Friday, April 10, 2015

An Energy Perspective on the Iran Nuclear Framework

  • With enormous natural gas reserves and renewables potential, Iran has little need for nuclear power, and even less for uranium enrichment.
  • If Iran's sacrifices in pursuit of its nuclear program cannot be explained by a gap in its energy mix, what will motivate its leaders to abide by the current nuclear deal?
The coverage of the recently agreed international nuclear framework for Iran's nuclear program has missed an important aspect of the story. Nearly all of the reporting and analysis I have read considered the deal from a security and geopolitical perspective, without examining the merits of civilian nuclear power within Iran's domestic energy mix. That goes to the heart of Iran's motivation for future adherence to the terms of the detailed agreement that must shortly follow the broad framework negotiated in Switzerland.

This line of analysis dates back to an article I wrote for Geopolitics of Energy, published by the Canadian Energy Research Institute exactly 10 years ago, in April 2005, and subsequently reprinted in my blog. Other than some outdated figures on energy consumption, reserves and cost, it has held up pretty well, particularly in terms of its main proposition:

"Iran makes an unusual candidate for civilian nuclear power, compared to other countries with nuclear power. Most of these fall into either of two categories: those that lack other energy resources to support their economies, such as France, Japan and South Korea, and resource-rich countries that developed nuclear power as a consequence of their pursuit of nuclear weapons, including the US, former USSR, UK, and arguably China. Blessed as it is with hydrocarbon reserves, Iran does not fall into the former category, and it claims not to fall into the latter. Does it represent a unique case?"

In the years since I wrote that, we've seen a growing interest in nuclear energy elsewhere in the Middle East, including a reported memorandum of understanding between Saudi Arabia and Korea for constructing civilian power reactors in the Kingdom. Such projects in energy-rich Gulf States beg the same questions as in Iran, although the "displacement of oil for export" rationale holds up better for Saudi Arabia and the UAE than for Iran under the current circumstances.

As in 2005, the key to understanding the fit of nuclear power within Iran's energy mix is natural gas. In the most recent country analysis by the US Energy Information Administration (EIA) Iran's domestic energy consumption has grown by roughly two-thirds since the 2003 data on which I based my 2005 article. The EIA data indicate that around 75% of that growth has been fueled by gas. That's not surprising, since Iran now claims 18% of the world's proved reserves of natural gas, having leapfrogged Russia for the top spot a few years ago. At current production rates, Iran has over 200 years of proved gas reserves, compared to about 14 years for the US. (Higher US estimates are based on the less-restrictive category of resources, not reserves.)

Moreover, since 2005 the cost of building nuclear power plants has increased, in some cases significantly, while the cost of natural gas-fired combined cycle turbine power plants has generally declined, thanks to substantial efficiency improvements. For that matter, the cost of alternatives like solar power, which Iran's geography favors, has declined even more in the interim.

A decade after I first examined this question, it is still hard to find a compelling energy rationale for Iran to pursue civilian nuclear power with the persistence it has demonstrated. Developing more of its abundant natural gas would be more cost-effective, perhaps in combination with solar power, which presents natural synergies with gas relating to solar's intermittency. These options would not have triggered the kind of economic constraints to which Iran's choices have led.

Nor does the other rationale to which I alluded above withstand scrutiny in this case, involving the application of domestic nuclear power to free up for export oil and gas that would otherwise be consumed to generate electricity. The implied cost of Iranian gas displaced from power generation would likely be higher than the cost of new gas development, especially when the costs of the full nuclear fuel cycle that is the crux of international concerns are included. If anything, Iran's pursuit of nuclear energy in the last decade has functioned as a reverse fuel displacement mechanism, resulting in costly reductions in oil exports due to international sanctions.

As for the benefits of nuclear energy in cutting greenhouse gas emissions, Iran did not include nuclear power in the list of mitigation measures it presented at the UN climate summit in Durban in 2011, nor did it commit to specific emissions reductions at the Cancun Climate Conference in 2012.

On balance, Iran's objective need for civilian nuclear power scarcely justifies the sacrifices it has endured, or the lengths to which it has gone to secure its nuclear program. Over the last 10 years, buying time through engagement and negotiations led to an opportunity for the "P5 +1" countries to impose the tough sanctions that brought Iran to the point of the current deal, once rising US shale oil production effectively defused Iran's "oil weapon." However, if the current agreement merely buys more time, it risks squandering the best chance to bell this cat. We cannot count on having more slack in energy markets 10 years hence than we do today.

Viewed from an energy perspective, the primary purpose of Iran's nuclear program seems unlikely to be an expanded energy supply, rather than a weapons capability. In that context, the concerns about this deal recently expressed by two former US Secretaries of State who negotiated Cold War arms control agreements with the Soviet Union should be sobering. They deserve serious consideration by both the White House and a Congress that seeks its own opportunity to weigh in.

Thursday, April 02, 2015

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

Thursday, March 05, 2015

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

Tuesday, February 17, 2015

A Lesson in Oil Pricing

  • The recent oil-price collapse confirms what we should have learned in 2007-8 about the influence of the last increments of supply and demand on price.
  • This also means that future oil prices should be largely independent of the size of the oil market, even in a decarbonizing world.
In 2008, near the peak of a historic oil-price spike, the US Energy Information Administration (EIA) published a study projecting that opening the Arctic National Wildlife Refuge (ANWR) for drilling would reduce oil prices by no more than $1.44 per barrel, compared to their forecast without ANWR. Adding up to 1.5 million barrels per day to US production by 2028 would thus save motorists less than 4¢ per gallon. That result appeared during a Presidential election campaign that featured the slogan, "Drill, baby, drill!" and received significant attention.  I hope the authors of that study have been watching the current oil price collapse, because it provides some useful lessons in how oil prices are determined.

Oil traders and most economists understand that oil prices are ultimately set by the last few million barrels per day of supply and demand in the market, and resulting changes in inventory. The oil price spike of 2007-8 provided firm evidence for this phenomenon, as rapidly growing demand and production problems eroded global spare production capacity to a level of around 2 million barrels per day (MBD) compared to more than 5 MBD in late 2002, prior to the Venezuelan oil strike and the start of the Iraq War. This may have been obscured by the rise of the widely publicized Peak Oil meme, which provided a more viscerally appealing explanation for high oil prices until it ran out of steam recently.

A chart from one of the International Energy Agency's recent Oil Market Reports provides a neat illustration of the main factors leading to the recent price collapse. (See below.) Here, the emergence of a sustained surplus of 1-1.5 MBD starting in early 2014--less than 2% of the global oil market of around 93 MBD--was instrumental in depressing oil prices by more than half. Another factor was that, contrary to a key assumption of the 2008 EIA study, OPEC elected not to "neutralize any potential price impact of (additional US) oil production by reducing its oil exports." While shale technology has expanded US oil output by a multiple of what the EIA expected ANWR might add, the benefit for consumers isn't just pennies per gallon, but more than a dollar, at least for now.


Since the price of oil is set at the margin, it is also essentially independent of the total size of the oil market. That has important implications for how we envision the future of the oil market, especially in a world that is increasingly concerned about greenhouse gas emissions and transitioning to cleaner sources of energy. Even if future oil production were to be increasingly constrained by energy efficiency improvements and environmental policies, it doesn't necessarily follow that future oil prices must be low. That would only be the case if producers mistakenly invested in more production capacity than the market actually ended up needing.

As things stand today, there is a significant risk that the industry will not invest enough in future capacity, and that prices will again rise sharply before electric vehicles and other alternatives could scale up sufficiently to fill the gap, particularly if low oil prices also deter their growth. That's because without large investments in new oil output, current production will eventually decline from today's levels. Field-level decline rates range from just a few percent to 65% per year, depending on whether we're looking at the conventional oil reservoirs that make up over 90% of global supply, or at US shale production, which accounts for less than 5% of world oil.

Perhaps the bottom-line lesson is that we should never become complacent about the potential price volatility of what is still, at this point, an indispensable commodity. The shale revolution and OPEC's current behavior don't guarantee that oil prices must remain depressed, any more than previous concerns about Peak Oil meant they would remain high indefinitely.





 

Wednesday, February 11, 2015

What Will Fuel Today's Advanced Vehicles?

Last month I attended the annual "policy day" at the Washington Auto Show, which typically emphasizes green cars and related technology. This year it included several high-profile awards and announcements, along with a keynote address by US Secretary of Energy Ernest Moniz.  Yet while the environmental benefits of EVs and other advanced vehicles are a major factor in their proliferation, I didn't hear much about how the energy for these new car types would be produced.

The green car definition used by the DC car show encompasses hybrids, plug-in electric vehicles (EVs), fuel cell cars, and advanced internal-combustion cars including clean diesels. One trend that struck me after missing last year's show was that most of the green cars on display have become harder to distinguish visually from conventional models. For Volkswagen's eGolf EV, which shared
North American Car of the Year honors in Detroit with its gas and diesel siblings, and Ford's Fusion energi plug-in hybrid the differences are mainly under the hood, rather than in the sheet-metal.

Of course some new models looked every bit as exotic as you might expect. That included BMW's
i8 plug-in hybrid, which beat Tesla's updated 2015 Model S as Green Car Journal's "Green Luxury Car of the Year", and Toyota's Mirai fuel-cell car. The Mirai is expected to go on sale this fall in California, still the nation's leading green car market due to its longstanding Zero-Emission Vehicle mandate focused on tailpipe emissions. 

   
BMW i8 plug-in hybrid
   
Toyota Mirai fuel-cell car

Many of these cars have electric drivetrains, increasingly seen as the long-term alternative to petroleum-fueled cars. Although Secretary Moniz pointed out that the US government isn't attempting to pick a vehicle technology winner, there seemed to be a definite emphasis on vehicle electrification and much less on biofuels than in past years.

Another announcement at last month's session addressed where such vehicles might connect to the grid. BMW and VW have partnered with Chargepoint, an EV infrastructure company, to install high-voltage fast-chargers in corridors along the US east and west coasts to facilitate longer-range travel by EV. In making the announcement BMW's representative indicated that EVs will need fast recharging in order to compete with low gasoline prices. With the relative cost advantage of electricity having become a lot less compelling than when gasoline was near $4 per gallon, EV manufacturers need to mitigate the convenience concerns raised by cars with typical ranges of 100 miles or less. 

Getting energy to these cars more conveniently still leaves open the basic question of the ultimate source of that energy.  Perhaps one reason this isn't discussed much is that unlike for gasoline or diesel-powered cars, there's no simple answer. The source of US grid electricity varies much more than for petroleum fuels: by location, by season, and by time of day. However, even in California, which on average now gets 30% of its electricity from renewable sources and has set its sights on 50% from renewables by 2030, the marginal kilowatt-hour (kWh) of demand is likely met by power plants burning natural gas, due to their flexibility. That's especially true if many of these cars will be recharged near peak-usage times, instead of overnight as the EV industry expects.

Based on data from the EPA's fuel economy website, most of the plug-in cars I saw at the Washington Auto Show use around 35 kWh per 100 miles of combined driving. That reflects notionally equivalent miles-per-gallon figures ranging from 76 for the BMW i8 to 116 mpg for the eGolf. On that basis an EV driven 12,000 miles a year would increase natural gas demand at nearby power plants by around 30 thousand cubic feet (MCF) per year. That equates to 40% of the annual natural gas consumption of a US household in 2009. 

To put that in perspective, if we attained the President's goal of one million EVs on the road this year--a figure that may not be achieved until the end of the decade--they would consume about 30 billion cubic feet (BCF) of gas annually, or a little over 0.1% of US natural gas production. With plug-in EVs making up just 0.7% of US new-car sales in 2014, they are unlikely to strain US energy supplies anytime soon. 

It's also worth assessing how much gasoline these EVs will displace. That requires careful consideration of the more conventional models with which each EV competes. While a Tesla Model S surely lures buyers away from luxury-sport models like the BMW 6-series, thus saving around 500 gallons per year, an e-Golf likely replaces either a diesel Golf or a Prius-type hybrid, saving 250-300 gallons per year.  A million EVs saving an average of 350 gallons each per year would reduce US gasoline demand by 22,000 barrels per day, or 0.25%.

At this point the glass for electric vehicles seems both half-full and half-empty. The number of attractive plug-in models expands every year, as does the public recharging infrastructure to serve them. However, they still depend on generous tax credits and must now compete with gasoline near $2 per gallon. More importantly, at current levels their US sales are too low to have much impact on emissions or oil use for many years.
 
A different version of this posting was previously published on the website of Pacific Energy Development Corporation.

Thursday, January 29, 2015

How Much Will Low Oil Prices Stimulate Demand?

  • Since weak oil demand growth is a major ingredient in the current oil price crash, higher demand stimulated by low prices could be a moderating factor.
  • While US demand has risen since prices fell, there are several reasons why the global response may be slower to appear and less dramatic.
One of the main factors that will determine the depth and duration of the current slump in oil prices is the extent and timing of a resulting rebound in demand. It is likely to occur first in countries like the US, where fuel taxes are low and consumers see the results of lower oil prices at the  gas pump relatively quickly--a $1.65 per gallon drop already, since June. However, other factors besides taxes could impede faster demand growth elsewhere. 

From 2007 to 2009 the combination of high oil prices and a weak economy reduced US petroleum demand by
almost 2 million barrels (bbl) per day, compared to its 2006 peak. The first volumes backed out of the market were imported refined products, which had grown rapidly from the mid-1990s until 2005. Low domestic demand and expanding US oil production then led US oil refiners to seek new markets, particularly in Latin America. US petroleum product exports have increased by around 1.7 million bbl/day since the recession began.

These refiners might reasonably expect their domestic and foreign markets to grow faster with oil prices dramatically lower. So far, it's hard to see more than hints of this in the lagged data from the US government or API, which
reported December gasoline demand at a 7-year high. It's also hard to discern how much can be attributed to oil prices, rather than to US economic growth and a falling unemployment rate. The October update of vehicle miles traveled from the US Department of Transportation was still well below its 2008 peak but showed a modest upward trend, although that seems to have begun before oil prices fell.

Other indicators are also mixed. By the end of last year
sales-weighted fuel economy of new vehicles sold in the US had declined by 0.7 miles per gallon from its August 2014 peak. That reflected US consumers buying larger vehicles, including more SUVs, fewer hybrids and only slightly more plug-in electric cars than in the prior year. Despite this retreat, full-year-average fuel economy tracked by the University of Michigan still showed a more than 5 mpg gain since 2007, equating to 20% better fuel efficiency. So the roughly 45 million cars and light trucks sold in the US in the last three years--nearly a fifth of today's light-duty fleet--will use less gasoline than the ones they replaced, even in the most robust response to low gas prices imaginable.

Globally, growth prospects seem equally mixed. Since
last July the International Energy Agency has reduced its forecast of 2015 petroleum demand growth by a cumulative 500,000 bbl/day, to +0.9 million bbl/day, as the global economy weakened.  These conditions could combine with currency-related effects to dampen, or at least delay, a potential surge in global oil demand due to low prices. 
Because oil is traded in US dollars, the dollar's recent strength shrinks the oil savings experienced by other importing countries. While all of these countries are paying less for oil than they did last summer, exchange rates have eroded 10-30% of that benefit. The chart above displays this effect for the Euro and Japanese Yen. Closer to home, currencies like the Mexican and Colombian Pesos have depreciated by 12% and 29% since June, respectively.  That could prove significant, since Mexico's refined product imports from the US averaged over 500,000 bbl/day in 2014 (through October), along with over a million bbl/day to the rest of Latin America.

Since petroleum products are sold in local currency, after tax at the pump, consumers in many countries have seen a smaller drop to which they might respond, compared to US consumers. The average German gasoline price has fallen by just 19% since June and the average UK price by 20%, compared to 42% in the US. Meanwhile state-controlled gasoline prices in Brazil and Mexico have  gone up. That's unlikely to induce more driving.

So far the weekly figures  for US refinery throughput are up compared to last year, implying higher expected product sales. However, US inventories of gasoline and diesel fuel have also been growing for the last several months. If rising demand doesn't erode inventory gains soon, refiners may need to reduce processing rates, and that would feed back to oil prices. The next few months of energy statistics should tell a very interesting story.
 
A different version of this posting was previously published on the website of Pacific Energy Development Corporation.

Tuesday, January 20, 2015

Was 2014 Really the Warmest Year?

  • The media is widely reporting 2014 as the warmest year on record, yet the underlying data don't support that conclusion.
  • The data actually lead to a different finding, of 2014 tied with 2010 and 2005 within the margin of error, reflecting little warming since 2005.
When I opened today's Washington Post and turned to the Opinion section, I found two op-eds that began almost identically: Eugene Robinson's column stated, "We now know that 2014 was the hottest year in recorded history," while Catherine Rampell announced, "Last year, government scientists tell us, was the hottest year on record." The President even repeated this in his State of the Union address. However, that is not really what the figures in question indicate.

I suppose it's understandable that the Post's editors and those of many other media reporting the same finding might rely on the expertise of the government agencies involved, rather than digging deeper. The Post's columnists apparently based their comments on information provided to the media by NASA's Goddard Space Flight Center. The NASA press release, entitled, "NASA, NOAA Find 2014 Warmest Year in Modern Record," included links enabling one to scrutinize the raw data upon which this conclusion was based. I've reproduced the relevant portion below in picture form as of noon today, since this data is subject to periodic revisions.



NASA's dataset displays the differences between measured temperatures and the 14.0°C average from 1951-80. On this basis it confirms that the average recorded temperature in 2014 was 0.02°C higher than the average for the previous warmest year, 2010, which was in turn 0.01°C higher than 2005's. Unfortunately, neither that page nor the press release includes any information about the uncertainty inherent in these figures, which turns out to be larger than the increase from 2010-14.

All physical measurements, including those from the weather stations providing data to NASA, are plus-or-minus some error. Averaging them doesn't entirely negate that. Within the accuracy of these temperatures, it's not possible to distinguish among 2005, 2010 and 2014; they represent a statistical tie. That fact was explained more clearly than I have done in a report on January 14, 2015, from the team of scientists at Berkeley Earth. Hardly climate skeptics, this is the same group that made headlines a couple of years ago with a comprehensive study of existing climate data.


Why does this distinction matter? After all, measured temperatures have warmed nearly 2° Fahrenheit since the early 20th century, as shown in the graph above. Whether last year or 2010 was warmer might seem like more of an academic point than a practical one. However, the refrain of "record temperature" reports gives a false sense that the warming is accelerating. Instead, as the Berkeley Earth report found, "the Earth's average temperature for the last decade has changed very little." That's a very different impression than the one created by the stories I saw, with implications for how we respond to the risks of climate change.