraction between countries. However, there is little about the market for solar equipment, including the photovoltaic (PV) cells and modules at issue here, that qualifies as free.

The production and deployment of solar energy hardware has depended since its inception, and from one end of its value chain to the other, on significant government interventions. In the case of China-based PV manufacturing, these have included low-interest government loans, preferential access to land, and minimal environmental regulations. China-based PV manufacturers were also able to take advantage of extravagantly generous European solar subsidies in the 2000s to scale up their output, drive down their costs, and ultimately send much of the EU's solar manufacturing industry into bankruptcy.

On the US end, both solar manufacturing and deployment (installation) have benefited greatly from federal tax credits, cash grants from the US Treasury, and a web of state quotas for aggressively increasing utilization of renewable energy sources. Justified on grounds of energy security, "green jobs", and climate change mitigation, these measures have strongly promoted solar power and  delivered an extraordinary 68% compound annual growth rate in US solar installations since 2006. On a per-unit-of-energy basis, these supports are also at least an order of magnitude more valuable to the solar industry than the federal tax benefits received by the oil and gas industry.

One of the factors that makes this decision so difficult and politically sensitive is that a whole industry has apparently grown up around cheap solar imports, to the point that the main solar benefit to the US economy today is from installation, not manufacturing. US companies and their employees build solar panel racks and other "balance of system" gear, finance rooftop and other solar projects, and construct these installations.

These companies could be at risk of losing business and shedding jobs, if a large tariff were imposed on imported solar cells, modules and panels. Those impacts might be less than feared, though, because the cost of the actual sunlight-converting PV hardware now makes up less than a third of total solar project costs. In other words, a tariff that doubled effective PV cost would drive up total solar costs to a much smaller degree, and least of all for residential solar, which has the highest total costs per kilowatt.

There's another important aspect of this debate that hasn't received much attention. If solar power is as important to our future energy diet as many think, then it should be no more desirable to become heavily reliant on China for our supplies of PV components than it did to depend on growing imports of Middle East oil. That was the main energy security issue for the US for the last 30 years, until the shale revolution unexpectedly reversed that trend. Relying on solar imports from China in the long run will be nothing like depending on Canada for the largest share of the petroleum the US still imports.

It also makes sense to address this situation now, before solar power has grown to 20% or 30% of the US electricity mix, and with the US economy near full employment, when those workers that did lose their jobs would have the best chance to replace them quickly.

From the start, the complaint of unfair competition lodged by Suniva Inc. and Solar World Americas--Chinese- and German-owned, respectively--has been derided as an effort to prop up a couple of marginal players at the expense of the much larger US solar-installation sector. That ignores the position of First Solar (NASDAQ:FSLR), a US-based PV manufacturer with $3 billion in global sales. The company is on record supporting the trade complaint. Of course they aren't a disinterested party; they stand to benefit from a tariff that would raise the cost of competing PV gear from China and elsewhere.

That's precisely the point of the complaint: strengthening US solar manufacturers, so that the growth of solar energy in this country doesn't end up like TV sets and other consumer electronics. There's more at stake, because PV isn't TV. If solar power becomes a major part of US energy supplies by mid-century, it will actually matter if we have a robust manufacturing base to drive its deployment, rather than relying on any one country or region for its key building block.

Could China's EVs Lead to Peak Oil Demand?

• China's decision on whether and when to ban cars burning gasoline and diesel could alter our view of how far we are from a peak in global oil demand.
• Even though the likely date of such a peak is highly uncertain, the idea of an impending peak could significantly affect investments and other decisions.

A few months ago the British government made headlines when it announced it would ban new gasoline and diesel cars, starting in 2040. That move, which apparently excludes hybrid cars, is further fallout from the 2015 Dieselgate emissions-cheating scandal.

Now it appears that China is preparing to issue a similar ban. With around 30% of global new-vehicle sales, China could upend the plans and economics of the world's fuel and automobile industries. However, it is less obvious that this would lead directly to the arrival of "peak demand" for oil, an idea that has largely displaced earlier thoughts of Peak Oil related to supply.

Some background is in order, because the two concepts are easy to confuse. Peak Oil, which gained considerable traction with investors and the public in the 2000s, was based on the undoubted fact that the quantity of oil in the earth's crust is finite, at least on a human time-scale. Its proponents argued that we were nearing a geological limit on oil production, and that quite soon oil companies and OPEC nations wouldn't be able to sustain their current production, let alone continue adding to it every year.

The presumption that such a peak was imminent has been pretty clearly refuted by the shale revolution, the first stages of which had already begun when Peak Oil was still fashionable. In fact, humanity has only extracted a small percentage of the world's oil resources. We continue to find both additional resources and new ways to extract more from previously identified resources. Global proved oil reserves--a measure of how much can be produced economically with current technology--have more than doubled since 1980, while production (and consumption) grew by 34%.

For that matter, many of the shale plays that today produce a total of more than 4 million barrels per day had been known for decades. Petroleum engineers just didn't see how to produce oil from them in commercial volumes and at a cost that could compete with other sources like oil fields in deep water.

The first mention I heard of "peak demand" was at an IHS investment conference in 2009, when supply-focused Peak Oil was still king. At the time, it was a novel idea, since only a year earlier, oil prices crested just short of $150 per barrel on the back of surging demand and, to some extent the expectation of Peak Oil, and were only tamed by the unfolding global financial crisis.

Peak demand proposes that consumption of petroleum and its products will reach its maximum extent within a few decades, and thereafter plateau or fall. Crucially, it doesn't depend on a single theory, but on a combination of factors that are easily observable, though still uncertain in their future progression: meaningful improvements in fuel economy, even for large vehicles; policies and regulations to decarbonize the global energy system in response to climate change; an apparent decoupling of GDP and energy consumption; and the rise of partially and fully electrified vehicles.

That brings us back to the implications of a ban on internal combustion engine (ICE) cars in China. Considering that China has accounted for roughly a third of the increase in global oil consumption since 2014, this has to be reckoned as one of the larger uncertainties about future oil demand. Even if we're only talking about the equivalent of a couple of million barrels per day of lost demand growth by 2030, OPEC's ongoing struggle to balance a market that has been oversupplied by less than that amount puts the potential impact for oil investment and economics into sharp relief.

China has every incentive to take this step. Its urban air pollution is on a scale that cities like London and L.A. haven't experienced since the 1950s or 1960s. The country's 2015 pledge to limit greenhouse gas emissions was a centerpiece, and arguably the sine qua non, of the Paris climate agreement. If that weren't enough, the country's dependence on oil imports is exploding in much the same way as the US's did in the early-to-mid 2000s.

Perhaps I'm cynical to think that the last point weighs most heavily on China's policy-makers, just as US energy debates hinged on energy security concerns until quite recently. China's oil demand continues to grow, with over 20 million new cars and trucks reaching its roads each year, and the vast majority of them still needing gasoline or diesel fuel. Meanwhile, its oil production is going sideways, at best, as its mature oil fields decline.

Moreover, despite the country's large unconventional oil resource potential there does not seem to be a shale light at the end of their tunnel, because most of the conditions that supported the shale revolution here don't apply within China's state-dominated system. What it does have is plenty of electricity, and multiple ways to generate a lot more.

Let's concede that China's grid electricity, on which most of those EVs would be running, is among the highest in the world in emissions of both CO2 and local air pollutants. Switching China's new cars from gasoline and diesel to electricity won't constitute a big environmental win, initially or perhaps ever. Even under the relatively generous assumptions used in a recent analysis on Bloomberg, it will take the average EV in China 7 years to repay its extra lifecycle carbon debt, unless the country's electricity mix becomes much greener.

That seems realistic but almost beside the point, if China's main aim is to shore up its worsening energy security. Nor should we ignore the industrial-policy angle in such a move. China set out to dominate the global solar equipment market and can claim success, at least based on sales. If EVs catch on as many expect, the ultimate global market for them would be a sizable multiple of last year's $116 billion figure for global solar investment, only part of which relates to solar cell and module manufacturing, where China leads.

So let's assume 100% EVs is a given in China from some point in the next two decades. Does that spell the end of global oil demand growth in roughly the same timeframe? A number of recent forecasts, including those from Shell and Statoil, reached that conclusion even before the news about China's future car market.

It's not hard to envision this point of view solidifying into conventional wisdom, with interesting implications. Among other things, it could result in further cuts to investment in oil exploration and production that various experts including the International Energy Agency already worry could lead to another big oil price spike--well before EVs take off in a big way. It could also reduce R&D and investment in improvements to the conventional cars that will account for the large majority of car fleets and new car sales for some time to come, with adverse consequences for emissions.

When I consider these forecasts I'm struck by how early we are in this particular transition. Global EV sales are still only around 1% of global car sales, and petroleum products account for all but a small sliver of the global transportation energy market. As fellow energy blogger Robert Rapier recently noted on Forbes, "China is a long way from reining in its oil consumption growth."

Meanwhile, the nascent competition between petroleum liquids and electricity in transportation will occur against the backdrop of a much more complex reshuffling of the entire global energy mix. The current stage of that larger transition involves the rejection of coal and its replacement by natural gas and intermittent renewable energy: wind and solar electricity.

An excellent article by John Kemp in Reuters last week placed the shift away from coal in the context of a long sequence of historical energy transitions. As he noted, "Each step in the grand energy transition has seen the dominant fuel replaced by one that is more convenient and useful." Although there are other, compelling rationales for a move in the direction of electric vehicles backed by wind and solar power, it is extremely difficult to see that combination today in the terms Mr. Kemp used.

Pairing EVs with vehicle autonomy might create a product that is indeed more convenient and useful than current ICE cars with their effectively unlimited range and short refueling times. Perhaps it will require packaging self-driving EVs into mobility-on-demand services to beat that standard. It remains to be seen whether such a package would be technically or commercially viable, since even Tesla's "Autopilot" feature is still a far cry from such level 4 or 5 autonomy.

And even if EVs win the battle for car consumers with sustained help from governments, electricity is still an energy carrier, not an energy source. Renewables may go a long way toward replacing coal in the next two decades, but dispensing with both coal's 28% contribution to global primary energy consumption and oil's 33% in such a short interval looks like a massive stretch. Before the transition to EVs is complete, we may see at least some of them running on electricity generated by gas turbines burning petroleum distillates such as kerosene. (The environmental impacts of such a linkage would be significantly lower than running a fleet of EVs on coal.)

So while China's likely ban on internal combustion engine cars certainly looks like a key step on the path to peak oil demand, it could just as easily force oil producers to find new markets. That happened over a century ago, when a much smaller oil industry saw kerosene lose out to electric lighting and was farsighted or lucky enough to shift its focus to fueling Mr. Ford's new automobiles.

Peak demand for oil definitely lies somewhere in our future, regardless of China's future vehicle choices.  However, as a long-time practitioner of scenario planning, my faith in precise forecasts extrapolated from current facts and trends is limited. Whether we are close to peak demand or, as with a global peak in oil supply, continue to push it farther off, will remain subject to uncertainties that won't be resolved for some time. Our best indication of either peak--demand or supply--will come when we have passed it. However, the idea of an impending peak has shown great potential to affect markets and decisions in the meantime.

How Will Low Oil Prices Affect Natural Gas?

• The growth of US natural gas output in recent years has been sustained partly by gas produced in conjunction with shale or "tight" oil.
• The slowdown in oil drilling in response to lower oil prices could also affect future natural gas production, and thus prices, especially in the US.

Media coverage of energy has focused heavily on oil prices, lately, for understandable reasons. Oil's dramatic plunge and subsequent volatility would be newsworthy, even if petroleum weren't still our leading source of energy, especially for transportation. In this context, the dog that hasn't barked is natural gas, although oil and gas are still linked by common drilling hardware and often produced from the same wells. With oil drilling being curtailed in response to low oil prices, should we be concerned about natural gas supplies in the months and years ahead?

At first glance the answer ought to be a straightforward "no." As most people now know, US drillers figured out how to tap the country's vast shale gas resources economically. US gas production is at record levels, after rising steadily since 2006 and surpassing former top producer Russia around 2009. US natural gas inventories were severely depleted following last year's "Polar Vortex" winter, but output grew fast enough to keep the benchmark price of gas below $4 per million BTUs this winter, despite below-average temperatures east of the Mississippi. 

However, in assessing gas supply under low oil prices we must factor in the industry's response to the natural gas price collapse in 2008. The prices of oil and gas both dropped precipitously during the financial crisis, but gas didn't recover to the same extent as oil. In 2007 the average spot price of natural gas on an energy equivalent basis was just over half that of West Texas Intermediate crude (WTI). By 2010 gas was worth only a third as much as oil, and by 2012 just 17%--the equivalent of $16 per barrel in a world of $100 oil. Drillers responded accordingly.

As the Energy Information Administration (EIA) chart below depicts, drilling for gas fell sharply from 2009-12, while  "oil-directed drilling" rose just as sharply. In fact, these were mainly the same rigs, redeployed to pursue different targets--sometimes in the same shale basin--as gas grew cheaper.

 So shouldn't natural gas production have fallen in tandem with the decline in rigs drilling for gas? The extremely useful charts in the EIA's latest Drilling Productivity Report help to explain why gas output continued to climb. First, just as the increasing productivity of shale oil drilling has confounded expectations about how soon US shale oil production would begin to decline after prices fell below $50 per barrel, shale gas drilling productivity improved rapidly following the gas price collapse.

For example, between 2009 and 2012 average gas production per rig--not per well--in the mainly gas-yielding Marcellus Shale more than tripled. From 2012 -14 it doubled again. Those gains reflect the combination of improvements in drilling efficiency (more wells or more feet drilled per month), improvements in hydraulic fracturing effectiveness, and companies targeting more productive well sites as knowledge of the basin's geology increased.

A key development following the gas price collapse was the growth of gas production from wells drilled in pursuit of shale oil. The best example of this is in the Eagle Ford Shale in Texas. While oil production there grew from virtually nothing to over 1.7 million bbl/day, the region's gas output nearly quadrupled, to 7.5 billion cubic feet (BCF) per day, or 10% of total US gas production.

Now we've entered a new chapter, due to a global oil surplus. As of the latest drilling rig count from Baker Hughes, oil-directed rigs employed in the US have fallen by around 45% since November 2014, and gas-directed rigs are down  by a quarter. A few companies may have shifted from oil back to gas, but the overall rig trend is still down for both.

The net result is that the EIA expects oil production from the major US shale basins to remain essentially flat from March to April, while gas production should still grow by about 0.3%. How much farther would US shale oil and gas drilling have to contract before lower rig counts swamped productivity improvements for gas? Comparing those figures to the growth rates in previous months, perhaps not very much.

Of course the US represents only about a fifth of the global gas market. Elsewhere, especially in Europe and Asia, many gas sales contracts are pegged to oil prices, while supply is dominated not by flexible shale, but by large conventional gas fields and the trade in liquefied natural gas (LNG). So outside the US, lower oil prices may do more to stimulate gas demand than to shrink supply. Cheaper gas imports into China are apparently already having an impact on coal consumption.

That could create new opportunities for companies developing LNG facilities to export US gas, at the same time that the economics of such exports become more challenging. In markets like Asia, the effect of lower oil prices has cut the gap between landed LNG prices and US pipeline gas--and hence the motivation for exports--by more than half.

Even after oil's collapse, US natural gas at the Henry Hub has recently traded at about one-third of the price of WTI, per-BTU of energy. The contraction of drilling in response to low oil prices may tighten supplies and nudge the prices of both commodities higher, reminding us that gas isn't entirely immune to oil's influence. However, with US gas inventories ample, the market doesn't seem to anticipate either a spike in gas prices this summer, or a narrowing of gas's discount vs. oil any time soon.

A different version of this posting was previously published on the website of Pacific Energy Development Corporation

IEA Sees Fundamental Shifts in the Current Oil Price Drop

• The IEA's latest medium-term oil forecast is a useful update to the thinking behind its current long-term outlook, which predated much of the current price drop.
• They expect shale output to be relatively resilient and rely on Iraq's capacity to expand output in spite of significant security risks.

When the International Energy Agency issued its most recent long-term energy forecast last November 12th, Brent crude oil traded just above $80 per barrel. At that point it had fallen only half as far as it would by January 2015, compared to its June 2014 high of $115. As a result, the IEA's assessment of the price drop in its 2015 World Energy Outlook was incomplete, to say the least. The agency's Medium-Term Oil Market Report, issued in February, provides a necessary update and some interesting insights about how--and how far--they envision the oil market recovering.

Anyone expecting the IEA to provide a detailed oil-price forecast for the next five years will be disappointed. The current report reproduces recent oil futures price curves and generally endorses the consensus that prices won't rise as high as the level from which they have just fallen, at least by the end of the decade. At the same time, in the Executive Summary they remind their audience, "The futures market's record as price forecaster is of course notoriously mixed."  Six months ago West Texas Intermediate Crude for delivery in April 2015 was selling for around $90/bbl; yesterday it closed under $52. So much for the predictive power of futures markets, as most participants are aware.

The report's analysis of the factors influencing the oil supply and demand balance over the next five years is more useful. First and foremost, it recognizes that the factors contributing to this price correction bear little resemblance to the price drops of 1998 and 2008, and share only a few common threads with the big correction of 1986, chiefly involving OPEC's behavior. The biggest differences relate to the nature of the North American shale sector, which drove strong non-OPEC supply growth for the last several years, and the economic and policy factors--slowing growth in China, subsidy phaseouts, and currency depreciation-- likely to dampen the global demand response to cheaper oil.

With regard to shale, the IEA suggests that the current pressures on the US oil industry will prove temporary. They apparently expect the growth of unconventional production from both shale and oil sands to slow but remain the largest source of non-OPEC supply increases through 2020, outstripping increases in OPEC's capacity and offsetting declines elsewhere. Those declines include a 500,000 bbl/day drop in Russian production, mainly due to the effect of sanctions over Russia's involvement in Ukraine.

The agency even suggests that North American shale could emerge from this experience stronger, because of its inherent resiliency. The same factors that should see shale output slow sooner than that from big conventional projects taking years to develop would allow it to ramp up faster, once the current global oil surplus has been consumed. Meanwhile, with larger projects delayed or canceled, conventional production would take longer to return to net growth above normal decline rates. 

That could become the factor that dispels the current skepticism concerning shale oil opportunities outside North America, as apparently exemplified in BP's latest long-term outlook. Companies looking for growth opportunities in a few years might regard developing the shale resources of China, Argentina and Russia--assuming sanctions on the latter end--as lower-cost, lower-risk investments than some deepwater or other big-ticket projects.

As for OPEC, its production growth through 2020 seems to come down to a single country. The report assesses the current situation in Iraq and concludes that despite the threat from the Islamic State and the country's ongoing internal frictions, output should continue to grow by another million bbl/day or so. That strikes me as optimistic, particularly considering the proximity of ISIS forces to Kirkuk, which formerly accounted for around 10% of Iraqi production. Postwar development has focused on the big fields in southern Iraq, which have so far proved to be beyond the reach of ISIS, but a further deterioration of security in the Kurdish north could jeopardize future expansion plans.

The wild card on the supply side is Iran, which under international sanctions has seen its oil exports cut by roughly half. The Medium-Term Oil Market Report explicitly assumes that sanctions will continue. However, if current nuclear talks reached an agreement, sales could ramp up by a million bbl/day over the next year, if buyers could be found. That would alter the IEA's supply/demand calculations substantially.

And that leads us to demand, which at this point is still a key uncertainty. I concur with the report's general assessment that the world has changed since previous oil price drops and rebounds in ways that make a sharp rise in oil use less likely. US demand is up, but as I described in a recent post large groups of consumers around the world have seen little or no relief at the gas pump that might stimulate more consumption.

When I wrote about the IEA's World Energy Outlook last December, I focused on its themes of stress and the potential for a false sense of security. In the short time since then the oil and gas industry has experienced a large dose of stress, but I've seen few signs of complacency on the part of consumers beyond a recovery in the US sales of SUVs and light trucks. That may change if low oil prices persist for a few years.

A different version of this posting was previously published on the website of Pacific Energy Development Corporation

2014 in Review: Shale Energy's First Price Cycle

2014 was an extraordinary year in energy, vividly illustrating both sides of the Chinese proverb about interesting times. Oil market volatility was the big story for much of the year, with the dominance of geopolitical risks finally yielding to surging supplies. Of the two energy revolutions underway, shale wields the bigger stick for now, while the growth of renewables gathers momentum. All of this has implications for 2015 and beyond.

The US remained the epicenter of the shale revolution this year, with development elsewhere still subject to uncertainties about economic production potential, infrastructure, and the rules of the road. A comparison of oil-equivalent additions to US energy supplies from oil, gas and non-hydro renewables for the first nine months of the year highlights both the significance of shale and the differences in relative scale that impede a rapid shift to renewables.

US shale drilling added over a million barrels per day of "light tight oil" (LTO) production, compared to 2013, based on US Energy Information Administration data for the first nine months of the year. That brings cumulative gains since 2011 to nearly 3 million bbl/day. This hasn't just upended the global oil market; it has also revolutionized the way oil moves across North America. Over a million bbl/day now moves by rail, a figure recently projected to peak at 1.5 million by 2016. Nor is that entirely the result of delays to pipeline projects like Keystone XL. One proposed pipeline for Bakken LTO was reportedly canceled due to a lack of interest from shippers. Rail is expensive but provides producers and refiners with greater flexibility in both volume and destinations than fixed pipelines.

The collapse of oil prices has prompted many producers to reassess drilling plans, although it has been a boon for refiners and consumers.  Refining margins look relatively healthy, at least based on the proxy of "crack spreads", the difference between the wholesale prices of gasoline and diesel and the oil from which they are made. Some refiners also anticipate that low prices will spur demand growth, as described in a fascinating Wall St. Journal interview with Tom O'Malley, who has turned a succession of castoff refineries into profitable businesses. 

We may already be seeing the demand response to lower prices. November US volumes were at a 7-year high, according to API. This is unlikely to be replicated quickly elsewhere, however, for the same reasons that global oil demand was slow to moderate when prices rose over the last several years: In many countries the influence of oil prices on consumer behavior is overwhelmed by fuel taxes or subsidies. With prices now falling, some developing countries are capitalizing on the opportunity to unwind billions of dollars in consumption subsidies, offsetting market drops. That could have important implications for future oil demand and greenhouse gas emissions.

Meanwhile US consumers have watched retail gasoline prices fall by $1.39 per gallon since July and by over a dollar compared to a year ago. If sustained, the effective stimulus could exceed $100 billion annually, ignoring the effect of lower prices for jet fuel, diesel and other products. It's not surprising that half of respondents in last month's Wall St. Journal/NBC poll indicated this was important for their families.

While oil has been making headlines, shale gas without much fanfare added the equivalent of another half-million bbl/day to US production. That explains why despite enormous drawdowns of gas during last winter's "Polar Vortex", gas inventories began this winter much closer to normal levels than was widely expected in the  spring. Gas has lost a little ground in electricity generation to coal in the last two years, but few reading the EPA's proposed Clean Power Plan regulation would expect that trend to continue.

Shale gas remains controversial in some areas due to perceived environmental and community impacts. New York state is apparently making its temporary ban on hydraulic fracturing ("fracking") permanent, preferring to rely on shale gas supplies from neighboring Pennsylvania. Yet while shale drilling in North Dakota has led to an increase in gas flaring--burning off gas that can't economically reach a market--the latest findings from the University of Texas and Environmental Defense Fund measured methane leakage from gas wells at an average of 0.43%. That shrinks gas's emissions footprint and enhances its potential role in climate change mitigation.

Turning to renewables, wind energy now provides a little over 4% of US electricity. However, its growth has slowed due to uncertainty about continued federal subsidies. The wind production tax credit, or PTC, had previously been extended through 2013 in a way that allowed projects brought online later to benefit from the extension. It was just extended again through the end of 2014, along with a broad package of other expiring tax benefits. This late revival might be a gift to a few projects already under construction, but it seems unlikely to spur additional projects without further legislative action in the new Congress.

Solar power has also made great strides, with costs falling rapidly and US additions in 2014 expected to reach 6,500 MW, likely outpacing wind additions. This is happening despite the ongoing trade dispute between the US and China over imported solar modules. Utilities are already experiencing solar's impact on their traditional business model. Yet as important as wind and solar power are likely to be in the future energy mix, their impact in 2014, at least in the US, was still dwarfed by the growth of shale resources. Drilling is already slowing down, however, so renewables could take the lead in 2015 as shale is expected to post smaller gains.

Looking ahead, the global focus on greenhouse gas emissions will increase in the run-up to the Paris climate conference in December.  It remains to be seen whether enough progress was made in the recently completed talks in Lima, Peru, to resolve the significant remaining obstacles to a new global climate agreement. And while oil supply gains trumped geopolitics in 2014, a list of risk hot-spots from the Council on Foreign Relations includes several scenarios with major implications for oil and/or natural gas prices. Meanwhile we can expect the new Congress to take up Keystone XL, oil exports, EPA regulations, and other energy-related issues. I'd bet on another lively year.

A different version of this posting was previously published on the website of Pacific Energy Development Corporation.

The IEA's Stressful Outlook

• The latest long-term forecast from the International Energy Agency suggests that the benefits of today's low oil prices might be temporary, with more volatility ahead.
• The report focuses on a number of risks, including the adequacy of investment in both new oil capacity and low-emission energy, and the scale of nuclear plant retirements.

For an organization established by energy-importing countries in the aftermath of an oil crisis, the recent launch of the International Energy Agency's annual World Energy Outlook (WEO) took surprisingly little satisfaction in the current dip in oil prices, and none in the difficulties it is causing for OPEC.  Instead, the presentation  was peppered with terms  like "stress", "risk" and  "doubts",  and references to a "false sense of security" and a "stormy energy future." I see that as an indication of how much the global energy agenda has changed and broadened in the last decade or so.

For oil in particular, the IEA sees today's growth in North American production masking the consequences of the ongoing turmoil in the Middle East. In Iraq and other countries in the region, uncertainty is delaying investments that should be made now, if future supplies are to meet demand growth after US "tight oil" and other non-OPEC  expansion has plateaued. And that point could come sooner than expected if drillers reduce US shale investments by 10% next year, as IEA anticipates, or if the significant governance problems of Brazil's oil sector, which were only hinted at, are not resolved soon.

The launch covered several other areas, as well, none of which escaped suggested stresses of their own. Start with natural gas. IEA sees gas on its way eventually to become the "first fuel", consistent with the view of their "Golden Age of Gas" scenario of 2011. This would be driven in part by a large increase in LNG production from new sources such as East Africa, Russia and North America, along with growth from traditional LNG suppliers in North Africa and Australia. IEA expects increased competition from LNG with pipeline gas to improve energy security, especially in Europe, but not necessarily gas prices for end users. In fact, the high relative cost of LNG could impede the displacement of coal by gas in Asia. 

The presentation also highlighted the significant challenges IEA expects in the electricity sector in the period to 2040, a longer interval for which this year's WEO provides the first glimpse. A net expansion of global power generation by around 75% is more challenging than even that figure suggests, because it must incorporate the replacement of more than a third of today's generating capacity. As a result, only oil-fired generation will experience a net decline.  IEA forecasts up to half of new capacity through 2040 coming from renewables, on a scale posing significant risks for power system reliability, especially in Europe.

Nuclear power, a major source of baseload low-carbon electricity, is an area of special focus in this year's report, along with Africa. The expected growth of nuclear energy over the next several decades occurs mainly in the developing world, while 38% of today's nuclear capacity--nearly 200 reactors--will be retired by 2040. Many of those retirements will occur in Europe, and the Chief Economist of the IEA, Fatih Birol, expressed concern about the policies and budgets supporting such decommissioning on an unprecedented scale.

By 2040 the balance of nuclear power capacity would have shifted from around 80% in OECD countries and 20% in today's developing countries, to roughly 50/50. While the report also draws attention to the growing policy problem of nuclear waste disposal, it identifies nuclear as "one of a limited number of options available at scale to reduce CO2 emissions."

The largest source of stress in the report appears to be the disconnect between the narrowing window for reducing greenhouse gas emissions to a level that climate models indicate would limit global warming to 2°C, and the higher emissions inherent in the IEA's central "New Policies" scenario. Meeting the 2° target would require increasing average annual investments in low-carbon energy, including energy efficiency, by a factor of four compared to 2013. At last month's G20 summit in Australia we heard that "red warning lights are once again flashing on the dashboard of the global economy."  Could even the IEA's middle view of energy investments proceed if much of the world slid back into recession?

The presentation wasn't all gloomy, of course. Dr. Birol pointed out the competitive advantage that low energy costs confer on the US, and both he and IEA Executive Director Maria van der Hoevan highlighted the recent China/US emissions deal as a very positive development. (My own analysis concluded that it would still allow China's emissions to grow dramatically before peaking.) They also conceded that lower oil prices would provide oil-importing countries with some timely "breathing space."  And for the first time I heard that three out of four cars sold in the world are now covered by fuel economy regulations, suggesting increases in energy efficiency to come.

It also struck me that some of the negatives in the presentation might tend to cancel each other out. If the global oil industry, especially in the Middle East, fails to invest sufficiently in the next few years to ensure that supplies continue to grow in the 2020s, then the resulting higher oil prices could accelerate the transition to natural gas and renewables, while providing greater incentives for energy efficiency. That combination might reduce emissions sooner than IEA's main forecast indicates.

Last year the IEA's World Energy Outlook failed to anticipate the drop in oil prices; how many other forecasters likewise missed it? It featured some of the same big themes repeated this year, including the ongoing shift of the energy world's center of gravity toward Asia and the scale of the global emissions challenge. On a more basic level, however, a comparison of the two documents suggests that the agency is still trying to understand the transformation of global energy markets by the parallel shale and renewable energy revolutions. They aren't alone in that, either.

A different version of this posting was previously published on the website of Pacific Energy Development Corporation.

Keystone XL Loses Another Round

The image that will stick with me from yesterday's failed attempt by Senator Mary Landrieu of Louisiana to avoid a filibuster on her bill to approve the Keystone XL pipeline is that of her Senate colleague, Barbara Boxer (D-CA) standing next to a blown-up photo of choking smog, presumably in China. Inconveniently, the greenhouse gases at the heart of this debate are invisible and global in effect, rather than local like the pollution from unscrubbed coal plants half a world away. Senator Boxer's smog ploy epitomizes the confusion and misinformation surrounding this project.

That extends to the White House, where the President's recent arguments against the pipeline reflect beliefs, rather than facts, and stand in contrast to the findings of his own administration on the economic and environmental impact of the pipeline, or of oil exports, should some of Keystone's oil be sold into the global market from the Gulf Coast.

Yesterday's defeat is likely to be more final for Senator Landrieu than for the pipeline. She goes into next month's runoff election as a distinct underdog, based on recent polling. The pipeline, however, will likely get another opportunity in the new Congress early next year, when supporters are expected to have an easier time coming up with the 60 votes necessary to bring a bill to the Senate floor for an up-or-down vote. The project may even benefit from having avoided a Presidential veto now, since the fig-leaf of letting the review process run its course would have been more transparent this time than when the President rejected the pipeline in 2012.

How Good Is The New Emissions Deal with China?

• President Obama's emissions deal with China sets an ambitious target for US CO2 cuts while leaving substantial headroom for emissions growth in China. 
• It will likely compound his problems, domestically, but could have significant influence on upcoming international climate negotiations.

Only an event like Tuesday's agreement between President Obama and his Chinese counterpart to limit greenhouse gas emissions (GHG) from the two countries could top the unexpected scramble in the US Senate to pass a Keystone XL pipeline bill as the big energy story of the week. The significance of the climate deal is open to interpretation, from both international and US political perspectives. Before exploring those, we should examine its consequences.

The White House announced that in exchange for the US agreeing to reduce "net greenhouse gas emissions 26-28 percent below 2005 levels by 2025", China would undertake to cap its GHG emissions by "around 2030." It also announced plans to step up a number of cooperative efforts with China in this area, including joint R&D and a jointly funded public/private carbon capture and sequestration (CCS) project in China. What does all this mean in terms of US emissions?

We need to start with the 2012 baseline in which net US emissions were already nearly 11% below 2005 levels. The current Annual Energy Outlook of the US Energy Information Administration (EIA), assuming the laws and regulations in force at the time it was produced, projects that US energy-related CO2 emissions will increase by 236 million metric tons (MT) by 2025, compared to 2012, leaving us at roughly 7% under 2005. Emissions from transportation would shrink, while those from industry would rise as the US economy grows by an expected 2.4% per year.

As I understand it that EIA forecast doesn't include the emissions that the EPA's "Clean Power Plan" for existing power plants would be expected to save if fully implemented. EPA targets reducing CO2 emissions from the US electricity sector--accounting for 39% of net emissions in 2005--by 25% by 2020 and 30% by 2030, compared to 2005. That would shave around 460 million MT from the EIA figure for 2025, getting us to nearly 15% below 2005. The additional savings to reach 26% below 2005 are thus in the neighborhood of 700 million MT per year by 2025. To put that in perspective, it's equivalent to the 2012 CO2 emissions from combustion in the entire US industrial sector, and exceeds total emissions of methane from all sectors, including agriculture, oil & gas, and landfills.

So unless I've done my sums wrong, or misinterpreted the government's data, the US/China deal commits to reducing US emissions by as much again as we've cut since 2005--largely as a result of a weaker economy and the shale gas revolution--after banking the expected savings from the 2011 fuel economy regulations, energy efficiency programs and renewable energy incentives, and an EPA plan for the power sector that is certain to run into strong opposition in the new Congress. That seems pretty ambitious to me, although it falls short of the 40% reduction recently agreed by the EU for 2030.

It's harder to assess what China's side of the deal means in practical terms. Its 2012 emissions were estimated at nearly 10 billion MT/yr, having grown by 8%/yr since 2004 and by 6%/yr since 2009. At that rate, even if its emissions peaked in 2030, they could double before starting to decline. If China's emissions growth declined to just 2% per year, consistent with the lower rates of growth in coal consumption observed recently, by 2030 it could still add nearly 4 billion MT/yr--equivalent to the current emissions of the entire EU, and 5 times the incremental US cuts to which President Obama just agreed. The most recent projection of China's emissions from the EIA had them growing by 5 billion MT by 2030 but essentially plateauing thereafter.

This falls substantially short of what would be required to keep global emissions within the range that climate models predict would limit average global temperature increases to 2°C, compared to pre-industrial levels. However, it goes well beyond China's previous commitment on emissions intensity at Copenhagen in 2009.

Now consider how this deal looks from the standpoint of US politics. Voters just resoundingly handed undivided control of the legislative branch of government to the President's opposition. Republican office-holders and those who just voted for them are likely to regard it as an unwelcome commitment of the US by a lame-duck President to a promise that only his successors could fulfill. In the process, it hands China and other countries a point with which to prod future US administrations should they fall short of its goals. In exchange, he got President Xi Jinping to admit that China can't emit CO2 limitlessly, but can still do more or less what it may have been planning, anyway. It's hard to see this making things easier in Congress for the President's existing environmental agenda.

The deal looks better from the perspective of international environmental and climate policy circles in the lead-up to the Paris climate conference, "COP21", at the end of 2015. One lesson from the Kyoto Protocol is that to be meaningful a global climate agreement must have a strong commitment from the world's largest emitters of CO2 and other GHGs. China and the US are the two biggest emitters, and the EU at #3 is effectively pre-committed. Together these three blocs account for over half of all emissions today. Having them on-side at the start raises the chances of reaching a  big agreement.

As others have observed, this deal makes it harder to argue against a global CO2 agreement based on China's relative inaction, while increasing pressure on other developing countries to agree to limit their own emissions. It also signals that despite political weakness at home, the White House will likely push for aggressive targets at COP21, setting up further conflict with Congress in the next election year. Finally, its timing is early enough to influence the negotiations but not so early as to permit close scrutiny of Chinese or US follow-through on its goals before the Paris talks begin.

China Seizes Opportunity to Fill Its Petroleum Reserve. Should Others?

• China is apparently snapping up cheap oil cargoes to fill its strategic petroleum reserve.
• That might make sense for the US, too, if earmarked for new regional SPRs, rather than refilling the existing one on the Gulf.

The Wall St. Journal has reported that state-owned oil companies in China are capitalizing on lower prices to fill that country's strategic petroleum reserve (SPR). The obvious question is whether the US should do the same, particularly since surging oil output from shale deposits is a major factor in the recent rebalancing of the oil market. If that means putting more oil into caverns on the Gulf Coast, the answer should be no. However, this could be an opportunity to begin creating strategic reserves for parts of the country like the West Coast that are poorly served by our 1970s-vintage SPR.

Superficially, $80 oil provides a tempting chance to turn a profit while replacing the 30 million barrels of oil the US government sold as part of a "coordinated release" with other International Energy Agency members during the Libyan revolution. Comparing the average WTI price in June 2011 to today's, the Department of Energy could pocket around $15 per barrel on the overall sale and repurchase. However, much has changed in the last three years.

When I examined this subject a year ago, the dramatic reduction in US oil imports resulting from the combination of resurgent production and lower consumption had roughly doubled the effective capacity of the SPR, in terms of the number of days of lost imports it could cover in a crisis. Since then, US crude oil imports have fallen by another 5% or so, increasing SPR coverage correspondingly--at least for the parts of the country to which it can easily deliver.

Yet as I noted in another post earlier this year, US oil imports aren't just falling; they are shifting in location. The West Coast, where domestic production has been declining, not growing, now accounts for about 15% of US crude oil imports. It has essentially no dedicated petroleum reserve, other than commercial inventories that are roughly 50% lower than when I traded oil for Texaco's refining and marketing subsidiary in the early 1990s. If oil prices fell much further, it might even make sense for west coast refiners to stock up, regardless of what official action the US government took.

With US oil production still increasing, demand stable or falling, oil imports shrinking, and imports from Canada growing in both absolute and relative terms, it is high time to reconsider holding nearly 700 million barrels of oil--$55 billion worth even at today's depressed prices--in a part of the country where production could soon surpass its 1972 peak. This seems like exactly the kind of overdue reform opportunity that a new Congress might be interested in taking up next year.

Will Russia's Gas Deal with China Block Other Suppliers?

• The recent natural gas deal between Russia and China involves volumes comparable to the gas production of the US Gulf of Mexico.
• Barring a major economic slowdown, meeting China's projected growth in gas demand will require this Russian gas, more LNG imports, and China's own shale gas.

 

$400 billion deals aren't announced every week--even by heads of state--although the new natural gas supply agreement between Russia and China had been in the works for some time. However, the crucial element of price apparently wasn't agreed until a negotiating session that lasted until 4:00 AM, Shanghai time. "Our Chinese friends are difficult, hard negotiators," said President Putin. They certainly waited for the right moment, with Russia pressed by sanctions in the aftermath of its annexation of Crimea.

The numbers are all impressive: After investing more than $50 billion in gas field and pipeline development in Eastern Siberia, Russia will sell 38 billion cubic meters (BCM) of gas per year to China for 30 years, and China will reportedly invest $20 billion for gas infrastructure and market development within its borders. Deliveries are set to start in 2018 and could eventually ramp up to 60 BCM/yr.

To put that in perspective, 38 BCM/yr equates to 3.7 billion cubic feet (BCF) per day. That's on par with the entire natural gas production of the Eagle Ford shale formation in south Texas, or the federal waters of the Gulf of Mexico.  Of greater relevance is that it's also nearly twice the output of Australia's Gorgon LNG project, which is expected to begin production in 2015. So from the perspective of the regional gas market and alternative supplies, this is a very significant quantity of gas, especially with a number of new Australian LNG projects under development or consideration.

As of 2012 China's gas market was already the largest in Asia, ahead of Japan, based on BP's annual Statistical Review of World Energy. This deal represents 27% of China's current gas demand, so it's tempting to conclude that squeezing Russian gas into China must come at the expense of other potential suppliers. If China's gas market were mature, such a zero-sum view could not be ignored, particularly by marginal LNG projects in Australia, Indonesia and the US that have not yet begun construction.

Competition with Russian gas could also impede development funding and access to infrastructure for China's nascent shale gas industry. The US Energy Information Administration's 2013 global survey of technically recoverable shale resources found that China could have over a quadrillion cubic feet--1,115 TCF--of shale gas in the ground, or nearly twice as much as the US. Yet China's progress in tapping this resource has been slow, and hardly a week goes by without another article explaining why it will be difficult if not impossible for others to replicate the US shale gas boom any time soon.

The growth of demand will largely shape the competitive environment for gas in China. In 2012 natural gas accounted for less than 5% of the country's total primary energy consumption, compared to 13% for Taiwan, 17% for South Korea and 22% for Japan, none of which are significant gas producers. From 2007-12 China's gas market grew at a compound average rate of 15% per year. In their just-released Medium-Term Gas Market Report, the International Energy Agency (IEA) forecasts China's gas demand growing by 90% by 2019, while their latest World Energy Outlook anticipated it tripling by 2025 and quadrupling by 2035, eventually reaching 11% of energy consumption. Achieving that would require the equivalent of ten gas deals the size of this one.

That outcome isn't a certainty, for many reasons. Having all that gas turn up at the right time poses a massive logistical and capital investment challenge, and China's economy might slow further. Meanwhile, the price implied in the media coverage of the Russia/China deal is around $350 per 1000 cubic meters ($10 per million BTUs) or more than double the current US wellhead price. That's a lot cheaper than most of the LNG delivered to Asia, but it won't outcompete Chinese coal on economics alone, and it won't jump-start new, gas-reliant industries the way the US shale gas revolution is beginning to do.

The scale of market development implicit in the IEA's forecasts for China would require a substantial expansion of gas-fired power generation, which in any case is the logical complement to China's aggressive expansion of wind and solar power installations. It also entails a significant shift from solid and liquid heating and cooking fuels to gas, where at least in the case of liquids, $10 gas would have the edge over products derived from $100 oil. It might even encompass gas-based distributed power generation using fuel cells, which is still in its infancy in the US. Such developments will benefit all potential suppliers, not just Russia.

It's also worth considering what this deal means for Russia. While many reports have suggested it provides a counterweight to Russia's dependence on the European gas market, that's really only true in a financial sense. The deal represents a major growth opportunity for Gazprom, Russia's majority-state-owned natural gas company, but this isn't the same gas that now supplies the EU. It will mainly be production from new gas fields. The potential upside for Russia may depend on its ability to leverage the infrastructure built for this deal into a larger gas network for supplying growth throughout Asia--in competition with US and other LNG projects eyeing that market.

"Milestone" is an over-used term, but it fits this deal. If the parties can iron out all the remaining details and proceed to construction and ultimately delivery, it could prove to be a key step in giving gas a much bigger role in fueling Asia's growth. That would have important environmental benefits, in both mitigating the air pollution in Asia's major cities and reducing carbon emissions, perhaps by enough to bend the curve of the region's greenhouse gas growth.

 

A different version of this posting was previously published on the website of Pacific Energy Development Corporation.

How Can US Natural Gas Reduce Europe's Dependence on Russia?

• The EU's dependence on Russian natural gas is directly linked to its own gas production, which has fallen faster than EU member countries' demand for gas.
• While US LNG exports aren't an immediate remedy, due to permitting and construction time lags, the prospect of their availability is already affecting the gas market.

Russia's annexation of Ukraine's Crimean Peninsula has drawn new attention to Europe's reliance on energy supplies from Russia, particularly for natural gas. Lacking the means to force Russia's president to back down, US politicians and leading newspapers have latched onto the idea of exporting shale gas to reduce the EU's vulnerability to an accidental or intentional disruption of these supplies.  The efficacy of this strategy depends on more than the logistics and timing of US liquefied natural gas (LNG) projects.

The European Union is expected to import 15.5 billion cubic feet (BCF) per day of natural gas from Russia this year, roughly half of which would normally be transported by pipelines passing through Ukraine. Worries about the security of these supplies in the current crisis are compounded by Europe's increasing reliance on gas imports from all sources.

While EU gas consumption, based on the union's 28 current member countries, has been essentially flat over the last decade, its production has declined by more than a third, as shown in the chart below. As of the end of 2012, EU self-sufficiency in gas stood at just 35%. The widening of the gap between EU gas demand and production bears a close resemblance to the situation in which the US found itself with regard to crude oil prior to the shale revolution, and it is the main source of Europe's vulnerability in natural gas.

After Russia, the EU's main gas suppliers are Norway and Algeria, primarily by pipeline, followed by LNG sourced from Qatar, Nigeria and other countries.  Russia's leading role in supplying Europe's gas is consistent with its status as the world's second-largest gas producer and largest gas exporter, its proximity to the EU, and its pipeline network developed over multiple decades. Europe's gas supply mix includes ample political risk, but none of the EU's other suppliers are geopolitical rivals like Russia.

The EU has three main options for reducing its dependence on gas imports from Russia. It could shrink natural gas consumption, which is already happening to a modest degree as pricey gas-fired power generation is being squeezed out between subsidized wind and solar power and cheaper coal power, in a mirror image of US trends of the last several years.  This seems inconsistent with the EU's long-term emission goals and its need for gas to back up intermittent renewable electricity generation, so the further scope for this option appears limited, at least for the next decade.

EU countries could also attempt to revive domestic gas production. Europe's conventional gas fields may be in decline, other than in non-EU Norway, but its shale gas potential was estimated at 470 trillion cubic feet (TCF) in the US Energy Information Administration's global shale assessment last year. That's about 40% bigger than Europe's reserves and technically recoverable resources of conventional gas. Uncertainties on this estimate are still large, but it's in the same ballpark with the Marcellus shale in the eastern US, which currently produces over 14 BCF/day.

Unfortunately, initial efforts in Poland's shale have been disappointing, while Germany, France, and other countries have imposed explicit or implicit moratoria on shale gas development. Unless these policies are reversed in the aftermath of the Ukraine crisis, the EU will be unable to grow its way out of its dependence on Russia.

That leaves import diversification as the likeliest path for weaning Europe off Russian gas. This process is underway incrementally, hastened by previous Russian gas brinksmanship. Interest in US gas is understandable on many levels, not least because even after increasing production by around 17 BCF/day since 2006, US shale resources are expected to add another 13 BCF/day by 2020.

Energy experts have been quick to point out that the first US LNG exports won't be available for at least several years, and that companies, rather than governments, are the main parties involved in gas contracts. Customers in Europe will have to compete for US and other LNG supplies with customers elsewhere, especially in Asia, where China's gas demand is growing and Japan's post-Fukushima nuclear shutdowns have dramatically increased LNG imports.

These constraints are real. However, they ignore the ways in which changing the market's expectations about future LNG supplies--and potentially prices--could affect the calculations of Europe's gas buyers today and limit the political leverage that Russia's dominant gas export position conveys. Anecdotal reports suggest that US LNG is already a factor in contract renegotiations in Eastern Europe. As Amy Myers Jaffe of UC Davis and formerly the Baker Institute tweeted a few weeks ago, "it isn't about physical LNG cargo to Europe; it is about US exports promoting market liberalization (and) greater liquidity." 

 A decision by the US government to streamline the permitting and development of LNG facilities wouldn't enable US exports to displace Russian gas in Europe this year or next, but it would put Russia on notice that in the future it must compete in a market in which gas customers in Europe and elsewhere will have much greater choice. That would certainly complicate President Putin's plans.

 

A different version of this posting was previously published on the website of Pacific Energy Development Corporation.